ALABAMA POWER CO - Annual Report: 2021 (Form 10-K)

Table of Contents Index to Financial Statements

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2021

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period from to

Commission
File Number

Registrant,
State of Incorporation,
Address and Telephone Number

I.R.S. Employer
Identification No.

1-3526

The Southern Company

58-0690070

(A Delaware Corporation)

30 Ivan Allen Jr. Boulevard, N.W.

Atlanta, Georgia 30308

(404) 506-5000

1-3164

Alabama Power Company

63-0004250

(An Alabama Corporation)

600 North 18th Street

Birmingham, Alabama 35203

(205) 257-1000

1-6468

Georgia Power Company

58-0257110

(A Georgia Corporation)

241 Ralph McGill Boulevard, N.E.

Atlanta, Georgia 30308

(404) 506-6526

001-11229

Mississippi Power Company

64-0205820

(A Mississippi Corporation)

2992 West Beach Boulevard

Gulfport, Mississippi 39501

(228) 864-1211

001-37803

Southern Power Company

58-2598670

(A Delaware Corporation)

30 Ivan Allen Jr. Boulevard, N.W.

Atlanta, Georgia 30308

(404) 506-5000

1-14174

Southern Company Gas

58-2210952

(A Georgia Corporation)

Ten Peachtree Place, N.E.

Atlanta, Georgia 30309

(404) 584-4000

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Securities registered pursuant to Section 12(b) of the Act:


Registrant	Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
The Southern Company	Common Stock, par value $5 per share	SO	New York Stock Exchange
			(NYSE)
The Southern Company	Series 2017B 5.25% Junior Subordinated Notes due 2077	SOJC	NYSE
The Southern Company	2019 Series A Corporate Units	SOLN	NYSE
The Southern Company	Series 2020A 4.95% Junior Subordinated Notes due 2080	SOJD	NYSE
The Southern Company	Series 2020C 4.20% Junior Subordinated Notes due 2060	SOJE	NYSE
The Southern Company	Series 2021B 1.875% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2081	SO 81	NYSE
Alabama Power Company	5.00% Series Class A Preferred Stock	ALP PR Q	NYSE
Georgia Power Company	Series 2017A 5.00% Junior Subordinated Notes due 2077	GPJA	NYSE
Southern Power Company	Series 2016A 1.000% Senior Notes due 2022	SO/22B	NYSE
Southern Power Company	Series 2016B 1.850% Senior Notes due 2026	SO/26A	NYSE

Securities registered pursuant to Section 12(g) of the Act:(*)


Registrant			Title of Each Class
Alabama Power Company			Preferred stock, cumulative, $100 par value:
			4.20% Series
			4.52% Series
			4.60% Series
			4.64% Series
			4.72% Series
			4.92% Series

(*)At December 31, 2021

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.


Registrant	Yes	No
The Southern Company	X
Alabama Power Company	X
Georgia Power Company	X
Mississippi Power Company		X
Southern Power Company		X
Southern Company Gas		X

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x (Response applicable to all registrants.)

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit such files). Yes x No ¨

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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Registrant

Large Accelerated Filer

Accelerated
Filer

Non-accelerated Filer

Smaller
Reporting
Company

Emerging Growth Company

The Southern Company

Alabama Power Company

Georgia Power Company

Mississippi Power Company

Southern Power Company

Southern Company Gas

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.


Registrant	Yes	No
The Southern Company	X
Alabama Power Company		X
Georgia Power Company		X
Mississippi Power Company		X
Southern Power Company		X
Southern Company Gas		X

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No x (Response applicable to all registrants.)

Aggregate market value of The Southern Company's common stock held by non-affiliates of The Southern Company at June 30, 2021: $64.1 billion. All of the common stock of the other registrants is held by The Southern Company. A description of each registrant's common stock follows:

Registrant

Description of
Common Stock

Shares Outstanding at January 31, 2022

The Southern Company

Par Value $5 Per Share

1,060,226,587

Alabama Power Company

Par Value $40 Per Share

30,537,500

Georgia Power Company

Without Par Value

9,261,500

Mississippi Power Company

Without Par Value

1,121,000

Southern Power Company

Par Value $0.01 Per Share

1,000

Southern Company Gas

Par Value $0.01 Per Share

100

Documents incorporated by reference: specified portions of The Southern Company's Definitive Proxy Statement on Schedule 14A relating to the 2022 Annual Meeting of Stockholders are incorporated by reference into PART III. In addition, specified portions of Alabama Power Company's Definitive Proxy Statement on Schedule 14A relating to its 2022 Annual Meeting of Shareholders are incorporated by reference into PART III.

Each of Georgia Power Company, Mississippi Power Company, Southern Power Company, and Southern Company Gas meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format specified in General Instructions I(2)(b), (c), and (d) of Form 10-K.

This combined Form 10-K is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Mississippi Power Company, Southern Power Company, and Southern Company Gas. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

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Table of Contents


		Page

	Definitions	ii
	Cautionary Statement Regarding Forward-Looking Information	vi

	PART I
Item 1	Business	I-1
	The Southern Company System	I-1
	Construction Programs	I-4
	Financing Programs	I-5
	Fuel Supply	I-5
	Territory Served by the Southern Company System	I-6
	Competition	I-8
	Seasonality	I-9
	Regulation	I-9
	Rate Matters	I-11
	Human Capital	I-13
Item 1A	Risk Factors	I-15
Item 1B	Unresolved Staff Comments	I-26
Item 2	Properties	I-27
Item 3	Legal Proceedings	I-34
Item 4	Mine Safety Disclosures	I-34
	Information about Our Executive Officers – Southern Company	I-35
	Information about Our Executive Officers – Alabama Power	I-37

	PART II
Item 5	Market for Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	II-1
Item 6	Reserved	II-1
Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	II-2
Item 7A	Quantitative and Qualitative Disclosures about Market Risk	II-2
Item 8	Financial Statements and Supplementary Data	II-73
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	II-269
Item 9A	Controls and Procedures	II-269
Item 9B	Other Information	II-269
Item 9C	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	II-269

	PART III
Item 10	Directors, Executive Officers and Corporate Governance	III-1
Item 11	Executive Compensation	III-1
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	III-1
Item 13	Certain Relationships and Related Transactions, and Director Independence	III-1
Item 14	Principal Accountant Fees and Services	III-2

	PART IV
Item 15	Exhibits and Financial Statement Schedules	IV-1
Item 16	Form 10-K Summary	IV-1
	Signatures

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DEFINITIONS

When used in this Form 10-K, the following terms will have the meanings indicated.


Term			Meaning
2013 ARP			Alternate Rate Plan approved by the Georgia PSC in 2013 for Georgia Power for the years 2014 through 2016 and subsequently extended through 2019
2019 ARP			Alternate Rate Plan approved by the Georgia PSC in 2019 for Georgia Power for the years 2020 through 2022
AFUDC			Allowance for funds used during construction
Alabama Power			Alabama Power Company
AMEA			Alabama Municipal Electric Authority
Amended and Restated Loan Guarantee Agreement			Loan guarantee agreement entered into by Georgia Power with the DOE in 2014, as amended and restated in March 2019, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4
AOCI			Accumulated other comprehensive income
ARO			Asset retirement obligation
ASC			Accounting Standards Codification
ASU			Accounting Standards Update
Atlanta Gas Light			Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas
Atlantic Coast Pipeline			Atlantic Coast Pipeline, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas held a 5% interest through March 24, 2020
Bcf			Billion cubic feet
Bechtel			Bechtel Power Corporation, the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4
Bechtel Agreement			The 2017 construction completion agreement between the Vogtle Owners and Bechtel
CCN			Certificate of convenience and necessity
CCR			Coal combustion residuals
CCR Rule			Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015
Chattanooga Gas			Chattanooga Gas Company, a wholly-owned subsidiary of Southern Company Gas
Clean Air Act			Clean Air Act Amendments of 1990
CO2			Carbon dioxide
COD			Commercial operation date
Contractor Settlement Agreement			The December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the Vogtle 3 and 4 Agreement
Cooperative Energy			Electric generation and transmission cooperative in Mississippi
COVID-19			The novel coronavirus disease declared a pandemic by the World Health Organization and the Centers for Disease Control and Prevention in March 2020
CPCN			Certificate of public convenience and necessity
CWIP			Construction work in progress
Dalton			City of Dalton, Georgia, an incorporated municipality in the State of Georgia, acting by and through its Board of Water, Light, and Sinking Fund Commissioners
Dalton Pipeline			A pipeline facility in Georgia in which Southern Company Gas has a 50% undivided ownership interest
DOE			U.S. Department of Energy
DSGP			Diamond State Generation Partners
ECCR			Georgia Power's Environmental Compliance Cost Recovery tariff
ECO Plan			Mississippi Power's environmental compliance overview plan
ELG			Effluent limitations guidelines
Eligible Project Costs			Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the loan guarantee program established under Title XVII of the Energy Policy Act of 2005
EMC			Electric membership corporation

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DEFINITIONS

(continued)


Term			Meaning
EPA			U.S. Environmental Protection Agency
EPC Contractor			Westinghouse and its affiliate, WECTEC Global Project Services Inc.; the former engineering, procurement, and construction contractor for Plant Vogtle Units 3 and 4
FASB			Financial Accounting Standards Board
FERC			Federal Energy Regulatory Commission
FFB			Federal Financing Bank
FFB Credit Facilities			Note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities
Fitch			Fitch Ratings, Inc.
GAAP			U.S. generally accepted accounting principles
Georgia Power			Georgia Power Company
GHG			Greenhouse gas
GRAM			Atlanta Gas Light's Georgia Rate Adjustment Mechanism
Guarantee Settlement Agreement			The June 9, 2017 settlement agreement between the Vogtle Owners and Toshiba related to certain payment obligations of the EPC Contractor guaranteed by Toshiba
Gulf Power			Gulf Power Company, until January 1, 2019 a wholly-owned subsidiary of Southern Company; effective January 1, 2021, Gulf Power Company merged with and into Florida Power and Light Company, with Florida Power and Light Company remaining as the surviving company
Heating Degree Days			A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Heating Season			The period from November through March when Southern Company Gas' natural gas usage and operating revenues are generally higher
HLBV			Hypothetical liquidation at book value
IBEW			International Brotherhood of Electrical Workers
IGCC			Integrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility
IIC			Intercompany Interchange Contract
Illinois Commission			Illinois Commerce Commission
Internal Revenue Code			Internal Revenue Code of 1986, as amended
IPP			Independent power producer
IRP			Integrated resource plan
IRS			Internal Revenue Service
ITAAC			Inspections, Tests, Analyses, and Acceptance Criteria, standards established by the NRC
ITC			Investment tax credit
JEA			Jacksonville Electric Authority
Jefferson Island			Jefferson Island Storage and Hub, L.L.C, which owns a natural gas storage facility in Louisiana consisting of two salt dome caverns; a subsidiary of Southern Company Gas through December 1, 2020
KW			Kilowatt
KWH			Kilowatt-hour
LIBOR			London Interbank Offered Rate
LIFO			Last-in, first-out
LNG			Liquefied natural gas
LOCOM			Lower of weighted average cost or current market price
LTSA			Long-term service agreement
Marketers			Marketers selling retail natural gas in Georgia and certificated by the Georgia PSC
MEAG Power			Municipal Electric Authority of Georgia
MGP			Manufactured gas plant
Mississippi Power			Mississippi Power Company
mmBtu			Million British thermal units

iii

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DEFINITIONS

(continued)


Term			Meaning
Moody's			Moody's Investors Service, Inc.
MPUS			Mississippi Public Utilities Staff
MRA			Municipal and Rural Associations
MW			Megawatt
MWH			Megawatt hour
natural gas distribution utilities			Southern Company Gas' natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas)
NCCR			Georgia Power's Nuclear Construction Cost Recovery tariff
NDR			Alabama Power's Natural Disaster Reserve
NextEra Energy			NextEra Energy, Inc.
Nicor Gas			Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas
NOX			Nitrogen oxide
NRC			U.S. Nuclear Regulatory Commission
NYMEX			New York Mercantile Exchange, Inc.
NYSE			New York Stock Exchange
OCI			Other comprehensive income
OPC			Oglethorpe Power Corporation (an EMC)
OTC			Over-the-counter
PennEast Pipeline			PennEast Pipeline Company, LLC, a joint venture in which Southern Company Gas has a 20% ownership interest
PEP			Mississippi Power's Performance Evaluation Plan
Pivotal LNG			Pivotal LNG, Inc., through March 24, 2020, a wholly-owned subsidiary of Southern Company Gas
PowerSecure			PowerSecure, Inc., a wholly-owned subsidiary of Southern Company
PowerSouth			PowerSouth Energy Cooperative
PPA			Power purchase agreements, as well as, for Southern Power, contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid
PSC			Public Service Commission
PTC			Production tax credit
Rate CNP			Alabama Power's Rate Certificated New Plant, consisting of Rate CNP New Plant, Rate CNP Compliance, and Rate CNP PPA
Rate ECR			Alabama Power's Rate Energy Cost Recovery
Rate NDR			Alabama Power's Rate Natural Disaster Reserve
Rate RSE			Alabama Power's Rate Stabilization and Equalization
Registrants			Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power Company, and Southern Company Gas
ROE			Return on equity
S&P			S&P Global Ratings, a division of S&P Global Inc.
SCS			Southern Company Services, Inc., the Southern Company system service company and a wholly-owned subsidiary of Southern Company
SEC			U.S. Securities and Exchange Commission
SEGCO			Southern Electric Generating Company, 50% owned by each of Alabama Power and Georgia Power
SEPA			Southeastern Power Administration
Sequent			Sequent Energy Management, L.P. and Sequent Energy Canada Corp., wholly-owned subsidiaries of Southern Company Gas through June 30, 2021
SERC			SERC Reliability Corporation
SNG			Southern Natural Gas Company, L.L.C., a pipeline system in which Southern Company Gas has a 50% ownership interest
SO2			Sulfur dioxide

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DEFINITIONS

(continued)


Term			Meaning
Southern Company			The Southern Company
Southern Company Gas			Southern Company Gas and its subsidiaries
Southern Company Gas Capital			Southern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas
Southern Company power pool			The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations
Southern Company system			Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas, SEGCO, Southern Nuclear, SCS, Southern Linc, PowerSecure, and other subsidiaries
Southern Holdings			Southern Company Holdings, Inc., a wholly-owned subsidiary of Southern Company
Southern Linc			Southern Communications Services, Inc., a wholly-owned subsidiary of Southern Company, doing business as Southern Linc
Southern Nuclear			Southern Nuclear Operating Company, Inc., a wholly-owned subsidiary of Southern Company
Southern Power			Southern Power Company and its subsidiaries
SouthStar			SouthStar Energy Services, LLC (a Marketer), a wholly-owned subsidiary of Southern Company Gas
SP Solar			SP Solar Holdings I, LP, a limited partnership indirectly owning substantially all of Southern Power's solar and battery energy storage facilities, in which Southern Power has a 67% ownership interest
SP Wind			SP Wind Holdings II, LLC, a holding company owning a portfolio of eight operating wind facilities, in which Southern Power is the controlling partner in a tax equity arrangement
SRR			Mississippi Power's System Restoration Rider, a tariff for retail property damage cost recovery and reserve
Subsidiary Registrants			Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas
Tax Reform Legislation			The Tax Cuts and Jobs Act, which became effective on January 1, 2018
Toshiba			Toshiba Corporation, the parent company of Westinghouse
traditional electric operating companies			Alabama Power, Georgia Power, and Mississippi Power
Triton			Triton Container Investments, LLC, an investment of Southern Company Gas through May 29, 2019
VCM			Vogtle Construction Monitoring
VIE			Variable interest entity
Virginia Commission			Virginia State Corporation Commission
Virginia Natural Gas			Virginia Natural Gas, Inc., a wholly-owned subsidiary of Southern Company Gas
Vogtle 3 and 4 Agreement			Agreement entered into with the EPC Contractor in 2008 by Georgia Power, acting for itself and as agent for the Vogtle Owners, and rejected in bankruptcy in July 2017, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4
Vogtle Owners			Georgia Power, Oglethorpe Power Corporation, MEAG Power, and Dalton
Vogtle Services Agreement			The June 2017 services agreement between the Vogtle Owners and the EPC Contractor, as amended and restated in July 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear
WACOG			Weighted average cost of gas
Westinghouse			Westinghouse Electric Company LLC
Williams Field Services Group			Williams Field Services Group, LLC

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Annual Report on Form 10-K contains forward-looking statements. Forward-looking statements include, among other things, statements concerning the potential and expected effects of the COVID-19 pandemic, regulated rates, the strategic goals for the business, customer and sales growth, economic conditions, cost recovery and other rate actions, projected equity ratios, current and proposed environmental regulations and related compliance plans and estimated expenditures, GHG emissions reduction goals, pending or potential litigation matters, access to sources of capital, projections for the qualified pension plans, postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, completion dates and costs of construction projects, matters related to the abandonment of the Kemper IGCC, completion of announced acquisitions, filings with state and federal regulatory authorities, federal and state income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "would," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

•the impact of recent and future federal and state regulatory changes, including tax, environmental, and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;

•the potential effects of the continued COVID-19 pandemic, including, but not limited to, those described in Item 1A "Risk Factors" herein;

•the extent and timing of costs and legal requirements related to CCR;

•current and future litigation or regulatory investigations, proceedings, or inquiries, including litigation and other disputes related to the Kemper County energy facility;

•the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate, including from the development and deployment of alternative energy sources;

•variations in demand for electricity and natural gas;

•available sources and costs of natural gas and other fuels;

•the ability to complete necessary or desirable pipeline expansion or infrastructure projects, limits on pipeline capacity, and operational interruptions to natural gas distribution and transmission activities;

•transmission constraints;

•effects of inflation;

•the ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of facilities or other projects, including Plant Vogtle Units 3 and 4 (which includes components based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale) and Plant Barry Unit 8, due to current and/or future challenges which include, but are not limited to, changes in labor costs, availability, and productivity; challenges with management of contractors or vendors; subcontractor performance; adverse weather conditions; shortages, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; delays due to judicial or regulatory action; nonperformance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems or any remediation related thereto; design and other licensing-based compliance matters, including, for nuclear units, inspections and the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related investigations, reviews, and approvals by the NRC necessary to support NRC authorization to load fuel; challenges with start-up activities, including major equipment failure, or system integration; and/or operational performance; and challenges related to the COVID-19 pandemic;

•the ability to overcome or mitigate the current challenges at Plant Vogtle Units 3 and 4, as described in Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 herein, that could further impact the cost and schedule for the project;

•legal proceedings and regulatory approvals and actions related to construction projects, such as Plant Vogtle Units 3 and 4 and Plant Barry Unit 8, including PSC approvals and FERC and NRC actions;

•under certain specified circumstances, a decision by holders of more than 10% of the ownership interests of Plant Vogtle Units 3 and 4 not to proceed with construction and the ability of other Vogtle Owners to tender a portion of their ownership interests to Georgia Power following certain construction cost increases;

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)

•in the event Georgia Power becomes obligated to provide funding to MEAG Power with respect to the portion of MEAG Power's ownership interest in Plant Vogtle Units 3 and 4 involving JEA, any inability of Georgia Power to receive repayment of such funding;

•the ability to construct facilities in accordance with the requirements of permits and licenses (including satisfaction of NRC requirements), to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;

•investment performance of the employee and retiree benefit plans and nuclear decommissioning trust funds;

•advances in technology, including the pace and extent of development of low- to no-carbon energy technologies and negative carbon concepts;

•performance of counterparties under ongoing renewable energy partnerships and development agreements;

•state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to ROE, equity ratios, additional generating capacity, and fuel and other cost recovery mechanisms;

•the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities, Southern Power's generation facilities, and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions;

•the inherent risks involved in operating and constructing nuclear generating facilities;

•the inherent risks involved in transporting and storing natural gas;

•the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;

•internal restructuring or other restructuring options that may be pursued;

•potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;

•the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;

•the ability to obtain new short- and long-term contracts with wholesale customers;

•the direct or indirect effect on the Southern Company system's business resulting from cyber intrusion or physical attack and the threat of physical attacks;

•interest rate fluctuations and financial market conditions and the results of financing efforts;

•access to capital markets and other financing sources;

•changes in Southern Company's and any of its subsidiaries' credit ratings;

•the replacement of LIBOR with an alternative reference rate;

•the ability of Southern Company's electric utilities to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;

•catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events, political unrest, or other similar occurrences;

•the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid, natural gas pipeline infrastructure, or operation of generating or storage resources;

•impairments of goodwill or long-lived assets;

•the effect of accounting pronouncements issued periodically by standard-setting bodies; and

•other factors discussed elsewhere herein and in other reports filed by the Registrants from time to time with the SEC.

The Registrants expressly disclaim any obligation to update any forward-looking statements.

vii

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PART I

Item 1. BUSINESS

Southern Company is a holding company that owns all of the outstanding common stock of three traditional electric operating companies, Southern Power Company, and Southern Company Gas.

•The traditional electric operating companies – Alabama Power, Georgia Power, and Mississippi Power – are each operating public utility companies providing electric service to retail customers in three Southeastern states in addition to wholesale customers in the Southeast.

•Southern Power Company is also an operating public utility company. The term "Southern Power" when used herein refers to Southern Power Company and its subsidiaries, while the term "Southern Power Company" when used herein refers only to the Southern Power parent company. 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 is an energy services holding company whose primary business is the distribution of natural gas in four states – Illinois, Georgia, Virginia, and Tennessee – through the natural gas distribution utilities. Southern Company Gas is also involved in several other businesses that are complementary to the distribution of natural gas.

Southern Company also owns SCS, Southern Linc, Southern Holdings, Southern Nuclear, PowerSecure, and other direct and indirect subsidiaries. SCS, the system service company, has contracted with Southern Company, each traditional electric operating company, Southern Power, Southern Company Gas, Southern Nuclear, SEGCO, and other subsidiaries to furnish, at direct or allocated cost and upon request, the following services: 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. 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 through its subsidiary, Southern Telecom, Inc. Southern Linc's system covers approximately 127,000 square miles in the Southeast. Southern Holdings is an intermediate holding company subsidiary, which invests in various projects. During 2021, Southern Holdings sold or terminated three of its leveraged lease investments and only one remains. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants and is currently managing construction of and developing 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 "The Southern Company System" herein for additional information. Also see Note 15 to the financial statements in Item 8 herein for information regarding recent acquisition and disposition activity. Segment information for Southern Company and Southern Company Gas is included in Note 16 to the financial statements in Item 8 herein.

The Registrants' Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports are made available on Southern Company's website, free of charge, as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. Southern Company's internet address is www.southerncompany.com.

The Southern Company System

Traditional Electric Operating Companies

The traditional electric operating companies are vertically integrated utilities that own generation, transmission, and distribution facilities. See PROPERTIES in Item 2 herein for additional information on the traditional electric operating companies' generating facilities. Each company's transmission facilities are connected to the respective company's own generating plants and other sources of power (including certain generating plants owned by Southern Power) and are interconnected with the transmission facilities of the other traditional electric operating companies and SEGCO. For information on the State of Georgia's integrated transmission system, see "Territory Served by the Southern Company System – Traditional Electric Operating Companies and Southern Power" herein.

Agreements in effect with principal neighboring utility systems provide for capacity and energy transactions that may be entered into for reasons related to reliability or economics. Additionally, the traditional electric operating companies have entered into various reliability agreements with certain neighboring utilities, each of which provides for the establishment and periodic review of principles and procedures for planning and operation of generation and transmission facilities, maintenance schedules, load retention programs, emergency operations, and other matters affecting the reliability of bulk power supply. The traditional electric operating companies have joined with other utilities in the Southeast to form the SERC to augment further

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the reliability and adequacy of bulk power supply. Through the SERC, the traditional electric operating companies are represented at the North American Electric Reliability Corporation. In February 2021, Southern Company joined a filing at the FERC proposing a Southeast Energy Exchange Market (SEEM) that included many of the other electric service providers in the Southeast. In October 2021, the proposal became effective by operation of law following a tie vote by the FERC, subject to certain rehearing requests. A petition for appeal has been filed regarding the FERC's orders. SEEM is an extension of the existing bilateral market where participants will use an automated, intra-hour energy exchange to buy and sell power close to the time the energy is consumed, utilizing available unreserved transmission. SEEM is expected to begin service in mid-2022. The ultimate outcome of this matter cannot be determined at this time.

The utility assets of the traditional electric operating companies and certain utility assets of Southern Power Company are operated as a single integrated electric system, or Southern Company power pool, pursuant to the IIC. Activities under the IIC are administered by SCS, which acts as agent for the traditional electric operating companies and Southern Power Company. The fundamental purpose of the Southern Company power pool is to provide for the coordinated operation of the electric facilities in an effort to achieve the maximum possible economies consistent with the highest practicable reliability of service. Subject to service requirements and other operating limitations, system resources are committed and controlled through the application of centralized economic dispatch. Under the IIC, each traditional electric operating company and Southern Power Company retains its lowest cost energy resources for the benefit of its own customers and delivers any excess energy to the Southern Company power pool for use in serving customers of other traditional electric operating companies or Southern Power Company or for sale by the Southern Company power pool to third parties. The IIC provides for the recovery of specified costs associated with the affiliated operations thereunder, as well as the proportionate sharing of costs and revenues resulting from Southern Company power pool transactions with third parties. In connection with the sale of former subsidiary Gulf Power in January 2019, an appendix was added to the IIC setting forth terms and conditions governing Gulf Power's continued participation in the IIC for a defined transition period. On December 21, 2021, NextEra Energy provided a 180-day notice of its intention to leave the Southern Company power pool.

Southern Power and Southern Linc have secured from the traditional electric operating companies certain services which are furnished in compliance with FERC regulations.

Alabama Power and Georgia Power each have agreements with Southern Nuclear to operate the Southern Company system's existing nuclear plants, Plants Farley, Hatch, and Vogtle. In addition, Georgia Power has an agreement with Southern Nuclear to develop, license, construct, and operate Plant Vogtle Units 3 and 4. See "Regulation – Nuclear Regulation" herein for additional information.

Southern Power

Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates (under authority from the FERC) in the wholesale market. Southern Power seeks opportunities to execute its strategy to create value through various transactions including acquisitions, dispositions, and sales of partnership interests, development and construction of new generating facilities, and entry into PPAs, including contracts for differences that provide the owner of a renewable facility a certain fixed price for electricity sold to the grid, primarily with investor-owned utilities, IPPs, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. The electricity from the natural gas generating facilities owned by Southern Power is primarily sold under long-term, fixed-price capacity PPAs both with unaffiliated wholesale purchasers as well as with the traditional electric operating companies. Southern Power has attempted to insulate itself from significant fuel supply, fuel transportation, and electric transmission risks by generally making such risks the responsibility of the counterparties to its PPAs. However, Southern Power's future earnings will depend on the parameters of the wholesale market and the efficient operation of its wholesale generating assets, as well as Southern Power's ability to execute its growth strategy and to develop and construct generating facilities. Southern Power's business activities are not subject to traditional state regulation like the traditional electric operating companies, but the majority of its business activities are subject to regulation by the FERC. For additional information on Southern Power's business activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Business Activities" in Item 7 herein.

Southern Power Company directly owns and manages generation assets primarily in the Southeast, which are included in the Southern Company power pool, and has various subsidiaries whose generation assets are not included in the Southern Company power pool. These subsidiaries were created to own, operate, and pursue natural gas and renewable generation facilities, either wholly or in partnership with various third parties. At December 31, 2021, Southern Power's generation fleet, which is owned in part with various partners, totaled 12,446 MWs of nameplate capacity in commercial operation (including 5,066 MWs of nameplate capacity owned by its subsidiaries). See "Traditional Electric Operating Companies" herein for additional information on the Southern Company power pool.

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A majority of Southern Power's partnerships in renewable facilities allow for the sharing of cash distributions and tax benefits at differing percentages, with Southern Power being the controlling member and thus consolidating the assets and operations of the partnerships. At December 31, 2021, Southern Power had eight tax equity partnership arrangements where the tax equity investors receive substantially all of the tax benefits from the facilities, including ITCs and PTCs. In addition, Southern Power holds controlling interests in non-tax equity partnerships with its ownership interests primarily ranging from 51% to 66%.

See PROPERTIES in Item 2 herein for additional detail regarding Southern Power's partnership arrangements and Note 15 to the financial statements under "Southern Power" in Item 8 herein for additional information regarding Southern Power's acquisitions, dispositions, construction, and development projects.

Southern Power calculates an investment coverage ratio for its generating assets, including those owned with various partners, based on the ratio of investment under contract to total investment using the respective facilities' net book value (or expected in-service value for facilities under construction) as the investment amount. With the inclusion of investments associated with the facilities currently under construction, as well as other capacity and energy contracts, Southern Power's average investment coverage ratio at December 31, 2021 was 95% through 2026 and 92% through 2031, with an average remaining contract duration of approximately 13 years. For the year ended December 31, 2021, approximately 47% of contracted MWs were with AAA to A- or equivalent rated counterparties, 42% were with BBB+ to BBB- or equivalent rated counterparties, and 8% were with unrated entities that either have ratemaking authority or have posted collateral to cover potential credit exposure.

Southern Power's electricity sales from natural gas generating facilities are primarily through long-term PPAs that consist of two types of agreements. The first type, referred to as a unit or block sale, is a customer purchase from a dedicated plant unit where all or a portion of the generation from that unit is reserved for that customer. Southern Power typically has the ability to serve the unit or block sale customer from an alternate resource. The second type, referred to as requirements service, provides that Southern Power serves the customer's capacity and energy requirements from a combination of the customer's own generating units and from Southern Power resources not dedicated to serve unit or block sales. Southern Power has rights to purchase power provided by the requirements customers' resources when economically viable. Capacity charges that form part of the PPA payments are designed to recover fixed and variable operations and maintenance costs based on dollars-per-kilowatt year and to provide a return on investment.

Southern Power's electricity sales from solar and wind generating facilities are also primarily through long-term PPAs; however, these solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or provide Southern Power a certain fixed price for the electricity sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Generally, under the renewable generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.

Southern Power actively pursues replacement PPAs prior to the expiration of its current PPAs and anticipates that the revenues attributable to one customer may be replaced by revenues from a new customer; however, the expiration of any of Southern Power's current PPAs without the successful remarketing of a replacement PPA could have a material negative impact on Southern Power's earnings but is not expected to have a material impact on Southern Company's earnings.

Southern Company Gas

Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. Southern Company Gas is also involved in several other businesses that are complementary to the distribution of natural gas, including gas pipeline investments and gas marketing services. Southern Company Gas also has an "all other" non-reportable segment that includes segments below the quantitative threshold for separate disclosure, including storage operations and subsidiaries that fall below the quantitative threshold for separate disclosure. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' other businesses also included wholesale gas services. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 herein for information regarding Southern Company Gas' recent dispositions, including the sale of Sequent.

Gas distribution operations, the largest segment of Southern Company Gas' business, operates, constructs, and maintains 76,289 miles of natural gas pipelines and 14 storage facilities, with total capacity of 157 Bcf, to provide natural gas to residential, commercial, and industrial customers. Gas distribution operations serves approximately 4.3 million customers across four states.

Gas pipeline investments primarily 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. SNG, the largest natural gas pipeline investment, is the owner of a 7,000-mile pipeline connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to

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markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. Gas pipeline investments also includes a 20% ownership interest in the PennEast Pipeline project, which was cancelled in September 2021. For additional information on Southern Company Gas's pipeline investments, see Note 7 to the financial statements under "Southern Company Gas" in Item 8 herein.

Gas marketing services is comprised of SouthStar, which serves approximately 603,000 natural gas commodity customers, markets gas to residential, commercial, and industrial customers and offers energy-related products that provide natural gas price stability and utility bill management in competitive markets or markets that provide for customer choice.

Construction Programs

The subsidiary companies of Southern Company are engaged in continuous construction programs, including capital expenditures to accommodate existing and estimated future loads on their respective systems and to comply with environmental laws and regulations, as applicable. In 2022, the Southern Company system's construction program is expected to be apportioned approximately as follows:


	Southern Company system(a)(b)		Alabama Power		Georgia Power(a)		Mississippi Power(a)
	(in billions)
New generation	$	1.6	$	0.3	$	1.4	$	—
Environmental compliance(c)	0.1		—		—		—
Generation maintenance	0.9		0.5		0.3		0.1
Transmission	1.5		0.4		1.0		—
Distribution	1.7		0.4		1.2		0.1
Nuclear fuel	0.2		0.1		0.1		—
General plant	0.6		0.2		0.3
	6.6		1.9		4.4		0.3
Southern Power(d)	0.1
Southern Company Gas(e)	1.7
Other subsidiaries	0.3
Total(a)	$	8.7	$	1.9	$	4.4	$	0.3

(a)Totals may not add due to rounding.

(b)Includes the Subsidiary Registrants, as well as other subsidiaries.

(c)Reflects cost estimates for environmental laws and regulations. These estimated expenditures do not include any potential compliance costs associated with any future regulation of CO2 emissions from fossil fuel-fired electric generating units or costs associated with closure and monitoring of ash ponds and landfills in accordance with the CCR Rule and the related state rules. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" and FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" in Item 7 herein for additional information. No material capital expenditures are expected for non-environmental government regulations.

(d)Does not include approximately $0.3 billion for planned acquisitions and placeholder growth, which may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy.

(e)Includes costs for ongoing capital projects associated with infrastructure improvement programs for certain natural gas distribution utilities that have been previously approved by their applicable state regulatory agencies. See Note 2 to the financial statements under "Southern Company Gas" in Item 8 herein for additional information.

The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" in Item 7 herein for additional information, including estimated construction and environmental expenditures for the years 2023 through 2026.

Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" in Item 7 herein for additional information with respect to certain existing and proposed environmental requirements and PROPERTIES – "Electric – Jointly-Owned Facilities" and – "Natural Gas – Jointly-Owned Properties" in Item 2 herein and Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information concerning the Registrants' joint ownership of certain facilities.

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Financing Programs

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY in Item 7 herein and Note 8 to the financial statements in Item 8 herein for information concerning financing programs.

Fuel Supply

Electric

The traditional electric operating companies' and SEGCO's supply of electricity is primarily fueled by natural gas and coal, as well as nuclear for Alabama Power and Georgia Power. Southern Power's supply of electricity is primarily fueled by natural gas. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATION – "Southern Company – Electricity Business – Fuel and Purchased Power Expenses" and MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATION under "Fuel and Purchased Power Expenses" for each of the traditional electric operating companies in Item 7 herein for information regarding the electricity generated and the average cost of fuel in cents per net KWH generated for the years 2020 and 2021.

SCS, acting on behalf of the traditional electric operating companies and Southern Power Company, has agreements in place for the natural gas burn requirements of the Southern Company system. For 2022, SCS has contracted for 517 Bcf of natural gas supply under agreements with remaining terms up to 12 years. In addition to natural gas supply, SCS has contracts in place for both firm natural gas transportation and storage. Management believes these contracts provide sufficient natural gas supplies, transportation, and storage to ensure normal operations of the Southern Company system's natural gas generating units.

The traditional electric operating companies have agreements in place from which they expect to receive substantially all of their 2022 coal burn requirements. These agreements have terms ranging between one and three years. Fuel procurement specifications, emission allowances, environmental control systems, and fuel changes have allowed the traditional electric operating companies to remain within limits set by applicable environmental regulations. As new environmental regulations are proposed that impact the utilization of coal, the traditional electric operating companies' fuel mix will be monitored to help ensure compliance with applicable laws and regulations. Additionally, Southern Company and the traditional electric operating companies will continue to evaluate the need to purchase additional emissions allowances, the timing of capital expenditures for environmental control equipment, and potential unit retirements and replacements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" in Item 7 herein and Note 2 to the financial statements under "Georgia Power – Integrated Resource Plan" and "Mississippi Power – Integrated Resource Plan" in Item 8 herein for information regarding plans to retire or convert to natural gas certain coal-fired generating capacity.

Alabama Power and Georgia Power have multiple contracts covering their nuclear fuel needs for uranium, conversion services, enrichment services, and fuel fabrication with remaining terms ranging from one to 13 years. Management believes suppliers have sufficient nuclear fuel production capability to permit normal operation of the Southern Company system's nuclear generating units. Alabama Power and Georgia Power also have contracts with the United States, acting through the DOE, that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent fuel in 1998, as required by the contracts, and Alabama Power and Georgia Power have pursued and are pursuing legal remedies against the government for breach of contract. See Note 3 to the financial statements under "Nuclear Fuel Disposal Costs" in Item 8 herein for additional information.

Changes in fuel prices to the traditional electric operating companies are generally reflected in fuel adjustment clauses contained in rate schedules. See "Rate Matters – Rate Structure and Cost Recovery Plans" herein for additional information. Southern Power's natural gas PPAs generally provide that the counterparty is responsible for substantially all of the cost of fuel.

Natural Gas

Advances in natural gas drilling in shale producing regions of the United States have resulted in historically high supplies of natural gas and lower prices for natural gas, which fluctuate over time. Demand increases in 2021 resulted in price increases and high volatility; however, absent unforeseen developments, forward prices are expected to decline over the next several years. Procurement plans for natural gas supply and transportation to serve regulated utility customers are reviewed and approved by the regulatory agencies in the states where Southern Company Gas operates. Southern Company Gas purchases natural gas supplies in the open market by contracting with producers and marketers and, for Atlanta Gas Light and Chattanooga Gas, from Sequent, under asset management agreements approved by the applicable state regulatory agency. Despite the sale of Sequent on July 1, 2021, the Atlanta Gas Light and Chattanooga Gas asset management agreements with Sequent remain in place and will expire on March 31, 2023 and March 31, 2025, respectively. Southern Company Gas also contracts for transportation and storage services from interstate pipelines that are regulated by the FERC. When firm pipeline services are temporarily not needed, Southern Company Gas may release the services in the secondary market under FERC-approved capacity release provisions or utilize asset management arrangements, thereby reducing the net cost of natural gas

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charged to customers for most of the natural gas distribution utilities. Peak-use requirements are met through utilization of company-owned storage facilities, pipeline transportation capacity, purchased storage services, peaking facilities, and other supply sources, arranged by either transportation customers or Southern Company Gas. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 herein for additional information on the sale of Sequent.

Territory Served by the Southern Company System

Traditional Electric Operating Companies and Southern Power

The territory in which the traditional electric operating companies provide retail electric service comprises most of the states of Alabama and Georgia, together with southeastern Mississippi. In this territory there are non-affiliated electric distribution systems that obtain some or all of their power requirements either directly or indirectly from the traditional electric operating companies. As of December 31, 2021, the territory had an area of approximately 116,000 square miles and an estimated population of approximately 16 million. Southern Power sells wholesale electricity at market-based rates across various U.S. utility markets, primarily to investor-owned utilities, IPPs, municipalities, and other load-serving entities, as well as commercial and industrial customers.

Alabama Power is engaged, within the State of Alabama, in the generation, transmission, distribution, and purchase of electricity and the sale of electric service, at retail in approximately 400 cities and towns (including Anniston, Birmingham, Gadsden, Mobile, Montgomery, and Tuscaloosa), as well as in rural areas, and at wholesale to 11 municipally-owned electric distribution systems, all of which are served indirectly through sales to AMEA, and two rural distributing cooperative associations. The sales contract with AMEA is scheduled to expire on December 31, 2025. In addition, Alabama Power sells, and cooperates with dealers in promoting the sale of, electric appliances and products and also markets and sells outdoor lighting services.

Georgia Power is engaged in the generation, transmission, distribution, and purchase of electricity and the sale of electric service within the State of Georgia, at retail in over 530 cities and towns (including Athens, Atlanta, Augusta, Columbus, Macon, Rome, and Savannah), as well as in rural areas, and at wholesale to OPC, MEAG Power, Dalton, various EMCs, and non-affiliated utilities. Georgia Power also markets and sells outdoor lighting services and other customer-focused utility services.

Mississippi Power is engaged in the generation, transmission, distribution, and purchase of electricity and the sale of electric service within 23 counties in southeastern Mississippi, at retail in 123 communities (including Biloxi, Gulfport, Hattiesburg, Laurel, Meridian, and Pascagoula), as well as in rural areas, and at wholesale to one municipality, six rural electric distribution cooperative associations, and one generating and transmitting cooperative.

The following table provides the number of retail customers served by customer classification for the traditional electric operating companies at December 31, 2021:


	Alabama Power	Georgia Power	Mississippi Power	Total(*)
	(in thousands)
Residential	1,309	2,329	156	3,795
Commercial	205	323	34	562
Industrial	6	11	—	17
Other	1	10	—	10
Total(*)	1,521	2,673	191	4,385

(*)Totals may not add due to rounding.

For information relating to KWH sales by customer classification for the traditional electric operating companies, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS in Item 7 herein. Also, for information relating to the sources of revenues for Southern Company, each traditional electric operating company, and Southern Power, see Item 7 herein and Note 1 to the financial statements under "Revenues – Traditional Electric Operating Companies" and " – Southern Power" and Note 4 to the financial statements in Item 8 herein.

As of December 31, 2021, there were 62 electric cooperative distribution systems operating in the territories in which the traditional electric operating companies provide electric service at retail or wholesale.

PowerSouth is a generating and transmitting cooperative selling power to several distributing cooperatives, municipal systems, and other customers in south Alabama. As of December 31, 2021, PowerSouth owned generating units with more than 1,600 MWs of nameplate capacity, including an undivided 8.16% ownership interest in Alabama Power's Plant Miller Units 1 and 2.

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See PROPERTIES – "Electric – Jointly-Owned Facilities" in Item 2 herein and Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information.

Alabama Power has power supply agreements with PowerSouth to provide 200 MWs of year-round capacity service through January 31, 2024 and 200 MWs of winter-only capacity service through December 31, 2023. In 2019, Alabama Power agreed to provide PowerSouth an additional 100 MWs of year-round capacity service from November 1, 2020 through February 28, 2023, with the option to extend through May 31, 2023. Additionally, in accordance with an agreement executed in August 2021, Alabama Power will provide approximately 100 MWs of year-round capacity service to PowerSouth beginning February 1, 2024.

On September 1, 2021, Alabama Power and PowerSouth began operations under a coordinated planning and operations agreement, with a minimum term of 10 years. The agreement includes combined operations (including joint commitment and dispatch) and real-time energy sales and purchases and is expected to create energy cost savings and enhanced system reliability for both parties. Projected revenues are expected to offset any increased administrative costs incurred by Alabama Power. Under the agreement, Alabama Power has the right to participate in a portion of PowerSouth's future incremental load growth.

Alabama Power also has a separate agreement with PowerSouth involving interconnection between their systems. The delivery of capacity and energy from PowerSouth to certain distributing cooperatives in the service territory of Alabama Power is governed by the Southern Company/PowerSouth Network Transmission Service Agreement. The rates for this service to PowerSouth are on file with the FERC.

OPC is an EMC owned by its 38 retail electric distribution cooperatives, which provide retail electric service to customers in Georgia. OPC provides wholesale electric power to its members through its generation assets, some of which are jointly owned with Georgia Power, and power purchased from other suppliers. OPC and the 38 retail electric distribution cooperatives are members of Georgia Transmission Corporation, an EMC (GTC), which provides transmission services to its members and third parties. See PROPERTIES – "Electric – Jointly-Owned Facilities" in Item 2 herein and Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information regarding Georgia Power's jointly-owned facilities.

Mississippi Power has an interchange agreement with Cooperative Energy, a generating and transmitting cooperative, pursuant to which various services are provided. Cooperative Energy also has a 10-year network integration transmission service agreement with SCS for transmission service to certain delivery points on Mississippi Power's transmission system through March 31, 2031. See Note 2 to the financial statements under "Mississippi Power – Municipal and Rural Associations Tariff" in Item 8 herein for information on an additional agreement between Mississippi Power and Cooperative Energy.

As of December 31, 2021, there were 72 municipally-owned electric distribution systems operating in the territory in which the traditional electric operating companies provide electric service at retail or wholesale.

As of December 31, 2021, 48 municipally-owned electric distribution systems and one county-owned system received their requirements through MEAG Power. MEAG Power serves these requirements from self-owned generation facilities, some of which are jointly-owned with Georgia Power, and purchases from other resources. MEAG Power also has a pseudo scheduling and services agreement with Georgia Power. Dalton serves its requirements from self-owned generation facilities, some of which are jointly-owned with Georgia Power, and through purchases from Southern Power through a service agreement. See PROPERTIES – "Electric – Jointly-Owned Facilities" in Item 2 herein and Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information.

Georgia Power has entered into substantially similar agreements with GTC, MEAG Power, and Dalton providing for the establishment of an integrated transmission system to carry the power and energy of all parties. The agreements require an investment by each party in the integrated transmission system in proportion to its respective share of the aggregate system load. See PROPERTIES – "Electric – Jointly-Owned Facilities" in Item 2 herein for additional information.

Southern Power has PPAs with Georgia Power, investor-owned utilities, IPPs, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. See "The Southern Company System – Southern Power" herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" in Item 7 herein for additional information.

SCS, acting on behalf of the traditional electric operating companies, also has a contract with SEPA providing for the use of the traditional electric operating companies' facilities at government expense to deliver to certain cooperatives and municipalities, entitled by federal statute to preference in the purchase of power from SEPA, quantities of power equivalent to the amounts of power allocated to them by SEPA from certain U.S. government hydroelectric projects.

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Southern Company Gas

Southern Company Gas is engaged in the distribution of natural gas in four states through the natural gas distribution utilities. The natural gas distribution utilities construct, manage, and maintain intrastate natural gas pipelines and distribution facilities. Details of the natural gas distribution utilities at December 31, 2021 are as follows:


Utility	State	Number of customers	Approximate miles of pipe
		(in thousands)
Nicor Gas	Illinois	2,260	34.6
Atlanta Gas Light	Georgia	1,695	34.2
Virginia Natural Gas	Virginia	312	5.8
Chattanooga Gas	Tennessee	70	1.7
Total		4,337	76.3

For information relating to the sources of revenue for Southern Company Gas, see Item 7 herein and Note 1 to the financial statements under "Revenues – Southern Company Gas" and Note 4 to the financial statements in Item 8 herein.

Competition

Electric

The electric utility industry in the U.S. is continuing to evolve as a result of regulatory and competitive factors. The competition for retail energy sales among competing suppliers of energy is influenced by various factors, including price, availability, technological advancements, service, and reliability. These factors are, in turn, affected by, among other influences, regulatory, political, and environmental considerations, taxation, and supply.

The retail service rights of all electric suppliers in the State of Georgia are regulated by the Territorial Electric Service Act of 1973. Pursuant to standards set forth in this Act, the Georgia PSC has assigned substantially all of the land area in the state to a supplier. Notwithstanding such assignments, this Act provides that any new customer locating outside of 1973 municipal limits and having a connected load of at least 900 KWs may exercise a one-time choice for the life of the premises to receive electric service from the supplier of its choice.

Pursuant to the 1956 Utility Act, the Mississippi PSC issued "Grandfather Certificates" of public convenience and necessity to Mississippi Power and to six distribution rural cooperatives operating in southeastern Mississippi, then served in whole or in part by Mississippi Power, authorizing them to distribute electricity in certain specified geographically described areas of the state. The six cooperatives serve approximately 325,000 retail customers in a certificated area of approximately 10,300 square miles. In areas included in a "Grandfather Certificate," the utility holding such certificate may extend or maintain its electric system subject to certain regulatory approvals; extensions of facilities by such utility, or extensions of facilities into that area by other utilities, may not be made unless the Mississippi PSC grants a CPCN. Areas included in a CPCN that are subsequently annexed to municipalities may continue to be served by the holder of the CPCN, irrespective of whether it has a franchise in the annexing municipality. On the other hand, the holder of the municipal franchise may not extend service into such newly annexed area without authorization by the Mississippi PSC.

Generally, the traditional electric operating companies have experienced, and expect to continue to experience, competition in their respective retail service territories in varying degrees from the development and deployment of alternative energy sources such as self-generation (as described below) and distributed generation technologies, as well as other factors. Further technological advancements or the implementation of policies in support of alternative energy sources may result in further competition.

Southern Power competes with investor-owned utilities, IPPs, and others for wholesale energy sales across various U.S. utility markets. The needs of these markets are driven by the demands of end users and the generation available. Southern Power's success in wholesale energy sales is influenced by various factors including reliability and availability of Southern Power's plants, availability of transmission to serve the demand, price, and Southern Power's ability to contain costs.

As of December 31, 2021, Alabama Power had cogeneration contracts in effect with seven industrial customers. Under the terms of these contracts, Alabama Power purchases excess energy generated by such companies. During 2021, Alabama Power purchased approximately 83 million KWHs from such companies at a cost of $3 million.

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As of December 31, 2021, Georgia Power had contracts in effect to purchase generation from 36 small IPPs. During 2021, Georgia Power purchased 4.9 billion KWHs from such companies at a cost of $289 million. Georgia Power also has PPAs for electricity with five cogeneration facilities. Payments are subject to reductions for failure to meet minimum capacity output. During 2021, Georgia Power purchased 406 million KWHs at a cost of $34 million from these facilities.

As of December 31, 2021, Mississippi Power had a cogeneration agreement in effect with one of its industrial customers. Under the terms of this contract, Mississippi Power purchases any excess generation. During 2021, Mississippi Power did not make any such purchases.

Natural Gas

Southern Company Gas' natural gas distribution utilities do not compete with other distributors of natural gas in their exclusive franchise territories but face competition from other energy products. Their principal competitors are electric utilities and fuel oil and propane providers serving the residential, commercial, and industrial markets in their service areas for customers who are considering switching to or from a natural gas appliance.

Competition for heating as well as general household and small commercial energy needs generally occurs at the initial installation phase when the customer or builder makes decisions as to which types of equipment to install. Customers generally use the chosen energy source for the life of the equipment.

Customer demand for natural gas could be affected by numerous factors, including:

•changes in the availability or price of natural gas and other forms of energy;

•general economic conditions;

•energy conservation, including state-supported energy efficiency programs;

•legislation and regulations, including certain city-wide bans on the use of natural gas in new construction;

•the cost and capability to convert from natural gas to alternative energy products; and

•technological changes resulting in displacement or replacement of natural gas appliances.

Southern Company Gas has natural gas-related programs that generally emphasize natural gas as the fuel of choice for customers and seek to expand the use of natural gas through a variety of promotional activities. In addition, Southern Company Gas partners with third-party entities to market the benefits of natural gas appliances.

Seasonality and Demand

The demand for electric power and natural gas supply is affected by seasonal differences in the weather. While the electric power sales of some electric utilities peak in the summer, others peak in the winter. In the aggregate, during normal weather conditions, the Southern Company system's electric power sales peak during both the summer and winter. In most of the areas Southern Company Gas serves, natural gas demand peaks during the winter. As a result, the overall operating results of the Registrants in the future may fluctuate substantially on a seasonal basis. In addition, the Subsidiary Registrants have historically sold less power and natural gas when weather conditions are milder.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "General" and – RESULTS OF OPERATIONS – "Southern Company Gas – Seasonality of Results" in Item 7 herein for information regarding trends in market demand for electricity and natural gas and the impact of seasonality on Southern Company Gas' business, respectively.

Regulation

States

The traditional electric operating companies and the natural gas distribution utilities are subject to the jurisdiction of their respective state PSCs or applicable state regulatory agencies. These regulatory bodies have broad powers of supervision and regulation over public utilities operating in the respective states, including their rates, service regulations, sales of securities (except for the Mississippi PSC), and, in the cases of the Georgia PSC and the Mississippi PSC, in part, retail service territories. See "Territory Served by the Southern Company System" and "Rate Matters" herein for additional information.

Federal Power Act

The traditional electric operating companies, Southern Power Company and certain of its generation subsidiaries, and SEGCO are all public utilities engaged in wholesale sales of energy in interstate commerce and, therefore, are subject to the rate, financial, and accounting jurisdiction of the FERC under the Federal Power Act. The FERC must approve certain financings and allows an "at cost standard" for services rendered by system service companies such as SCS and Southern Nuclear. The FERC is also authorized to establish regional reliability organizations which enforce reliability standards, address impediments to the construction of transmission, and prohibit manipulative energy trading practices.

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Alabama Power and Georgia Power are also subject to the provisions of the Federal Power Act or the earlier Federal Water Power Act applicable to licensees with respect to their hydroelectric developments. As of December 31, 2021, among the hydroelectric projects subject to licensing by the FERC are 14 existing Alabama Power generating stations having an aggregate installed capacity of 1.7 million KWs and 17 existing Georgia Power generating stations and one generating station partially owned by Georgia Power, with a combined aggregate installed capacity of 1.1 million KWs.

In 2013, the FERC issued a new 30-year license to Alabama Power for Alabama Power's seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin). Alabama Power filed a petition requesting rehearing of the FERC order granting the relicense seeking revisions to several conditions of the license. In 2016, the FERC issued an order granting in part and denying in part Alabama Power's rehearing request. American Rivers and Alabama Rivers Alliance also filed multiple appeals of the FERC's 2013 order for the new 30-year license and, in 2018, the U.S. Court of Appeals for the District of Columbia Circuit vacated the order and remanded the proceeding to the FERC. Alabama Power continues to operate the Coosa River developments under annual licenses issued by the FERC.

In November 2021, Alabama Power filed an application with the FERC to relicense the Harris Dam project on the Tallapoosa River. The current Harris Dam project license will expire on November 30, 2023.

In 2018, Georgia Power filed applications to surrender the Langdale and Riverview hydroelectric projects on the Chattahoochee River upon their license expirations on December 31, 2023. Both projects together represent 1,520 KWs of Georgia Power's hydro fleet capacity.

In December 2021, Georgia Power filed an application with the FERC to relicense the Lloyd Shoals project on the Ocmulgee River. The current Lloyd Shoals project license will expire on December 31, 2023.

Georgia Power and OPC also have a license, expiring in 2026, for the Rocky Mountain project, a pure pumped storage facility of 903,000 KW installed capacity. In December 2021, OPC, as an agent for co-licensees of the project, filed a notice of intent with the FERC to relicense the project. An application to relicense the project is expected to be filed with the FERC by December 31, 2024. See PROPERTIES – "Electric – Jointly-Owned Facilities" in Item 2 herein for additional information.

Licenses for all projects, excluding those discussed above, expire in the years 2034-2066 for Alabama Power's projects and in the years 2034-2060 for Georgia Power's projects.

Upon or after the expiration of each license, the U.S. Government, by act of Congress, may take over the project or the FERC may relicense the project either to the original licensee or to a new licensee. In the event of takeover or relicensing to another, the original licensee is to be compensated in accordance with the provisions of the Federal Power Act, such compensation to reflect the net investment of the licensee in the project, not in excess of the fair value of the property, plus reasonable damages to other property of the licensee resulting from the severance therefrom of the property. The FERC may grant relicenses subject to certain requirements that could result in additional costs.

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

Nuclear Regulation

Alabama Power, Georgia Power, and Southern Nuclear are subject to regulation by the NRC. The NRC is responsible for licensing and regulating nuclear facilities and materials and for conducting research in support of the licensing and regulatory process, as mandated by the Atomic Energy Act of 1954, as amended; the Energy Reorganization Act of 1974, as amended; and the Nuclear Nonproliferation Act of 1978, as amended; and in accordance with the National Environmental Policy Act of 1969, as amended, and other applicable statutes. These responsibilities also include protecting public health and safety, protecting the environment, protecting and safeguarding nuclear materials and nuclear power plants in the interest of national security, and assuring conformity with antitrust laws.

The NRC licenses for Georgia Power's Plant Hatch Units 1 and 2 expire in 2034 and 2038, respectively. The NRC licenses for Alabama Power's Plant Farley Units 1 and 2 expire in 2037 and 2041, respectively. The NRC licenses for Plant Vogtle Units 1 and 2 expire in 2047 and 2049, respectively.

In 2012, the NRC issued combined construction and operating licenses (COLs) for Plant Vogtle Units 3 and 4. Receipt of the COLs allowed full construction to begin. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 herein for additional information.

See Notes 3 and 6 to the financial statements under "Nuclear Insurance" and "Nuclear Decommissioning," respectively, in Item 8 herein for additional information.

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Environmental Laws and Regulations

See "Construction Programs" herein, MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" in Item 7 herein, and Note 3 to the financial statements under "Environmental Remediation" and Note 6 to the financial statements in Item 8 herein for information concerning environmental laws and regulations impacting the Registrants.

Rate Matters

Rate Structure and Cost Recovery Plans

Electric

The rates and service regulations of the traditional electric operating companies are uniform for each class of service throughout their respective retail service territories. Rates for residential electric service are generally of the block type based upon KWHs used and include minimum charges. Residential and other rates contain separate customer charges. Rates for commercial service are presently of the block type and, for large customers, the billing demand is generally used to determine capacity and minimum bill charges. These large customers' rates are generally based upon usage by the customer and include rates with special features to encourage off-peak usage. Additionally, Alabama Power and Mississippi Power are generally allowed by their respective state PSCs to negotiate the terms and cost of service to large customers. Such terms and cost of service, however, are subject to final state PSC approval.

The traditional electric operating companies recover certain costs through a variety of forward-looking, cost-based rate mechanisms. Fuel and net purchased energy costs are recovered through specific fuel cost recovery provisions. These fuel cost recovery provisions are adjusted to reflect increases or decreases in such costs as needed or on schedules as required by the respective PSCs. Approved compliance, storm damage, and certain other costs are recovered at Alabama Power and Mississippi Power through specific cost recovery mechanisms approved by their respective PSCs. Certain similar costs at Georgia Power are recovered through various base rate tariffs as approved by the Georgia PSC. Costs not recovered through specific cost recovery mechanisms are recovered at Alabama Power and Mississippi Power through annual, formulaic cost recovery proceedings and at Georgia Power through periodic base rate proceedings.

See Note 2 to the financial statements in Item 8 herein for a discussion of rate matters and certain cost recovery mechanisms. Also see "Integrated Resource Planning" herein for additional information.

The traditional electric operating companies and Southern Power Company and certain of its generation subsidiaries are authorized by the FERC to sell power to non-affiliates, including short-term opportunity sales, at market-based prices. Specific FERC approval must be obtained with respect to a market-based contract with an affiliate.

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 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.

Natural Gas

Southern Company Gas' natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies. Rates charged to customers vary according to customer class (residential, commercial, or industrial) and rate jurisdiction. These agencies approve rates designed to provide the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable ROE.

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. The natural gas distribution utilities have weather or revenue normalization mechanisms that mitigate revenue fluctuations from customer consumption changes. Atlanta Gas Light operates in a deregulated environment in which Marketers rather than a traditional utility sell natural gas to end-use customers and earns revenue by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC.

See Note 2 to the financial statements under "Southern Company Gas" in Item 8 herein for a discussion of rate matters and certain cost recovery mechanisms.

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Integrated Resource Planning

Each of the traditional electric operating companies continually evaluates its electric generating resources in order to ensure that it maintains a cost-effective and reliable mix of resources to meet the existing and future demand requirements of its customers. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" in Item 7 herein for a discussion of existing and potential environmental regulations that may impact the future generating resource needs of the traditional electric operating companies, as well as a discussion of the Southern Company system's continued generating fleet transition.

Alabama Power

Triennially, Alabama Power provides an IRP report to the Alabama PSC. This report overviews Alabama Power's resource planning process and contains information that serves as the foundation for certain decisions affecting Alabama Power's portfolio of supply-side and demand-side resources. The IRP report facilitates Alabama Power's ability to provide reliable and cost-effective electric service to customers, while accounting for the risks and uncertainties inherent in planning for resources sufficient to meet expected customer demand. Under State of Alabama law, a CCN must be obtained from the Alabama PSC before Alabama Power constructs any new generating facility, unless such construction is an ordinary extension of an existing system in the usual course of business. On October 28, 2021, Alabama Power filed a petition for a CCN with the Alabama PSC to procure additional generating capacity through the acquisition of a 743-MW winter peak, simple-cycle, combustion turbine generation facility in Calhoun County, Alabama. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements under "Alabama Power – Certificates of Convenience and Necessity" in Item 8 herein for additional information.

Georgia Power

Triennially, Georgia Power must file an IRP with the Georgia PSC that specifies how it intends to meet the future electric service needs of its customers through a combination of demand-side and supply-side resources. The Georgia PSC, under state law, must certify any new demand-side or supply-side resources for Georgia Power to receive cost recovery. Once certified, the lesser of actual or certified construction costs and purchased power costs is recoverable through rates. Certified costs may be excluded from recovery only on the basis of fraud, concealment, failure to disclose a material fact, imprudence, or criminal misconduct. On January 31, 2022, Georgia Power filed its triennial IRP with the Georgia PSC. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plan" and " – Rate Plans" in Item 8 herein for additional information. Also see Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 herein for additional information on the Georgia Nuclear Energy Financing Act and the Georgia PSC certification of Plant Vogtle Units 3 and 4, which allow Georgia Power to recover certain financing costs for construction of Plant Vogtle Units 3 and 4.

Mississippi Power

In 2019, the Mississippi PSC established the Integrated Resource Planning and Reporting Rule, which requires long-term plans to best meet the needs of electric utility customers through a combination of demand-side and supply-side resources and considering transmission needs, including the triennial filing of an IRP, with supply-side updates midway through the three-year cycle, and an annual report on energy delivery improvements. The IRP filing is not intended to supplant or replace the Mississippi PSC's existing regulatory processes for petition and approval of CPCNs for new generating resources. 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. See Note 2 to the financial statements under "Mississippi Power – Integrated Resource Plan" in Item 8 herein for additional information.

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Human Capital

Southern Company system management is committed to attracting, developing, and retaining a sustainable workforce and aims to foster a diverse, equitable, inclusive, and innovative culture. The Southern Company system's values – safety first, unquestionable trust, superior performance, and total commitment – guide behavior. The Southern Company system had approximately 27,300 employees on its payroll at December 31, 2021 comprised of the following:


			At December 31, 2021(*)
Alabama Power			6,100
Georgia Power			6,500
Mississippi Power			1,000
Southern Power			500
Southern Company Gas			4,500
SCS			3,800
Southern Nuclear			3,800
PowerSecure and other			1,100
Total Southern Company system			27,300

(*)Numbers are rounded to 100s.

All Southern Company system employees are located within the United States. Part-time employees represent less than 1% of total employees.

Southern Company system management values a diverse, equitable, and inclusive workforce. Southern Company's subsidiaries have policies, programs, and processes to help ensure that all groups are represented, included, and fairly treated across all job levels. The Southern Company Board of Directors and management believe that diversity is important to provide different perspectives on risk, business strategy, and innovation. Southern Company management leads the Southern Company system's diversity, equity, and inclusion initiatives and employee recruitment, retention, and development efforts. The Board, principally through its Compensation and Management Succession Committee, oversees these efforts. In 2020, Southern Company system management launched the "Moving to Equity" initiative that focuses on five key areas: talent, workplace environment, community, political engagement, and supplier diversity. This initiative demonstrates the Southern Company system's commitments, highlights key results, and tracks progress on long-term goals.

Southern Company system management supports employee resource groups, diversity councils, and inclusion teams to provide formal networks of colleagues that can help promote belonging, improve employee retention, and support development. At December 31, 2021, people of color and women represented 29% and 25%, respectively, of the Southern Company system's workforce.

Southern Company system management recognizes the importance of attracting and retaining an appropriately qualified workforce. Southern Company system management uses a variety of strategies to attract and retain talent, including working with high schools, technical schools, universities, and military installations to fill many entry-level positions. The recruiting strategy also includes partnerships with professional associations and local communities to recruit mid-career talent. The addition of external hires augments the existing workforce to meet changing business needs, address any critical skill gaps, and supplement and diversify the Southern Company system's talent pipeline.

The Southern Company system supports the well-being of its employees through a comprehensive total rewards strategy with three measurable categories: physical, financial, and emotional well-being. The Southern Company system provides competitive salaries, annual incentive awards for nearly all employees, and health, welfare, and retirement benefits. The Southern Company system has a qualified defined benefit, trusteed pension plan and a qualified defined contribution, trusteed 401(k) plan which provides a competitive company matching contribution. Substantially all Southern Company system employees are eligible to participate in these plans. There are differences between the pension plan benefit formulas based on when and by which subsidiary an employee is hired. See Note 11 to the financial statements for additional information. At December 31, 2021, the average age of the Southern Company system employees was 45 and the average tenure with the Southern Company system was 15 years. Turnover rate, calculated as the percent of employees that terminated employment with the Southern Company system, including voluntary and involuntary terminations and retirements, divided by total employees, was 7.7%.

Southern Company system management is committed to developing talent and helping employees succeed by providing development opportunities along with purposeful people moves as part of individual development plans and succession planning processes. The Southern Company system has multiple development programs, including programs targeted toward all

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employees, high potential employees, first-level managers, managers of managers, and executives. Additionally, Southern Company system management strives to deliver consistent needs-based training and solutions as workplace needs evolve.

Southern Company system management believes the safety of employees and customers is paramount. The Southern Company system seeks to meet or exceed applicable laws and regulations while continually improving its safety technologies and processes. The Southern Company System Safety and Health Council, which includes leaders from each Registrant, works collectively across the Southern Company system to provide safety leadership, share learning, work collaboratively to address safety-related issues, and govern the consistency of safety programs. The safety programs are focused on the prevention and elimination of life-altering events, serious injuries, and fatalities. These programs include continuous process improvements to put critical controls in place to prevent serious injuries, promote learning, and implement appropriate corrective actions. In 2021, the Southern Company system had a serious injury rate of 0.05, which represents the number of incidents per 100 employees (calculated by taking the number of serious injuries multiplied by 200,000 workhours and divided by the total employee workhours during the year). A serious injury is one that is life-threatening or life-changing for the employee. Serious injury examples, as defined by applicable safety regulators, include fatalities, amputations, trauma to organs, certain bone fractures, severe burns, and eye injuries.

Since the onset of the COVID-19 pandemic in early 2020, the Southern Company system has continued to provide essential services to customers while protecting employees, customers, and communities by implementing applicable business continuity plans, including teleworking, canceling nonessential business travel, increasing cleaning frequency at business locations, implementing applicable safety and health guidelines issued by federal, state, and local officials, and establishing protocols for required work on customer premises. To date, these procedures have been effective in maintaining the Southern Company system's critical operations, while also emphasizing employee, customer, and community safety.

The Southern Company system also has longstanding relationships with labor unions. The traditional electric operating companies, Southern Nuclear, and the natural gas distribution utilities have separate agreements with local unions of the IBEW, which generally apply to operating, maintenance, and construction employees. These agreements cover wages, benefits, terms of the pension plans, working conditions, and procedures for handling grievances and arbitration. The Southern Company system also partners with the IBEW to provide training programs to develop technical skills and career opportunities.

At December 31, 2021, approximately 32% of Southern Company system employees were covered by agreements with unions, with agreements expiring between 2023 and 2026.

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Item 1A. RISK FACTORS

In addition to the other information in this Form 10-K, including MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL in Item 7, and other documents filed by Southern Company and/or its subsidiaries with the SEC, the following factors should be carefully considered in evaluating Southern Company and its subsidiaries. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, Southern Company and/or its subsidiaries. The risk factors discussed below could adversely affect a Registrant's results of operations, financial condition, liquidity, and cash flow, as well as cause reputational damage.

UTILITY REGULATORY, LEGISLATIVE, AND LITIGATION RISKS

Southern Company and its subsidiaries are subject to substantial federal, state, and local governmental regulation, including with respect to rates. Compliance with current and future regulatory requirements and procurement of necessary approvals, permits, and certificates may result in substantial costs to Southern Company and its subsidiaries.

Laws and regulations govern the terms and conditions of the services the Southern Company system offers, protection of critical electric infrastructure assets, transmission planning, reliability, pipeline safety, interaction with wholesale markets, and relationships with affiliates, among other matters. The Registrants' businesses are subject to regulatory regimes which could result in substantial monetary penalties if a Registrant is found to be noncompliant.

The profitability of the traditional electric operating companies' and the natural gas distribution utilities' businesses is largely dependent on their ability, through the rates that they are permitted to charge, to recover their costs and earn a reasonable rate of return on invested capital. The traditional electric operating companies and the natural gas distribution utilities seek to recover their costs, including compliance costs (including a reasonable return on invested capital), through their retail rates, which must be approved by the applicable state PSC or other applicable state regulatory agency. Such regulators, in a future rate proceeding, may alter the timing or amount of certain costs for which recovery is allowed or modify the current authorized rate of return. Rate refunds may also be required. Additionally, the rates charged to wholesale customers by the traditional electric operating companies and Southern Power and the rates charged to natural gas transportation customers by Southern Company Gas' pipeline investments and for some of its storage assets must be approved by the FERC. Changes to Southern Power's and the traditional electric operating companies' ability to conduct business pursuant to FERC market-based rate authority could affect wholesale rates. Also, while a small percentage of transmission revenues are collected through wholesale electric tariffs, the majority are collected through retail rates. Transmission planning could be impacted by FERC policy changes.

The impact of any future revision or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to Southern Company or any of its subsidiaries is uncertain. Changes in regulation, the imposition of additional regulations, changes in enforcement practices of regulators, or penalties imposed for noncompliance with existing laws or regulations could influence the operating environment of the Southern Company system and may result in substantial costs.

The Southern Company system's costs of compliance with environmental laws and satisfying related AROs are significant.

The Southern Company system's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, GHGs, water, land, avian and other wildlife and habitat protection, and other natural resources. Compliance with existing environmental requirements involves significant capital and operating costs including the settlement of AROs, a major portion of which is expected to be recovered through retail and wholesale rates. There is no assurance, however, that all such costs will be recovered. The Registrants expect future compliance expenditures will continue to be significant.

The EPA has adopted and is implementing regulations governing air and GHG emissions under the Clean Air Act and water quality under the Clean Water Act. The EPA and certain states have also adopted and continue to propose regulations governing the disposal and management of CCR at power plant sites. The cost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential compliance methods. The traditional electric operating companies will continue to periodically update their ARO cost estimates.

Additionally, environmental laws and regulations covering the handling and disposal of waste and release of hazardous substances could require the Southern Company system to incur substantial costs to clean up affected sites, including certain current and former operating sites, and locations subject to contractual obligations.

Litigation over environmental issues and claims of various types, including property damage, personal injury, and citizen enforcement of environmental requirements has occurred throughout the U.S. This litigation has included, but is not limited to,

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claims for damages alleged to have been caused by CO2 and other emissions, CCR, releases of regulated substances, alleged exposure to regulated substances, and/or requests for injunctive relief in connection with such matters.

Compliance with any new or revised environmental laws or regulations could affect many areas of operations for the Southern Company system. The Southern Company system's ultimate environmental compliance strategy and future environmental expenditures will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, fuel prices, and the outcome of pending and/or future legal challenges. Compliance costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, operational changes, or changing fuel sources for certain existing units, as well as related upgrades to the Southern Company system's transmission and distribution (electric and natural gas) systems. Environmental compliance spending over the next several years may differ materially from the amounts estimated and could adversely affect the Registrants if such costs cannot continue to be recovered on a timely basis. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to reduce their demand for electricity or natural gas.

The Southern Company system may be exposed to regulatory and financial risks related to the impact of GHG legislation, regulation, and emission reduction goals.

Concern and activism about climate change continue to increase and, as a result, demand for energy conservation and sustainable assets could further increase. Additionally, costs associated with GHG legislation, regulation, and emission reduction goals could be significant.

The Southern Company system has robust processes for identifying, assessing, and responding to climate-related risks, including a scenario planning process that is used to inform resource planning decisions in the states in which the traditional electric operating companies operate. This process relies on information from internal and external sources, which may or may not be accurate in predicting future outcomes. Each year, the Southern Company system develops scenarios which look out over a 30-year horizon. In 2021, scenarios included a wide range of fuel prices, load growth, and CO2 prices starting between $0 and $50 per metric ton of CO2 emitted and escalating over the 30-year horizon.

Additional GHG policies, including legislation, may emerge requiring the United States to accelerate its transition to a lower GHG emitting economy. However, the ultimate impact will depend on various factors, such as state adoption and implementation of requirements, natural gas prices, the development, deployment, and advancement of relevant energy technologies, the ability to recover costs through existing ratemaking provisions, and the outcome of pending and/or future legal challenges.

Because natural gas is a fossil fuel with lower carbon content relative to other fossil fuels, future carbon constraints, including, but not limited to, the imposition of a carbon tax, may create additional demand for natural gas, both for production of electricity and direct use in homes and businesses. However, such demand may be tempered by legislation limiting the use of natural gas in certain situations, such as new construction. Additionally, efforts to electrify the transportation and building sectors may result in higher electric demand and negatively impact natural gas demand. Future GHG constraints, including those related to methane emissions, designed to minimize emissions from natural gas could likewise result in increased costs to the Southern Company system and affect the demand for natural gas as well as the prices charged to customers and the competitive position of natural gas.

Southern Company has established an intermediate goal of a 50% reduction in GHG emissions from 2007 levels by 2030 and a long-term goal of net zero GHG emissions by 2050. Achievement of these goals is dependent on many factors, including natural gas prices and the pace and extent of development and deployment of low- to no-GHG energy technologies and negative carbon concepts. The strategy to achieve these goals also relies on continuing to pursue a diverse portfolio including low-carbon and carbon-free resources and energy efficiency resources; continuing to transition the Southern Company system's generating fleet and making the necessary related investments in transmission and distribution systems; continuing research and development with a particular focus on technologies that lower GHG emissions, including methods of removing carbon from the atmosphere; and constructively engaging with policymakers, regulators, investors, customers, and other stakeholders to support outcomes leading to a net zero future.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" in Item 7 herein for additional information.

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OPERATIONAL RISKS

The financial performance of Southern Company and its subsidiaries may be adversely affected if the subsidiaries are unable to successfully operate their facilities or perform certain corporate functions.

The financial performance of Southern Company and its subsidiaries depends on the successful operation of the electric generation, transmission, and distribution facilities, natural gas distribution and storage facilities, and distributed generation storage technologies and the successful performance of necessary corporate functions. There are many risks that could affect these matters, including operator error or failure of equipment or processes, accidents, operating limitations that may be imposed by environmental or other regulatory requirements or in connection with joint owner arrangements, labor disputes, physical attacks, fuel or material supply interruptions and/or shortages, transmission disruption or capacity constraints, including with respect to the Southern Company system's and third parties' transmission, storage, and transportation facilities, compliance with mandatory reliability standards, including mandatory cyber security standards, implementation of new technologies, technology system failures, cyber intrusions, environmental events, such as spills or releases, and catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes and other storms, droughts, pandemic health events, political unrest, or other similar occurrences.

Operation of nuclear facilities involves inherent risks, including environmental, safety, health, regulatory, natural disasters, cyber intrusions, physical attacks, and financial risks, that could result in fines or the closure of the nuclear units owned by Alabama Power or Georgia Power and which may present potential exposures in excess of insurance coverage.

Alabama Power owns, and contracts for the operation of, two nuclear units and Georgia Power holds undivided interests in, and contracts for the operation of, four existing nuclear units. The six existing units are operated by Southern Nuclear and represented approximately 26% and 28% of the total KWHs generated by Alabama Power and Georgia Power, respectively, in the year ended December 31, 2021. In addition, Southern Nuclear, on behalf of Georgia Power and the other Vogtle Owners, is managing the construction of Plant Vogtle Units 3 and 4. Nuclear facilities are subject to environmental, safety, health, operational, and financial risks such as: the potential harmful effects on the environment and human health and safety resulting from a release of radioactive materials; uncertainties with respect to the ability to dispose of spent nuclear fuel and the need for longer term on-site storage; uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of licensed lives and the ability to maintain and anticipate adequate capital reserves for decommissioning; limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with any nuclear operations; and significant capital expenditures relating to maintenance, operation, security, and repair of these facilities.

Damages, decommissioning, or other costs could exceed the amount of decommissioning trusts or external insurance coverage, including statutorily required nuclear incident insurance.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear facilities. In the event of non-compliance, the NRC has the authority to impose fines and/or shut down any unit, depending upon its assessment of the severity of the situation, until compliance is achieved. NRC orders or regulations related to increased security measures and any future NRC safety requirements could require Alabama Power and Georgia Power to make substantial operating and capital expenditures at their nuclear plants. In addition, if a serious nuclear incident were to occur, it could result in substantial costs to Alabama Power or Georgia Power and Southern Company. A major incident at a nuclear facility anywhere in the world could cause the NRC to delay or prohibit construction of new nuclear units or require additional safety measures at new and existing units. Moreover, a major incident at any nuclear facility in the U.S., including facilities owned and operated by third parties, could require Alabama Power and Georgia Power to make material contributory payments.

In addition, actual or potential threats of cyber intrusions or physical attacks could result in increased nuclear licensing or compliance costs that are difficult to predict.

Transporting and storing natural gas involve risks that may result in accidents and other operating risks and costs.

Southern Company Gas' natural gas distribution and storage activities involve a variety of inherent hazards and operating risks, such as leaks, accidents, explosions, and mechanical problems, which could result in serious injury, loss of life, significant damage to property, environmental pollution, and impairment of its operations. The location of pipelines and storage facilities near populated areas could increase the level of damage resulting from these risks. Additionally, these pipeline and storage facilities are subject to various state and other regulatory requirements. Failure to comply with these requirements could result in substantial monetary penalties or potential early retirement of storage facilities, which could trigger an associated impairment.

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Physical attacks, both threatened and actual, could impact the ability of the Subsidiary Registrants to operate.

The Subsidiary Registrants face the risk of physical attacks, both threatened and actual, against their respective generation and storage facilities and the transmission and distribution infrastructure used to transport energy, which could negatively impact their ability to generate, transport, and deliver power, or otherwise operate their respective facilities, or, with respect to Southern Company Gas, its ability to distribute or store natural gas, or otherwise operate its facilities, in the most efficient manner or at all. In addition, physical attacks against third-party providers could have a similar effect on the Southern Company system.

Despite the implementation of robust security measures, all assets are potentially vulnerable to disability, failures, or unauthorized access due to human error, natural disasters, technological failure, or internal or external physical attacks. If assets were to fail, be physically damaged, or be breached and were not restored in a timely manner, the affected Subsidiary Registrant may be unable to fulfill critical business functions. Insurance may not be adequate to cover any associated losses.

An information security incident, including a cybersecurity breach, or the failure of, or inability to remotely access, one or more key technology systems, networks, or processes could impact the ability of the Registrants to operate.

The Subsidiary Registrants operate in highly regulated industries that require the continued operation of sophisticated technology systems and network infrastructure, which are part of interconnected systems. Because of the critical nature of the infrastructure and the technology systems' inherent vulnerability to disability or failures due to hacking, viruses, denial of service, ransomware, acts of war or terrorism, or other types of data security breaches, the Southern Company system faces a heightened risk of cyberattack. Cyber actors, including those associated with foreign governments, have attacked and threatened to attack energy infrastructure. Various regulators have increasingly stressed that these attacks, including ransomware attacks, and attacks targeting utility systems and other critical infrastructure, are increasing in sophistication, magnitude, and frequency.

The Registrants and their third-party vendors have been subject, and will likely continue to be subject, to attempts to gain unauthorized access to their technology systems and confidential data or to attempts to disrupt utility and related business operations. While there have been immaterial incidents of phishing, unauthorized access to technology systems, financial fraud, and disruption of remote access across the Southern Company system, there has been no material impact on business or operations from these attacks. However, the Registrants cannot guarantee that security efforts will detect or prevent breaches, operational incidents, or other breakdowns of technology systems and network infrastructure and cannot provide any assurance that such incidents will not have a material adverse effect in the future.

In addition, in the ordinary course of business, Southern Company and its subsidiaries collect and retain sensitive information, including personally identifiable information about customers, employees, and stockholders, and other confidential information. In some cases, administration of certain functions may be outsourced to third-party service providers. Malicious actors may target these providers to disrupt the services they provide to the Registrants, or to use those third parties to attack the Registrants. The Registrants' third-party service providers could fail to establish adequate risk management and information security measures with respect to their systems.

Internal or external cyber attacks may inhibit the affected Registrant's ability to fulfill critical business functions, including energy delivery service failures, compromise sensitive and other data, violate privacy laws, and lead to customer dissatisfaction. Any cyber breach or theft, damage, or improper disclosure of sensitive electronic data may also subject the affected Registrant to penalties and claims from regulators or other third parties. Insurance may not be adequate to cover any associated losses. Additionally, the cost and operational consequences of implementing, maintaining, and enhancing system protection measures are significant, and they could materially increase to address ever changing intense, complex, and sophisticated cyber risks.

The Southern Company system may not be able to obtain adequate natural gas, fuel supplies, and other resources required to operate the traditional electric operating companies' and Southern Power's electric generating plants or serve Southern Company Gas' natural gas customers.

SCS, on behalf of the traditional electric operating companies and Southern Power, purchases fuel for the Southern Company system's generation fleet from a diverse set of suppliers. Southern Company Gas' primary business is the distribution of natural gas through the natural gas distribution utilities. Natural gas is delivered daily from different regions of the country. This daily supply is complemented by natural gas supplies stored in both company-owned and third party storage locations. To deliver this daily supply and stored natural gas, the Southern Company system has firm transportation capacity contracted with third party interstate pipelines. Disruption in the supply and/or delivery of fuel as a result of matters such as transportation delays, weather, labor relations, force majeure events, or environmental regulations affecting fuel suppliers could limit the ability of the traditional electric operating companies and Southern Power to operate certain facilities, which could result in higher fuel and operating costs, and the ability of Southern Company Gas to serve its natural gas customers.

The Southern Company system is dependent upon natural gas as a fuel source for its power generation needs, which not only has the potential to impact the traditional electric operating companies' and Southern Power's costs of generation but the costs

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of purchased power as well. The robust growth in supply allowed natural gas prices to moderate and remain below $3 per mmBtu in recent years; however, demand increases in 2021 resulted in price increases and high volatility. Prices have averaged approximately $3.75 per mmBtu in 2021, and 2022 prices are expected to be in the same range. Forward prices are expected to decline over the next several years toward $3 per mmBtu. With the majority of natural gas production being from shale gas formations, any limitation on shale gas production would be expected to have a material impact on the supply availability as well as the cost of natural gas. In addition, new demand, in particular exports to Mexico and those from LNG facilities, has grown significantly and is having greater impact on the traditional electric operating companies' and Southern Power's natural gas markets.

The traditional electric operating companies are also dependent on coal, and related coal supply contracts, for a portion of their electric generating capacity. The counterparties to coal supply contracts may not fulfill their obligations to supply coal because of financial or technical problems. In addition, the suppliers may be delayed in supplying or may not be required to supply coal under certain circumstances, such as in the event of a natural disaster. If the traditional electric operating companies are unable to obtain their contracted coal requirements, they may be required to purchase their coal requirements at higher prices, and these increased costs may not be recoverable through rates. The railroad industry is experiencing labor shortages, which could lead to delays in coal deliveries or increased costs. Additionally, the utility industry is also being impacted by coal delivery challenges associated with new railroad management systems which favor stable, predictable deliveries and a market trend of shifting railroad capacity away from coal deliveries to other industries.

In addition to fuel supply, the traditional electric operating companies and Southern Power also need adequate access to water, which is drawn from nearby sources, to aid in the production of electricity. Any impact to their water resources could also limit the ability of the traditional electric operating companies and Southern Power to operate certain facilities, which could result in higher fuel and operating costs.

The revenues of Southern Company, the traditional electric operating companies, and Southern Power depend in part on sales under PPAs, the success of which depend on PPA counterparties performing their obligations, Southern Company subsidiaries satisfying minimum requirements under the PPAs, and renewal or replacement of the PPAs for the related generating capacity.

Most of Southern Power's generating capacity has been sold to purchasers under PPAs. Southern Power's top three customers, Southern California Edison, Georgia Power, and Tennessee Valley Authority accounted for 7.4%, 6.3%, and 6.3%, respectively, of Southern Power's total revenues for the year ended December 31, 2021. The traditional electric operating companies have entered into PPAs with non-affiliated parties.

The revenues related to PPAs are dependent on the continued performance by the purchasers of their obligations. Although the credit evaluations undertaken and contractual protections implemented by Southern Power and the traditional electric operating companies take into account the possibility of default by a purchaser, actual exposure to a default by a purchaser may be greater than predicted or specified in the applicable contract.

Additionally, neither Southern Power nor any traditional electric operating company can predict whether the PPAs will be renewed at the end of their respective terms or on what terms any renewals may be made. If one of these Registrants is unable to replace expiring PPAs with an acceptable new revenue contract, it may be required to sell the power produced by the facility at wholesale prices and be exposed to market fluctuations and risks, or the affected site may temporarily or permanently cease operations. The failure to satisfy minimum operational or availability requirements under these PPAs, including PPAs related to projects under construction, could result in payment of damages or termination of the PPAs.

Increased competition from other companies that supply energy or generation and storage technologies and changes in customer demand for energy could negatively impact Southern Company and its subsidiaries.

The traditional electric operating companies operate under a business model that invests capital to serve customers and recovers those investments and earns a return for investors through state regulation. Southern Power's business model is primarily focused on investing capital or building energy assets to serve creditworthy counterparties using a bilateral contract model. A key premise of these business models is that generating power at power plants achieves economies of scale and produces power at a competitive cost.

Customers and stakeholders are increasingly focused on the Registrants' ability to meet rapidly changing demands for new and varied products, services, and offerings. Additionally, the risk of global climate change continues to shape customers' and stakeholders' sustainability goals and energy needs.

New technologies such as distributed energy resources and microgrids and increased customer and stakeholder demand for sustainable assets could change the type of assets constructed and/or the methods for cost recovery. Advances in these technologies or changes in laws or regulations could reduce the cost of distributed generation storage technologies or other alternative methods of producing power to a level that is competitive with that of most power generation production or result in

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smaller-scale, more fuel efficient, and/or more cost effective distributed generation that allows for increased self-generation by customers. Broader use of distributed generation by retail energy customers may also result from customers' changing perceptions of the merits of utilizing existing generation technology or tax or other economic incentives. Additionally, a state PSC or legislature may modify certain aspects of the traditional electric operating companies' business as a result of these advances in technology, which may provide for further competition from these alternative sources of generation.

It is also possible that rapid advances in power generation technology could reduce the value of the current electric generating facilities owned by the traditional electric operating companies and Southern Power. Changes in technology could also alter the channels through which electric customers buy or utilize power.

Southern Company Gas' business is dependent on natural gas prices remaining competitive as compared to other forms of energy. Southern Company Gas' gas marketing services segment also is affected by competition from other energy marketers providing similar services in Southern Company Gas' unregulated service territories, most notably in Illinois and Georgia. Southern Company Gas competes with natural gas facilities in the Gulf Coast region of the U.S., where the majority of the existing and proposed high deliverability salt-dome natural gas storage facilities in North America are located.

If new technologies become cost competitive and achieve sufficient scale, the market share of the Subsidiary Registrants could be eroded, and the value of their respective electric generating facilities or natural gas distribution and storage facilities could be reduced. Additionally, these technology and customer-induced changes to the electric generation business models could change the risk profile of the Southern Company system's historical capital investments. Southern Company Gas' market share could be reduced if Southern Company Gas cannot remain price competitive in its unregulated markets.

The Subsidiary Registrants are subject to workforce factors that could affect operations.

The Southern Company system must attract, train, and retain a workforce to meet current and future needs. Events such as an aging workforce without appropriate replacements, increased cost or reduced supply of labor, mismatch of skill sets to future needs, or unavailability of contract resources may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development, including workforce needs associated with major construction projects and ongoing operations. The Southern Company system may be subject to workforce trends occurring in the United States triggered by decisions of employees to leave the workforce and/or their employer at higher rates as compared to prior years. The Southern Company system's costs, including costs for contractors to replace employees, productivity costs, and safety costs, may rise. Failure to hire and adequately obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect Southern Company and its subsidiaries' ability to manage and operate their businesses.

The Registrants are subject to risks related to the COVID-19 pandemic, including, but not limited to, disruption to the construction of Plant Vogtle Units 3 and 4 for Southern Company and Georgia Power.

In response to the COVID-19 pandemic, most jurisdictions, including in the United States, initially instituted restrictions on travel, public gatherings, and non-essential business operations. While some jurisdictions, including some in the Southern Company system's service territory, have relaxed some of these restrictions, some remain and there is no guarantee restrictions will not be reimposed in the future. These restrictions, as well as changes in individual behavior in response to the pandemic, have significantly disrupted economic activity in the service territories of the traditional electric operating companies and the natural gas distribution utilities and caused volatility in capital markets at certain periods during 2020 and 2021 and could continue to do so in the future. The Registrants cannot predict the extent or duration of the pandemic, the impact of new variants of COVID-19, the timing, availability, distribution, or effectiveness of vaccines, anti-virals, or other treatments or preventions for COVID-19, governmental responsive measures, including vaccine mandates, or the extent of the effects or impacts on the global, national, or local economy, the capital markets, or the Subsidiary Registrants' customers, suppliers, or operations.

The effects of the continued COVID-19 pandemic and related global, federal, state, and local responses could include new or extended disruptions to supply chains and capital markets, further reduced labor availability and productivity, and new or prolonged reductions in economic activity. These effects could have a variety of adverse impacts on the Registrants, including, but not limited to, new or prolonged reductions in demand for energy, particularly from commercial and industrial customers, impairment of goodwill or long-lived assets, reductions in investments recorded at fair value, further increases in costs of necessary equipment, and further challenges to the development, construction, and/or operation of the Registrants' facilities, including electric generation, transmission, and distribution assets, the performance of necessary corporate and customer service functions, and access to funds from financial institutions and capital markets.

The effects of the COVID-19 pandemic also could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4, as discussed in Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 herein.

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CONSTRUCTION RISKS

The Registrants have incurred and may incur additional costs or delays in the construction of new plants or other facilities and may not be able to recover their investments. Also, existing facilities of the Subsidiary Registrants require ongoing expenditures, including those to meet AROs and other environmental standards and goals.

The businesses of the Registrants require substantial expenditures for investments in new facilities as well as capital improvements, including transmission, distribution, and generation facilities for the traditional electric operating companies, generation facilities for Southern Power, and capital improvements to natural gas distribution facilities for Southern Company Gas. These expenditures also include those to settle AROs and meet environmental standards and goals. The traditional electric operating companies and Southern Power are in the process of constructing new generating facilities and adding environmental modifications to certain existing generating facilities and Southern Company Gas is replacing certain pipe in its natural gas distribution system. The traditional electric operating companies also are in the process of closing ash ponds to comply with the CCR Rule and, where applicable, state CCR rules. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, expanding and improving the electric transmission and electric and natural gas distribution systems, and undertaking projects to comply with environmental laws and regulations. These projects are long term in nature and in some cases may include the development and construction of facilities with designs that have not been finalized or previously constructed.

The completion of these types of projects without delays or significant cost overruns is subject to substantial risks that have occurred or may occur, including labor costs, availability, and productivity; challenges with the management of contractors or vendors; subcontractor performance; adverse weather conditions; shortages, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delays; delays due to judicial or regulatory action; nonperformance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance matters including, for Plant Vogtle Units 3 and 4, inspections and the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related investigations, reviews, and approvals by the NRC necessary to support NRC authorization to load fuel; challenges with start-up activities, including major equipment failure, or system integration; and/or operational performance; and challenges related to the COVID-19 pandemic or future pandemic health events; continued public and policymaker support for projects; environmental and geological conditions; delays or increased costs to interconnect facilities to transmission grids; and increased financing costs as a result of changes in market interest rates or as a result of project delays.

If a Subsidiary Registrant is unable to complete the development or construction of a project or decides to delay or cancel construction of a project, it may not be able to recover its investment in that project and may incur substantial cancellation payments under equipment purchase orders or construction contracts, as well as other costs associated with the closure and/or abandonment of the construction project.

In addition, partnership and joint ownership agreements may provide partners or co-owners with certain decision-making authority in connection with projects under construction, including rights to change ownership allocations and/or cause the cancellation of a construction project under certain circumstances. Any failure by a partner or co-owner to perform its obligations under the applicable agreements could have a material negative impact on the applicable project under construction. Southern Power participates in partnership agreements with respect to a majority of its renewable energy projects and Georgia Power jointly owns Plant Vogtle Units 3 and 4 with other co-owners. See Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information regarding other jointly-owned facilities.

If construction projects are not completed according to specification, a Registrant may incur liabilities and suffer reduced plant efficiency, higher operating costs, and reduced net income. Furthermore, construction delays associated with renewable projects could result in the loss of otherwise available tax credits and incentives.

Even if a construction project (including a joint venture construction project) is completed, the total costs may be higher than estimated and may not be recoverable through regulated rates, if applicable. In addition, construction delays and contractor performance shortfalls can result in the loss of revenues. The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4. Southern Company and Georgia Power recorded total pre-tax charges to income of $3.1 billion ($2.3 billion after tax) through December 31, 2021 to reflect Georgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 herein for information regarding Plant Vogtle Units 3 and 4. Also see Note 2 to the financial statements under "Alabama Power – Certificates of Convenience and Necessity" in Item 8 herein for information regarding Alabama Power's construction of Plant Barry Unit 8.

Once facilities become operational, ongoing capital expenditures are required to maintain reliable levels of operation. Significant portions of the traditional electric operating companies' existing facilities were constructed many years ago. Older equipment, even if maintained in accordance with good engineering practices, may require significant expenditures to maintain

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efficiency, to comply with changing environmental requirements, to provide safe and reliable operations, and/or to meet related retirement obligations.

FINANCIAL, ECONOMIC, AND MARKET RISKS

The electric generation and energy marketing operations of the traditional electric operating companies and Southern Power and the natural gas operations of Southern Company Gas are subject to changes in energy prices and fuel costs.

The generation, energy marketing, and natural gas operations of the Southern Company system are subject to changes in energy prices and fuel costs, which could increase the cost of producing power, decrease the amount received from the sale of energy, and/or make electric generating facilities less competitive. The market prices for these commodities may fluctuate significantly over relatively short periods of time as a result of changes in supply and/or demand, which could increase the expenses and/or reduce the revenues of the Registrants. For the traditional electric operating companies and Southern Company Gas' regulated gas distribution operations, such impacts may not be fully recoverable through rates.

The traditional electric operating companies and Southern Company Gas from time to time have experienced and may continue to experience underrecovered fuel and/or purchased gas cost balances. While the traditional electric operating companies and Southern Company Gas are generally authorized to recover fuel and/or purchased gas costs through cost recovery clauses, recovery may be delayed or may be denied if costs are deemed to be imprudently incurred.

The Registrants are subject to risks associated with a changing economic environment, customer behaviors, including increased energy conservation, and adoption patterns of technologies by the customers of the Subsidiary Registrants.

The consumption and use of energy are linked to economic activity. This relationship is affected over time by changes in the economy, customer behaviors, and technologies. Any economic downturn could negatively impact customer growth and usage per customer. Additionally, any economic downturn or disruption of financial markets, both nationally and internationally, could negatively affect the financial stability of customers and counterparties of the Subsidiary Registrants.

Outside of economic disruptions, changes in customer behaviors in response to energy efficiency programs, changing conditions and preferences, legislation, or changes in the adoption of technologies could affect the relationship of economic activity to the consumption of energy. For example, some cities in the United States have banned the use of natural gas in new construction.

Both federal and state programs exist to influence how customers use energy, and several of the traditional electric operating companies and natural gas distribution utilities have PSC or other applicable state regulatory agency mandates to promote energy efficiency.

Customers could also voluntarily reduce their consumption of energy in response to decreases in their disposable income, increases in energy prices, or individual conservation efforts.

In addition, the adoption of technology by customers can have both positive and negative impacts on sales. Many new technologies utilize less energy than in the past. However, electric and natural gas technologies such as electric and natural gas vehicles can create additional demand. The Southern Company system uses best available methods and experience to incorporate the effects of changes in customer behavior, state and federal programs, PSC or other applicable state regulatory agency mandates, and technology, but the Southern Company system's planning processes may not accurately estimate and incorporate these effects.

The operating results of the Registrants are affected by weather conditions and may fluctuate on a seasonal basis. In addition, catastrophic events could result in substantial damage to or limit the operation of the properties of a Subsidiary Registrant.

Electric power and natural gas supply are generally seasonal businesses. The Subsidiary Registrants have historically sold less power and natural gas when weather conditions are milder.

Volatile or significant weather events could result in substantial damage to the transmission and distribution lines of the traditional electric operating companies, the generating facilities of the traditional electric operating companies and Southern Power, and the natural gas distribution and storage facilities of Southern Company Gas. The Subsidiary Registrants have significant investments in the Atlantic and Gulf Coast regions and Southern Power and Southern Company Gas have investments in various states which could be subject to severe weather and natural disasters, including hurricanes and wildfires. Further, severe drought conditions can reduce the availability of water and restrict or prevent the operation of certain generating facilities.

In the event a traditional electric operating company or Southern Company Gas experiences any of these weather events or any natural disaster or other catastrophic event, recovery of costs in excess of reserves and insurance coverage is subject to the approval of its state PSC or other applicable state regulatory agency. The traditional electric operating companies from time to

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time have experienced and may continue to experience deficits in their storm cost recovery reserve balances. Additionally, the applicable state PSC or other applicable state regulatory agency may deny or delay recovery of any portion of such costs.

In addition, damages resulting from significant weather events occurring within a Subsidiary Registrant's service territory or otherwise affecting its customers may result in the loss of customers and reduced demand for energy for extended periods and may impact customers' ability to perform under existing PPAs.

Acquisitions, dispositions, or other strategic ventures or investments may not result in anticipated benefits and may present risks, including risks not originally contemplated.

Southern Company and its subsidiaries have made significant acquisitions, dispositions, and investments in the past and may continue to do so. Such actions cannot be assured to be completed or beneficial to Southern Company or its subsidiaries. Southern Company and its subsidiaries continually seek opportunities to create value through various transactions, including acquisitions or sales of assets. Specifically, Southern Power continually seeks opportunities to execute its strategy to create value through various transactions, including acquisitions, dispositions, and sales of partnership interests, development and construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, IPPs, municipalities, and other load-serving entities, as well as commercial and industrial customers. Additionally, Southern Company Gas has made significant investments in existing pipelines, most of which are operated by third parties. If one of these agents fails to perform in a proper manner, the value of the investment could decline and Southern Company Gas could lose part or all of its investment. In addition, Southern Company Gas is required to fulfill capital obligations to pipeline joint ventures.

Southern Company and its subsidiaries may face significant competition for transactional opportunities and anticipated transactions may not be completed on acceptable terms or at all. In addition, these transactions are intended to, but may not, result in the generation of cash or income, the realization of savings, the creation of efficiencies, or the reduction of risk.

These transactions also involve risks, including that they may not result in an increase in income or provide adequate or expected funds or return on capital or other anticipated benefits; they may result in Southern Company or its subsidiaries entering into new or additional lines of business, which may have new or different business or operational risks; they may not be successfully integrated into the acquiring company's operations, internal control processes and/or accounting systems; the due diligence conducted prior to a transaction may not uncover situations that could result in financial or legal exposure or may not appropriately evaluate the likelihood or quantify the exposure from identified risks; they may result in decreased earnings, revenues, or cash flow; they may involve retained obligations in connection with transitional agreements or deferred payments related to dispositions that subject Southern Company or its subsidiaries to additional risk; Southern Company or the applicable subsidiary may not be able to achieve the expected financial benefits from the use of funds generated by any dispositions; expected benefits of a transaction may be dependent on the cooperation, performance, or credit risk of a counterparty; minority investments in growth companies may not result in a positive return on investment; or, for the traditional electric operating companies and Southern Company Gas, costs associated with such investments that were expected to be recovered through regulated rates may not be recoverable.

Southern Company and Southern Company Gas are holding companies and Southern Power owns many of its assets indirectly through subsidiaries. Each of these companies is dependent on cash flows from their respective subsidiaries to meet their ongoing and future financial obligations.

Southern Company and Southern Company Gas are holding companies and, as such, they have no operations of their own. Substantially all of Southern Company's and Southern Company Gas' and many of Southern Power's respective consolidated assets are held by subsidiaries. Southern Company's, Southern Company Gas' and, to a certain extent, Southern Power's ability to meet their respective financial obligations, including making interest and principal payments on outstanding indebtedness, and, for Southern Company, to pay dividends on its common stock, is dependent on the net income and cash flows of their respective subsidiaries and the ability of those subsidiaries to pay upstream dividends or to repay borrowed funds. Prior to funding Southern Company, Southern Company Gas, or Southern Power, the respective subsidiaries have financial obligations and, with respect to Southern Company and Southern Company Gas, regulatory restrictions that must be satisfied, including among others, debt service and preferred stock dividends. In addition, Southern Company, Southern Company Gas, and Southern Power may provide capital contributions or debt financing to subsidiaries under certain circumstances, which would reduce the funds available to meet their respective financial obligations, including making interest and principal payments on outstanding indebtedness, and to pay dividends on Southern Company's common stock.

A downgrade in the credit ratings of any of the Registrants, Southern Company Gas Capital, or Nicor Gas could negatively affect their ability to access capital at reasonable costs and/or could require posting of collateral or replacing certain indebtedness.

There are numerous factors that rating agencies evaluate to arrive at credit ratings for the Registrants, Southern Company Gas Capital, and Nicor Gas, including capital structure, regulatory environment, the ability to cover liquidity requirements, other

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commitments for capital, and certain other controllable and uncontrollable events. The Registrants, Southern Company Gas Capital, and Nicor Gas could experience a downgrade in their ratings if any rating agency concludes that the level of business or financial risk of the industry or the applicable company has deteriorated. Changes in ratings methodologies by the agencies could also have a negative impact on credit ratings. If one or more rating agencies downgrade any Registrant, Southern Company Gas Capital, or Nicor Gas, borrowing costs likely would increase, including potential automatic increases in interest rates under applicable term loans and credit facilities, the pool of investors and funding sources would likely decrease, and, particularly for any downgrade to below investment grade, significant collateral requirements may be triggered in a number of contracts. Any credit rating downgrades could require altering the mix of debt financing currently used and could require the issuance of secured indebtedness and/or indebtedness with additional restrictive covenants binding the applicable company.

Uncertainty in demand for energy can result in lower earnings or higher costs.

The traditional electric operating companies and Southern Power each engage in a long-term planning process to estimate the optimal mix and timing of new generation assets required to serve future load obligations. Southern Company Gas engages in a long-term planning process to estimate the optimal mix and timing of building new pipelines and storage facilities, replacing existing pipelines, rewatering storage facilities, and entering new markets and/or expanding in existing markets. These planning processes must project many years into the future to accommodate the long lead times associated with the permitting and construction of new generation and associated transmission facilities and natural gas distribution and storage facilities. Inherent risk exists in predicting demand as future loads are dependent on many uncertain factors, including economic conditions, customer usage patterns, efficiency programs, customer technology adoption, and the duration and extent of the COVID-19 pandemic. Because regulators may not permit the traditional electric operating companies or the natural gas distribution utilities to adjust rates to recover the costs of new generation and associated transmission assets and/or new pipelines and related infrastructure in a timely manner or at all, these subsidiaries may not be able to fully recover these costs or may have exposure to regulatory lag associated with the time between the incurrence of costs and the recovery in customers' rates. In addition, under Southern Power's model of selling capacity and energy at negotiated market-based rates under long-term PPAs, Southern Power might not be able to fully execute its business plan if market prices drop below original forecasts. Southern Power and/or the traditional electric operating companies may not be able to extend or replace existing PPAs upon expiration, or they may be forced to market these assets at prices lower than originally intended.

The traditional electric operating companies are currently obligated to supply power to retail customers and wholesale customers under long-term PPAs. Southern Power is currently obligated to supply power to wholesale customers under long-term PPAs. At peak times, the demand for power required to meet this obligation could exceed the Southern Company system's available generation capacity. Market or competitive forces may require that the traditional electric operating companies purchase capacity in the open market or build additional generation and transmission facilities and that Southern Power purchase energy or capacity in the open market. Because regulators may not permit the traditional electric operating companies to pass all of these purchase or construction costs on to their customers, the traditional electric operating companies may not be able to recover some or all of these costs or may have exposure to regulatory lag associated with the time between the incurrence of costs of purchased or constructed capacity and the traditional electric operating companies' recovery in customers' rates. Under Southern Power's long-term fixed price PPAs, Southern Power may not be able to recover all of these costs.

The businesses of the Registrants and Nicor Gas are dependent on their ability to successfully access capital through capital markets and financial institutions.

The Registrants and Nicor Gas rely on access to both short-term money markets and longer-term capital markets as a significant source of liquidity to meet capital requirements not satisfied by the cash flow from their respective operations. If any of the Registrants or Nicor Gas is not able to access capital at competitive rates or on favorable terms, its ability to implement its business plan will be limited due to weakened capacity to fund capital investments or acquisitions that it may otherwise rely on to achieve future earnings and cash flows. In addition, the Registrants and Nicor Gas rely on committed credit facilities as back-up liquidity for access to low cost money markets. Certain market disruptions, including an economic downturn or uncertainty, bankruptcy or financial distress at an unrelated utility company, financial institution, or sovereign entity, capital markets volatility and disruption, either nationally or internationally, changes in tax policy, volatility in market prices for electricity and natural gas, actual or threatened cyber or physical attacks on facilities within the Southern Company system or owned by unrelated utility companies, future impacts of the COVID-19 pandemic or other pandemic health events, war or threat of war, or the overall health of the utility and financial institution industries, may increase the cost of borrowing or adversely affect the ability to raise capital through the issuance of securities or other borrowing arrangements or the ability to secure committed bank lending agreements used as back-up sources of capital. Furthermore, some financial institutions may be limited in their ability to provide capital to the Registrants as a result of such financial institution's investment criteria, including criteria related to GHG.

Additionally, due to a portion of the Registrants' and Southern Company Gas Capital's indebtedness bearing interest at variable rates based on LIBOR or other floating benchmark rates, the announced phasing out of these rates may adversely affect the

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costs of financing. The discontinuation, reform, or replacement of LIBOR or any other benchmark rates may have an unpredictable impact on contractual relationships in the credit markets or cause disruption to the broader financial markets and could result in adverse consequences to the return on, value of, and market for the Registrants' and Southern Company Gas Capital's securities and other instruments whose returns are linked to any such benchmark. Additionally, any replacement benchmark rates may be relatively new, be fundamentally different from LIBOR, and be more volatile than other benchmark or market rates. The Secured Overnight Financing Rate has been identified as the current replacement benchmark rate for LIBOR in the United States. Uncertainty as to the nature of the phase-out of LIBOR and alternative reference rates or disruption in the financial markets could cause interest rates to increase. If sources of capital for the Registrants or Nicor Gas are reduced, capital costs could increase materially.

Failure to comply with debt covenants or conditions could adversely affect the ability of the Registrants, SEGCO, Southern Company Gas Capital, or Nicor Gas to execute future borrowings.

The debt and credit agreements of the Registrants, SEGCO, Southern Company Gas Capital, and Nicor Gas contain various financial and other covenants. Georgia Power's loan guarantee agreement with the DOE contains additional covenants, events of default, and mandatory prepayment events relating to the construction of Plant Vogtle Units 3 and 4. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements.

Volatility in the securities markets, interest rates, and other factors could substantially increase defined benefit pension and other postretirement plan costs and the funding available for nuclear decommissioning.

The costs of providing pension and other postretirement benefit plans are dependent on a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plan, changes in actuarial assumptions, government regulations, and/or life expectancy, and the frequency and amount of the Southern Company system's required or voluntary contributions made to the plans. Changes in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline in the value of investments that fund the pension and other postretirement plans, if not offset or mitigated by a decline in plan liabilities, could increase pension and other postretirement expense, and the Southern Company system could be required from time to time to fund the pension plans with significant amounts of cash. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Pension and Other Postretirement Benefits" in Item 7 herein and Note 11 to the financial statements in Item 8 herein for additional information regarding the defined benefit pension and other postretirement plans. Additionally, Alabama Power and Georgia Power each hold significant assets in their nuclear decommissioning trusts to satisfy obligations to decommission their nuclear plants. The rate of return on assets held in those trusts can significantly impact both the funding available for decommissioning and the funding requirements for the trusts. See Note 6 to the financial statements under "Nuclear Decommissioning" in Item 8 herein for additional information.

The Registrants are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.

The financial condition of some insurance companies, actual or threatened physical or cyber attacks, natural disasters, and an increased focus on climate issues, among other things, could have disruptive effects on insurance markets. The availability of insurance may decrease, and the insurance that the Registrants are able to obtain may have higher deductibles, higher premiums, and more restrictive policy terms. Further, the insurance policies may not cover all of the potential exposures or the actual amount of loss incurred.

The use of derivative contracts by Southern Company and its subsidiaries in the normal course of business could result in financial losses that negatively impact the net income of the Registrants or in reported net income volatility.

Southern Company and its subsidiaries use derivative instruments, such as swaps, options, futures, and forwards, to manage their commodity and interest rate exposures and, to a lesser extent, manage foreign currency exchange rate exposure and engage in limited trading activities. The Registrants could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform. These risks are managed through risk management policies, limits, and procedures, which might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, derivative contracts entered into for hedging purposes might not offset the underlying exposure being hedged as expected, resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management's judgment or use of estimates. The factors used in the valuation of these instruments become more difficult to predict and the calculations become less reliable further into the future. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

See Notes 13 and 14 to the financial statements in Item 8 herein for additional information.

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Future impairments of goodwill or long-lived assets could have a material adverse effect on the Registrants' results of operations.

Goodwill is assessed for impairment at least annually and more frequently if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value and long-lived assets are assessed for impairment whenever events or circumstances indicate that an asset's carrying amount may not be recoverable. At December 31, 2021, goodwill was $5.3 billion and $5.0 billion for Southern Company and Southern Company Gas, respectively.

In addition, Southern Company and its subsidiaries have long-lived assets recorded on their balance sheets. To the extent the value of goodwill or long-lived assets become impaired, the affected Registrant may be required to incur impairment charges that could have a material impact on their results of operations. See Notes 7, 9, and 15 to the financial statements in Item 8 herein for information regarding certain impairment charges at Southern Company and Southern Company Gas.

Item 1B.UNRESOLVED STAFF COMMENTS.

None.

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Item 2. PROPERTIES

Electric

The traditional electric operating companies, Southern Power, and SEGCO, at December 31, 2021, owned and/or operated 30 hydroelectric generating stations, 24 fossil fuel generating stations, three nuclear generating stations, 13 combined cycle/cogeneration stations, 45 solar facilities, 15 wind facilities, one fuel cell facility, and four battery storage facilities. The amounts of capacity for each company at December 31, 2021 are shown in the table below. The traditional electric operating companies have certain jointly-owned generating stations. For these facilities, the nameplate capacity shown represents the Registrant's portion of total plant capacity, with ownership percentages provided if less than 100%. See "Jointly-Owned Facilities" and "Titles to Property" herein and Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information.


Generating Station/Ownership Percentage	Location	Nameplate Capacity
		(KWs)
FOSSIL STEAM
Gadsden	Gadsden, AL	120,000
Barry	Mobile, AL	1,300,000
Greene County (60%)	Demopolis, AL	300,000
Gaston Unit 5	Wilsonville, AL	880,000
Miller (95.92%)	Birmingham, AL	2,532,288
Alabama Power Total		5,132,288
Bowen	Cartersville, GA	3,160,000
Scherer (8.4% of Units 1 and 2 and 75% of Unit 3)	Macon, GA	750,924
Wansley (53.5%)	Carrollton, GA	925,550
Yates	Newnan, GA	700,000
Georgia Power Total		5,536,474
Daniel (50%)	Pascagoula, MS	500,000
Greene County (40%)	Demopolis, AL	200,000
Watson	Gulfport, MS	750,000
Mississippi Power Total		1,450,000
Gaston Units 1-4	Wilsonville, AL
SEGCO Total		1,000,000	(a)
Total Fossil Steam		13,118,762
NUCLEAR STEAM
Farley	Dothan, AL
Alabama Power Total		1,720,000
Hatch (50.1%)	Baxley, GA	899,612
Vogtle Units 1 and 2 (45.7%)	Augusta, GA	1,060,240
Georgia Power Total		1,959,852
Total Nuclear Steam		3,679,852

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Generating Station/Ownership Percentage	Location	Nameplate Capacity
COMBUSTION TURBINES
Greene County	Demopolis, AL
Alabama Power Total		720,000
Boulevard	Savannah, GA	19,700
McDonough Unit 3	Atlanta, GA	78,800
McIntosh Units 1 through 8	Effingham County, GA	640,000
McManus	Brunswick, GA	481,700
Robins	Warner Robins, GA	158,400
Wansley (53.5%)	Carrollton, GA	26,322
Wilson	Augusta, GA	354,100
Georgia Power Total		1,759,022
Sweatt	Meridian, MS	39,400
Watson	Gulfport, MS	39,360
Mississippi Power Total		78,760
Addison	Thomaston, GA	668,800
Cleveland County	Cleveland County, NC	720,000
Dahlberg	Jackson County, GA	756,000
Rowan	Salisbury, NC	455,250
Southern Power Total		2,600,050
Gaston (SEGCO)	Wilsonville, AL	19,680	(a)
Total Combustion Turbines		5,177,512
COGENERATION
Washington County	Washington County, AL	123,428
Lowndes County	Burkeville, AL	104,800
Theodore	Theodore, AL	236,418
Alabama Power Total		464,646
Chevron Cogenerating Station	Pascagoula, MS	147,292	(b)
Mississippi Power Total		147,292
Total Cogeneration		611,938
COMBINED CYCLE
Barry	Mobile, AL	1,070,424
Central Alabama Generating Station	Autauga County, AL	885,000
Alabama Power Total		1,955,424
McIntosh Units 10 and 11	Effingham County, GA	1,318,920
McDonough-Atkinson Units 4 through 6	Atlanta, GA	2,520,000
Georgia Power Total		3,838,920
Daniel	Pascagoula, MS	1,070,424
Ratcliffe	Kemper County, MS	769,898
Mississippi Power Total		1,840,322
Franklin	Smiths, AL	1,857,820
Harris	Autaugaville, AL	1,318,920
Rowan	Salisbury, NC	530,550
Wansley Units 6 and 7	Carrollton, GA	1,073,000
Southern Power Total		4,780,290
Total Combined Cycle		12,414,956

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Generating Station/Ownership Percentage	Location	Nameplate Capacity
HYDROELECTRIC FACILITIES
Bankhead	Holt, AL	53,985
Bouldin	Wetumpka, AL	225,000
Harris	Wedowee, AL	132,000
Henry	Ohatchee, AL	72,900
Holt	Holt, AL	46,944
Jordan	Wetumpka, AL	100,000
Lay	Clanton, AL	177,000
Lewis Smith	Jasper, AL	157,500
Logan Martin	Vincent, AL	135,000
Martin	Dadeville, AL	182,000
Mitchell	Verbena, AL	170,000
Thurlow	Tallassee, AL	81,000
Weiss	Leesburg, AL	87,750
Yates	Tallassee, AL	47,000
Alabama Power Total		1,668,079
Bartletts Ferry	Columbus, GA	173,000
Burton	Clayton, GA	6,120
Flint River	Albany, GA	5,400
Goat Rock	Columbus, GA	38,600
Lloyd Shoals	Jackson, GA	14,400
Morgan Falls	Atlanta, GA	16,800
Nacoochee	Lakemont, GA	4,800
North Highlands	Columbus, GA	29,600
Oliver Dam	Columbus, GA	60,000
Rocky Mountain (25.4%)	Rome, GA	229,362	(c)
Sinclair Dam	Milledgeville, GA	45,000
Tallulah Falls	Clayton, GA	72,000
Terrora	Clayton, GA	16,000
Tugalo	Clayton, GA	45,000
Wallace Dam	Eatonton, GA	321,300
Yonah	Toccoa, GA	22,500
Georgia Power Total		1,099,882
Total Hydroelectric Facilities		2,767,961

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Generating Station/Ownership Percentage	Location	Nameplate Capacity
SOLAR FACILITIES
Fort Rucker	Calhoun County, AL	10,560
Anniston Army Depot	Dale County, AL	7,380
Alabama Power Total		17,940
Fort Benning	Columbus, GA	30,005
Fort Gordon	Augusta, GA	30,000
Fort Stewart	Fort Stewart, GA	30,000
Kings Bay	Camden County, GA	30,161
Marine Corps Logistics Base	Albany, GA	31,161
Moody Air Force Base	Valdosta, GA	49,500
Robins Air Force Base	Warner Robins, GA	128,000
8 Other Plants	Various Georgia locations	18,479
Georgia Power Total		347,306
Adobe	Kern County, CA	20,000
Apex	North Las Vegas, NV	20,000
Boulder I	Clark County, NV	100,000
Butler	Taylor County, GA	104,000
Butler Solar Farm	Taylor County, GA	22,000
Calipatria	Imperial County, CA	20,000
Campo Verde	Imperial County, CA	147,420
Cimarron	Springer, NM	30,640
Decatur County	Decatur County, GA	20,000
Decatur Parkway	Decatur County, GA	84,000
Desert Stateline	San Bernadino County, CA	299,990
East Pecos	Pecos County, TX	120,000
Garland	Kern County, CA	205,290
Gaskell West I	Kern County, CA	20,000
Granville	Oxford, NC	2,500
Henrietta	Kings County, CA	102,000
Imperial Valley	Imperial County, CA	163,200
Lamesa	Dawson County, TX	102,000
Lost Hills Blackwell	Kern County, CA	32,000
Macho Springs	Luna County, NM	55,000
Morelos del Sol	Kern County, CA	15,000
North Star	Fresno County, CA	61,600
Pawpaw	Taylor County, GA	30,480
Roserock	Pecos County, TX	160,000
Rutherford	Rutherford County, NC	74,800
Sandhills	Taylor County, GA	148,000
Spectrum	Clark County, NV	30,240
Tranquillity	Fresno County, CA	205,300
Southern Power Total		2,395,460	(d)
Total Solar		2,760,706

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Generating Station/Ownership Percentage	Location	Nameplate Capacity
WIND FACILITIES
Beech Ridge II	Greenbrier County, WV	56,200
Bethel	Castro County, TX	276,000
Cactus Flats	Concho County, TX	148,350
Deuel Harvest	Deuel County, SD	301,100
Glass Sands	Murray County, OK	118,300
Grant Plains	Grant County, OK	147,200
Grant Wind	Grant County, OK	151,800
Kay Wind	Kay County, OK	299,000
Passadumkeag	Penobscot County, ME	42,900
Reading	Osage & Lyon Counties, KS	200,100
Salt Fork	Donley & Gray Counties TX	174,000
Skookumchuck	Lewis & Thurston Counties, WA	136,800
Tyler Bluff	Cooke County, TX	125,580
Wake Wind	Crosby & Floyd Counties, TX	257,250
Wildhorse Mountain	Pushmataha County, OK	100,000
Southern Power Total		2,534,580	(e)
FUEL CELL FACILITY
Red Lion and Brookside	New Castle and Newark, DE	27,500	(f)
Southern Power Total		27,500
BATTERY STORAGE FACILITIES
Garland	Kern County, CA	73,000	(g)(j)
Milliken	Orange County, CA	2,000	(h)
Tranquillity	Fresno County, CA	32,000	(i)(j)
Wildcat	Palm Springs, CA	1,500	(h)
Southern Power Total		108,500

Total Alabama Power Generating Capacity		11,678,377
Total Georgia Power Generating Capacity		14,541,456
Total Mississippi Power Generating Capacity		3,516,374
Total Southern Power Generating Capacity		12,446,380
Total Generating Capacity		43,202,267

(a)Alabama Power and Georgia Power each own 50% of the outstanding common stock of SEGCO, an operating public utility company. Alabama Power and Georgia Power are each entitled to one-half of SEGCO's capacity and energy. Alabama Power acts as SEGCO's agent in the operation of SEGCO's units and furnishes fuel to SEGCO for its units. See Note 7 to the financial statements under "SEGCO" in Item 8 herein for additional information.

(b)Generation is dedicated to a single industrial customer. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" in Item 7 herein.

(c)Operated by OPC.

(d)Southern Power owns a 67% equity interest in SP Solar (a limited partnership indirectly owning all of Southern Power's solar facilities, except the Roserock and Gaskell West I solar facilities). SP Solar is the 51% majority owner of Boulder I, Garland, Henrietta, Imperial Valley, Lost Hills Blackwell, North Star, and Tranquillity solar facilities; the 66% majority owner of Desert Stateline solar facility; and the sole owner of the remaining SP Solar solar facilities. Southern Power owns 100% of Roserock and is also the controlling partner in a tax equity partnership owning Gaskell West I. All of these entities are consolidated subsidiaries of Southern Power and the capacity shown in the table is 100% of the nameplate capacity for the respective facility.

(e)Southern Power is the controlling member in SP Wind (a tax equity entity owning eight of Southern Power's wind facilities). SP Wind is the 90.1% majority owner of Wake Wind and owns 100% of the remaining SP Wind facilities. Southern Power is the controlling partner in other tax equity partnerships owning Cactus Flats, Wildhorse Mountain, Reading, Skookumchuck, and Deuel Harvest (additionally for Skookumchuck and Deuel Harvest, a noncontrolling interest in Southern Power's remaining equity is owned by another partner). Southern Power owns 100% of Glass Sands and is also the controlling member in a non-tax equity partnership for Beech Ridge II. All of these entities are consolidated subsidiaries of Southern Power and the capacity shown in the table is 100% of the nameplate capacity for the respective facility.

(f)Southern Power has two noncontrolling interest partners that own approximately 10 MWs of the facility.

(g)The facility has a total nameplate 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.

(h)Southern Power has an equity method investment in the facility as the Class A member.

(i)The facility has a total nameplate capacity of 72 MWs, of which 32 MWs were placed in service during 2021 and the remaining MWs are expected to be placed in service later in the first quarter 2022.

(j)Southern Power is the controlling partner in a tax equity partnership owning the Garland and Tranquillity battery energy storage facilities. Additionally, the noncontrolling interests in Southern Power's remaining equity are owned by two other partners and the facilities are indirect subsidiaries of SP Solar.

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See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" in Item 7 herein and Note 2 to the financial statements under "Georgia Power – Integrated Resource Plan" and "Mississippi Power – Integrated Resource Plan" in Item 8 herein for information regarding plans to retire or convert to natural gas certain coal-fired generating capacity included in the table above.

Except as discussed below under "Titles to Property," the principal plants and other important units of the traditional electric operating companies, Southern Power, and SEGCO are owned in fee by the respective companies. It is the opinion of management of each such company that its operating properties are adequately maintained and are substantially in good operating condition, and suitable for their intended purpose.

Mississippi Power owns a 79-mile length of 500-kilovolt transmission line which is leased to Entergy Gulf States Louisiana, LLC. The line extends from Plant Daniel to the Louisiana state line. Entergy Gulf States Louisiana, LLC is paying a use fee through 2024 covering all expenses and the amortization of the original cost. At December 31, 2021, the unamortized portion was approximately $5 million.

Mississippi Power owns a lignite mine that was intended to provide fuel for the Kemper IGCC. Liberty Fuels Company, LLC, the operator of the mine, has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. 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. See Note 3 to the financial statements under "Other Matters – Mississippi Power – Kemper County Energy Facility" in Item 8 herein for additional information.

In conjunction with Southern Company's sale of Gulf Power, 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. See Note 3 to the financial statements under "Other Matters – Mississippi Power – Plant Daniel" in Item 8 herein for additional information.

In 2021, the maximum demand on the traditional electric operating companies, Southern Power Company, and SEGCO was 33,373,000 KWs and occurred on July 29, 2021. The all-time maximum demand of 38,777,000 KWs on the traditional electric operating companies (including Gulf Power), Southern Power Company, and SEGCO occurred on August 22, 2007. These amounts exclude demand served by capacity retained by MEAG Power, OPC, and SEPA. The reserve margin for the traditional electric operating companies, Southern Power Company, and SEGCO in 2021 was 36%.

Jointly-Owned Facilities

Alabama Power, Georgia Power, and Mississippi Power at December 31, 2021 had undivided interests in certain generating plants and other related facilities with non-affiliated parties. The percentages of ownership of the total plant or facility are as follows:


		Percentage Ownership
	Total Capacity	Alabama Power		Power South		Georgia Power		Mississippi Power		OPC		MEAG Power		Dalton		Gulf Power
	(MWs)
Plant Miller Units 1 and 2	1,320	91.8	%	8.2	%	—	%	—	%	—	%	—	%	—	%	—	%
Plant Hatch	1,796	—		—		50.1		—		30.0		17.7		2.2		—
Plant Vogtle Units 1 and 2	2,320	—		—		45.7		—		30.0		22.7		1.6		—
Plant Scherer Units 1 and 2	1,636	—		—		8.4		—		60.0		30.2		1.4		—
Plant Scherer Unit 3	818	—		—		75.0		—		—		—		—		25.0
Plant Wansley	1,779	—		—		53.5		—		30.0		15.1		1.4		—
Rocky Mountain	903	—		—		25.4		—		74.6		—		—		—
Plant Daniel Units 1 and 2	1,000	—		—		—		50.0		—		—		—		50.0

Alabama Power, Georgia Power, and Mississippi Power have contracted to operate and maintain the respective units in which each has an interest (other than Rocky Mountain) as agent for the joint owners. Southern Nuclear operates and provides services to Alabama Power's and Georgia Power's nuclear plants.

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In addition, Georgia Power has commitments, in the form of capacity purchases totaling $42 million, 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. See Note 3 to the financial statements under "Commitments" in Item 8 herein for additional information.

Construction continues on Plant Vogtle Units 3 and 4, which are jointly owned by the Vogtle Owners (with each owner holding the same undivided ownership interest as shown in the table above with respect to Plant Vogtle Units 1 and 2). See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 herein.

Titles to Property

The traditional electric operating companies', Southern Power's, and SEGCO's interests in the principal plants and other important units of the respective companies are owned in fee by such companies, subject to the following major encumbrances: (1) a leasehold interest granted by Mississippi Power's largest retail customer, Chevron Products Company (Chevron), at the Chevron refinery, where five combustion turbines owned by Mississippi Power are located and used for co-generation, as well as liens on these assets pursuant to the related co-generation agreements and (2) liens associated with Georgia Power's reimbursement obligations to the DOE under its loan guarantee, which are secured by a first priority lien on (a) Georgia Power's undivided ownership interest in Plant Vogtle Units 3 and 4 and (b) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. See Note 5 to the financial statements under "Assets Subject to Lien" and Note 8 to the financial statements under "Long-term Debt" in Item 8 herein for additional information. The traditional electric operating companies own the fee interests in certain of their principal plants as tenants in common. See "Jointly-Owned Facilities" herein and Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information. Properties such as electric transmission and distribution lines, steam heating mains, and gas pipelines are constructed principally on rights-of-way, which are maintained under franchise or are held by easement only. A substantial portion of lands submerged by reservoirs is held under flood right easements. In addition, certain of the renewable generating facilities occupy or use real property that is not owned, primarily through various leases, easements, rights-of-way, permits, or licenses from private landowners or governmental entities.

Natural Gas

Southern Company Gas considers its properties to be adequately maintained, substantially in good operating condition, and suitable for their intended purpose. The following sections provide the location and general character of the materially important properties that are used by the segments of Southern Company Gas. Substantially all of Nicor Gas' properties are subject to the lien of the indenture securing its first mortgage bonds. See Note 8 to the financial statements in Item 8 herein for additional information.

Distribution and Transmission Mains

Southern Company Gas' distribution systems transport natural gas from its pipeline suppliers to customers in its service areas. These systems consist primarily of distribution and transmission mains, compressor stations, peak shaving/storage plants, service lines, meters, and regulators. At December 31, 2021, Southern Company Gas' gas distribution operations segment owned 76,289 miles of underground distribution and transmission mains, which are located on easements or rights-of-way that generally provide for perpetual use.

Storage Assets

Gas Distribution Operations

Southern Company Gas owns and operates eight underground natural gas storage fields in Illinois with a total working capacity of approximately 150 Bcf, approximately 135 Bcf of which is usually cycled on an annual basis. This system is designed to meet about 50% of the estimated peak-day deliveries and approximately 40% of the normal winter deliveries in Illinois. This level of storage capability provides Nicor Gas with supply flexibility, improves the reliability of deliveries, and helps mitigate the risk associated with seasonal price movements.

Southern Company Gas also has four LNG plants located in Georgia and Tennessee with total LNG storage capacity of approximately 7.0 Bcf. In addition, Southern Company Gas owns two propane storage facilities in Virginia, each with storage capacity of approximately 0.3 Bcf. The LNG plants and propane storage facility are used by Southern Company Gas' gas distribution operations segment to supplement natural gas supply during peak usage periods.

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All Other

Southern Company Gas subsidiaries own two high-deliverability natural gas storage and hub facilities that are included in the all other segment. Golden Triangle Storage, Inc. operates a storage facility in Texas consisting of two salt dome caverns. Central Valley Gas Storage, LLC operates a depleted field storage facility in California.

Jointly-Owned Properties

Southern Company Gas' gas pipeline investments segment has a 50% undivided ownership interest in a 115-mile pipeline facility in northwest Georgia that was placed in service in 2017. Southern Company Gas also has an agreement to lease its 50% undivided ownership in the pipeline facility. See Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information.

Item 3.LEGAL PROCEEDINGS

See Note 3 to the financial statements in Item 8 herein for descriptions of legal and administrative proceedings discussed therein. The Registrants' threshold for disclosing material environmental legal proceedings involving a governmental authority where potential monetary sanctions are involved is $1 million.

Item 4.MINE SAFETY DISCLOSURES

Not applicable.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS – SOUTHERN COMPANY

(Identification of executive officers of Southern Company is inserted in Part I in accordance with Regulation S-K, Item 401) The ages of the officers set forth below are as of December 31, 2021.

Thomas A. Fanning

Chairman, President, and Chief Executive Officer

Age 64

First elected in 2003. Chairman and Chief Executive Officer since December 2010 and President since August 2010.

Daniel S. Tucker

Executive Vice President and Chief Financial Officer

Age 51

First elected in 2021. Executive Vice President and Chief Financial Officer since September 2021. Previously served as Executive Vice President, Chief Financial Officer, and Treasurer of Georgia Power from January 2021 to September 2021, Executive Vice President and Chief Financial Officer of Southern Company Gas from January 2019 to January 2021, and Treasurer of Southern Company and Senior Vice President and Treasurer of SCS from October 2015 to January 2019.

Bryan D. Anderson

Executive Vice President

Age 55

First elected in 2020. Executive Vice President and President of External Affairs since January 2021. Executive Vice President of SCS since November 2020. Previously served as Senior Vice President of SCS with responsibility for governmental affairs from January 2015 to November 2020.

Stanley W. Connally, Jr.

Executive Vice President of SCS

Age 52

First elected in 2012. Executive Vice President for Operations of SCS since June 2018. Previously served as President, Chief Executive Officer, and Director of Gulf Power from July 2012 through December 2018 and Chairman of Gulf Power's Board of Directors from July 2015 through December 2018.

Mark A. Crosswhite

Chairman, President and Chief Executive Officer of Alabama Power

Age 59

First elected in 2011. President, Chief Executive Officer, and Director of Alabama Power since March 2014. Chairman of Alabama Power's Board of Directors since May 2014.

Christopher Cummiskey

Executive Vice President

Age 47

First elected in 2021. Executive Vice President since January 2021. Chairman of Southern Power since February 2021 and Executive Vice President of SCS, Chief Executive Officer of Southern Power, and President and Chief Executive Officer of Southern PowerSecure Holdings, Inc. and Southern Holdings since July 2020. Previously served as Executive Vice President, External Affairs of Georgia Power from May 2015 to June 2020.

Martin B. Davis

Executive Vice President and Chief Information Officer

Age 58

First elected in 2021. Executive Vice President since April 2021. Chief Information Officer and Executive Vice President of SCS since July 2015. Previously served as Vice President from July 2015 through April 2021.

Kimberly S. Greene

Chairman, President, and Chief Executive Officer of Southern Company Gas

Age 55

First elected in 2013. Chairman, President, and Chief Executive Officer of Southern Company Gas since June 2018. Director of Southern Company Gas since July 2016. Previously served as Executive Vice President and Chief Operating Officer of Southern Company from March 2014 through June 2018.

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James Y. Kerr II

Executive Vice President, Chief Legal Officer, and Chief Compliance Officer

Age 57

First elected in 2014. Executive Vice President, Chief Legal Officer (formerly known as General Counsel), and Chief Compliance Officer since March 2014.

Stephen E. Kuczynski

Chairman, President, and Chief Executive Officer of Southern Nuclear

Age 59

First elected in 2011. Chairman, President, and Chief Executive Officer of Southern Nuclear since July 2011.

Anthony L. Wilson

Chairman, President, and Chief Executive Officer of Mississippi Power

Age 57

First elected in 2015. President of Mississippi Power since October 2015 and Chief Executive Officer and Director since January 2016. Chairman of Mississippi Power's Board of Directors since August 2016.

Christopher C. Womack

Chairman, President, and Chief Executive Officer of Georgia Power

Age 63

First elected in 2008. Chairman and Chief Executive Officer of Georgia Power since June 2021 and President of Georgia Power since November 2020. Previously served as Executive Vice President and President of External Affairs of Southern Company from January 2009 to October 2020.

The officers of Southern Company were elected pursuant to a written consent in lieu of a meeting of the directors following the last annual meeting of stockholders held on May 26, 2021 for a term of one year or until their successors are elected and have qualified, except for Mr. Tucker, whose election as Executive Vice President and Chief Financial Officer of Southern Company was effective September 1, 2021.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS – ALABAMA POWER

(Identification of executive officers of Alabama Power is inserted in Part I in accordance with Regulation S-K, Item 401.) The ages of the officers set forth below are as of December 31, 2021.

Mark A. Crosswhite

Chairman, President, and Chief Executive Officer

Age 59

First elected in 2014. President, Chief Executive Officer, and Director since March 1, 2014. Chairman since May 2014.

J. Jeffrey Peoples

Executive Vice President

Age 62

First elected in 2020. Executive Vice President of Customer and Employee Services since June 2020. Previously served as Senior Vice President of Employee Services and Labor Relations from June 2018 to June 2020 and as Vice President of Human Resources from December 2015 to June 2018.

Philip C. Raymond

Executive Vice President, Chief Financial Officer, and Treasurer

Age 62

First elected in 2010. Executive Vice President, Chief Financial Officer, and Treasurer since August 2010.

Zeke W. Smith

Executive Vice President

Age 62

First elected in 2010. Executive Vice President of External Affairs since November 2010.

James P. Heilbron

Senior Vice President and Senior Production Officer

Age 50

First elected in 2013. Senior Vice President and Senior Production Officer of Alabama Power since March 2013 and Senior Vice President and Senior Production Officer – West of SCS and Senior Production Officer of Mississippi Power since October 2018.

R. Scott Moore

Senior Vice President

Age 54

First elected in 2017. Senior Vice President of Power Delivery since May 2017. Previously served as Vice President of Transmission from August 2012 to May 2017.

The officers of Alabama Power were elected at the meeting of the directors held on April 23, 2021 for a term of one year or until their successors are elected and have qualified.

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PART II

Item 5.MARKET FOR REGISTRANTS' COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

(a)(1) The common stock of Southern Company is listed and traded on the NYSE under the ticker symbol SO. The common stock is also traded on regional exchanges across the U.S.

There is no market for the other Registrants' common stock, all of which is owned by Southern Company.

(a)(2) Number of Southern Company's common stockholders of record at January 31, 2022: 103,154

Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $2.62 in 2021 and $2.54 in 2020. In January 2022, Southern Company declared a quarterly dividend of 66 cents per share. Dividends on Southern Company's common stock are payable at the discretion of Southern Company's Board of Directors and depend upon earnings, financial condition, and other factors. See Note 8 to the financial statements under "Dividend Restrictions" in Item 8 herein for additional information.

Each of the other Registrants have one common stockholder, Southern Company.

(a)(3) Securities authorized for issuance under equity compensation plans.

See Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

(b) Use of Proceeds

Not applicable.

None.

Item 6.RESERVED

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Item 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS


			Page
Combined Management's Discussion and Analysis of Financial Condition and Results of Operations
Overview			II-3
Results of Operations			II-8
Southern Company			II-8
Alabama Power			II-18
Georgia Power			II-22
Mississippi Power			II-27
Southern Power			II-31
Southern Company Gas			II-34
Future Earnings Potential			II-39
Accounting Policies			II-47
Financial Condition and Liquidity			II-55

This section generally discusses 2021 and 2020 items and year-to-year comparisons between 2021 and 2020. Discussions of 2019 items and year-to-year comparisons between 2020 and 2019 that are not included in this Annual Report on Form 10-K can be found in Item 7 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2020, which was filed with the SEC on February 17, 2021. The following Management's Discussion and Analysis of Financial Condition and Results of Operations is a combined presentation; however, information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf and each Registrant makes no representation as to information related to the other Registrants.

Item 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" in Item 7 herein and Note 1 to the financial statements under "Financial Instruments" in Item 8 herein. Also see Notes 13 and 14 to the financial statements in Item 8 herein.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS

Southern Company and Subsidiary Companies 2021 Annual Report

OVERVIEW

Business Activities

Southern Company is a holding company that owns all of the common stock of three traditional electric operating companies, Southern Power, and Southern Company Gas and owns other direct and indirect subsidiaries. The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. Southern Company's reportable segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. See Note 16 to the financial statements for additional information.

•The traditional electric operating companies – Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service to retail customers in three Southeastern states in addition to wholesale customers in the Southeast.

•Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions, dispositions, and sales of partnership interests, development and construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, IPPs, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. In general, Southern Power commits to the construction or acquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities.

•Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas. Southern Company Gas owns natural gas distribution utilities in four states – Illinois, Georgia, Virginia, and Tennessee – and is also involved in several other complementary businesses. Southern Company Gas manages its business through three reportable segments – gas distribution operations, gas pipeline investments, and gas marketing services, which includes SouthStar, a Marketer and provider of energy-related products and services to natural gas markets – and one non-reportable segment, all other. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' reportable segments also included wholesale gas services. See Notes 7, 15, and 16 to the financial statements for additional information.

Southern Company's other business activities include providing distributed energy and resilience solutions and deploying microgrids for commercial, industrial, governmental, and utility customers, as well as investments in telecommunications and gas storage facilities. Management continues to evaluate the contribution of each of these activities to total shareholder return and may pursue acquisitions, dispositions, and other strategic ventures or investments accordingly.

See FUTURE EARNINGS POTENTIAL herein for a discussion of the many factors that could impact the Registrants' future results of operations, financial condition, and liquidity.

Recent Developments

Southern Company

On October 29, 2021, Southern Company completed the sale of assets subject to a domestic leveraged lease to the lessee for $45 million. No gain or loss was recognized on the sale. 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). See Note 15 to the financial statements under "Southern Company" for additional information.

Alabama Power

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 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. The ultimate outcome of this matter cannot be determined at this time.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2021 Annual Report

During 2021, Alabama Power continued construction of Plant Barry Unit 8. At December 31, 2021, associated project expenditures included in CWIP totaled approximately $304 million.

For the year ended December 31, 2021, Alabama Power's weighted common equity return exceeded 6.15%, resulting in Alabama Power establishing a current regulatory liability of $181 million. In accordance with an Alabama PSC order issued on February 1, 2022, Alabama Power will apply $126 million 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 Note 2 to the financial statements under "Alabama Power" for additional information.

Georgia Power

Plant Vogtle Units 3 and 4 Construction and Start-Up Status

Construction continues on Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each), in which Georgia Power holds a 45.7% ownership interest. Georgia Power's share of the total project capital cost forecast 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 $10.4 billion.

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. 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.

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 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" for additional information.

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.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2021 Annual Report

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 in Note 2 to the financial statements under "Georgia Power – Nuclear Construction – Regulatory Matters." In addition, Georgia Power recorded a pre-tax charge to income in the fourth quarter 2021 of approximately $440 million ($328 million after tax), and may be required to record additional pre-tax charges to income of up to $460 million, associated with the cost-sharing and tender provisions of the joint ownership agreements based on the current project capital cost forecast. The incremental costs associated with these provisions will not be recovered from retail customers. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction – Joint Owner Contracts" for additional information.

The ultimate impact of the COVID-19 pandemic and other factors on the construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be determined at this time. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information.

Plant Vogtle Unit 3 and Common Facilities Rate Proceeding

On November 2, 2021, the Georgia PSC approved Georgia Power's application to adjust retail base rates to include a portion of costs related to its investment in Plant Vogtle Unit 3 and the common facilities shared between Plant Vogtle Units 3 and 4 (Common Facilities), as well as the related costs of operation, as modified pursuant to a stipulated agreement between Georgia Power and the staff of the Georgia PSC. The related increase in annual retail base rates of approximately $302 million 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 that became effective January 1, 2022. See Note 2 to the financial statements under "Georgia Power – Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" for additional information.

Rate Plans

On November 18, 2021, in accordance with the terms of the 2019 ARP, the Georgia PSC approved tariff adjustments effective January 1, 2022 resulting in a net increase in annual retail base rates of $157 million. Georgia Power is required to file its next general base rate case by July 1, 2022. See Note 2 to the financial statements under "Georgia Power – Rate Plans – 2019 ARP" for additional information.

Integrated Resource Plan

On January 31, 2022, Georgia Power filed its triennial IRP (2022 IRP), including 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.

In the 2022 IRP, Georgia Power requested approval to reclassify the remaining net book value of Plant Wansley Units 1 and 2 (approximately $611 million at December 31, 2021), Plant Bowen Units 1 and 2 (approximately $937 million at December 31, 2021), and Plant Scherer Unit 3 (approximately $612 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.

The 2022 IRP also included a request for approval of the 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.

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

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2021 Annual Report

Mississippi Power

During the first half of 2021, the Mississippi PSC approved the following non-fuel rate changes related to Mississippi Power's annual rate filings for 2021:

•an increase in revenues related to the ad valorem tax adjustment factor of approximately $28 million annually, which became effective with the first billing cycle of May 2021,

•an increase in revenues related to PEP of approximately $16 million annually, which became effective with the first billing cycle of April 2021 in accordance with the PEP rate schedule, and

•a decrease in revenues related to the ECO Plan of approximately $9 million annually, which became effective with the first billing cycle of July 2021.

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.

In accordance with an accounting order issued by the Mississippi PSC on October 14, 2021, Mississippi Power reclassified $49 million of retail costs associated with Hurricanes Zeta and Ida to a regulatory asset to be recovered through PEP over a period to be determined in Mississippi Power's 2022 PEP proceeding. In addition, 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 to restore the property damage reserve.

On January 18, 2022, the Mississippi PSC approved Mississippi Power's retail fuel cost recovery filing, which requested an increase in revenues of approximately $43 million annually effective with the first billing cycle of February 2022.

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

Southern Power

During 2021, Southern Power completed construction of and placed in service the 118-MW Glass Sands wind facility, 73 MWs of the 88-MW Garland battery energy storage facility, and 32 MWs of the 72-MW Tranquillity battery energy storage facility. Southern Power continues construction of the remainder of the Garland and Tranquillity battery energy storage facilities. On March 26, 2021, Southern Power purchased a controlling membership interest in the 300-MW Deuel Harvest wind facility located in Deuel County, South Dakota from Invenergy Renewables LLC.

See Note 15 to the financial statements under "Southern Power" for additional information.

Southern Company Gas

On April 28, 2021, Atlanta Gas Light filed its first Integrated Capacity and Delivery Plan (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, as well as the required capital investments and related costs to implement the programs. 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.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2021 Annual Report

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.

On November 18, 2021, the Illinois Commission approved a $240 million annual base rate increase for Nicor Gas 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%.

See Note 2 to the financial statements under "Southern Company Gas" for additional information.

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. See Note 15 to the financial statements under "Southern Company Gas" for additional information.

During the second and third quarters of 2021, Southern Company Gas recorded pre-tax impairment charges totaling $84 million ($67 million after tax) related to its equity method investment in the PennEast Pipeline project. 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. See Note 7 to the financial statements under "Southern Company Gas" for additional information.

Key Performance Indicators

In striving to achieve attractive risk-adjusted returns while providing cost-effective energy to approximately 8.7 million electric and gas utility customers collectively, the traditional electric operating companies and Southern Company Gas continue to focus on several key performance indicators. These indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, and execution of major construction projects. In addition, Southern Company and the Subsidiary Registrants focus on earnings per share (EPS) and net income, respectively, as a key performance indicator. See RESULTS OF OPERATIONS herein for information on the Registrants' financial performance. See RESULTS OF OPERATIONS – "Southern Company Gas – Operating Metrics" for additional information on Southern Company Gas' operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold.

The financial success of the traditional electric operating companies and Southern Company Gas is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. The traditional electric operating companies use customer satisfaction surveys to evaluate their results and generally target the top quartile of these surveys in measuring performance. Reliability indicators are also used to evaluate results. See Note 2 to the financial statements under "Alabama Power – Rate RSE" and "Mississippi Power – Performance Evaluation Plan" for additional information on Alabama Power's Rate RSE and Mississippi Power's PEP rate plan, respectively, both of which contain mechanisms that directly tie customer service indicators to the allowed equity return.

Southern Power continues to focus on several key performance indicators, including, but not limited to, the equivalent forced outage rate and contract availability to evaluate operating results and help ensure its ability to meet its contractual commitments to customers.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2021 Annual Report

RESULTS OF OPERATIONS

Southern Company

Consolidated net income attributable to Southern Company was $2.4 billion in 2021, a decrease of $726 million, or 23.3%, from 2020. The decrease was primarily due to a $1.0 billion increase in after-tax charges related to the construction of Plant Vogtle Units 3 and 4 and higher non-fuel operations and maintenance costs, partially offset by an increase in natural gas revenues associated with colder weather in the first quarter 2021 as compared to the corresponding period in 2020 and infrastructure replacement programs and base rate changes, higher retail electric revenues primarily associated with rates and pricing and sales growth, a decrease in impairment charges and a gain on termination related to leveraged leases at Southern Holdings, and higher wholesale electric capacity revenues. See Notes 2, 9, and 15 to the financial statements under "Georgia Power – Nuclear Construction," "Southern Company Leveraged Lease," and "Southern Company," respectively, for additional information.

Basic EPS was $2.26 in 2021 and $2.95 in 2020. Diluted EPS, which factors in additional shares related to stock-based compensation, was $2.24 in 2021 and $2.93 in 2020. EPS for 2021 and 2020 was negatively impacted by $0.01 and $0.03 per share, respectively, as a result of increases in the average shares outstanding. See Note 8 to the financial statements under "Outstanding Classes of Capital Stock – Southern Company" for additional information.

Dividends paid per share of common stock were $2.62 in 2021 and $2.54 in 2020. In January 2022, Southern Company declared a quarterly dividend of 66 cents per share. For 2021, the dividend payout ratio was 116% compared to 86% for 2020.

Discussion of Southern Company's results of operations is divided into three parts – the Southern Company system's primary business of electricity sales, its gas business, and its other business activities.


	2021		2020
	(in millions)
Electricity business	$	2,247	$	3,115
Gas business	539		590
Other business activities	(393)		(586)
Net Income	$	2,393	$	3,119

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2021 Annual Report

Electricity Business

Southern Company's electric utilities generate and sell electricity to retail and wholesale customers. A condensed statement of income for the electricity business follows:


	2021		Increase (Decrease) from 2020
	(in millions)
Electric operating revenues	$	18,300	$	1,803
Fuel	4,010		1,043
Purchased power	978		179
Cost of other sales	109		15
Other operations and maintenance	4,809		559
Depreciation and amortization	2,953		12
Taxes other than income taxes	1,062		38
Estimated loss on Plant Vogtle Units 3 and 4	1,692		1,367
Impairment charges	2		2
Gain on dispositions, net	(59)		(17)
Total electric operating expenses	15,556		3,198
Operating income	2,744		(1,395)
Allowance for equity funds used during construction	179		41
Interest expense, net of amounts capitalized	968		(8)
Other income (expense), net	427		112
Income taxes	219		(298)
Net income	2,163		(936)
Less:
Dividends on preferred stock of subsidiaries	15		—
Net loss attributable to noncontrolling interests	(99)		(68)
Net Income Attributable to Southern Company	$	2,247	$	(868)

Electric Operating Revenues

Electric operating revenues for 2021 were $18.3 billion, reflecting a $1.8 billion, or 10.9%, increase from 2020. Details of electric operating revenues were as follows:


	2021		2020
	(in millions)
Retail electric — prior year	$	13,643
Estimated change resulting from —
Rates and pricing	209
Sales growth	208
Weather	(74)
Fuel and other cost recovery	866
Retail electric — current year	$	14,852	$	13,643
Wholesale electric revenues	2,455		1,945
Other electric revenues	718		672
Other revenues	275		237
Electric operating revenues	$	18,300	$	16,497

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2021 Annual Report

Retail electric revenues increased $1.2 billion, or 8.9%, in 2021 as compared to 2020. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing in 2021 was primarily due to an increase effective January 1, 2021 in Alabama Power's Rate RSE, net of a related customer refund, and increases at Georgia Power resulting from higher contributions by commercial and industrial customers with variable demand-driven pricing, fixed residential customer bill programs, the effects of higher KWH sales on ECCR tariff revenues, and base tariff increases in accordance with the 2019 ARP, partially offset by a decrease in Georgia Power's NCCR tariff, both effective January 1, 2021.

Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.

See Note 2 to the financial statements under "Alabama Power" and "Georgia Power" for additional information. Also see "Energy Sales" herein for a discussion of changes in the volume of energy sold, including changes related to sales growth (decline) and weather.

Wholesale electric revenues consist of revenues from PPAs and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, the ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated MRA sales under cost-based tariffs as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.

Wholesale electric revenues from power sales were as follows:


	2021		2020
	(in millions)
Capacity and other	$	550	$	476
Energy	1,905		1,469
Total	$	2,455	$	1,945

In 2021, wholesale electric revenues increased $510 million, or 26.2%, as compared to 2020 due to increases of $436 million in energy revenues and $74 million in capacity revenues. Energy revenues increased $292 million at Southern Power primarily from a $247 million net increase in the price of energy and a $45 million increase in the volume of KWHs sold. Energy revenues increased $144 million at the traditional electric operating companies primarily due to higher energy prices. The increase in capacity revenues primarily resulted from a power sales agreement at Alabama Power that began in September 2020 and a net increase in natural gas PPAs at Southern Power.

Other Electric Revenues

Other electric revenues increased $46 million, or 6.8%, in 2021 as compared to 2020. The increase was primarily due to increases of $28 million in transmission revenues primarily related to new PPAs at Southern Power and increased open access transmission tariff sales at Alabama Power, $27 million in customer fees largely resulting from the COVID-19 pandemic-related temporary suspensions of disconnections and late fees in 2020 for the traditional electric operating companies, $11 million from outdoor lighting sales at Georgia Power, and $10 million in cogeneration steam revenue associated with higher natural gas prices at Alabama Power, partially offset by a $26 million decrease in pole attachment revenues at Georgia Power.

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Southern Company and Subsidiary Companies 2021 Annual Report

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2021 and the percent change from 2020 were as follows:


	2021
	Total KWHs	Total KWH Percent Change		Weather-Adjusted Percent Change(*)
	(in billions)
Residential	47.4	(0.2)	%	0.5	%
Commercial	46.7	2.7		3.2
Industrial	48.7	3.7		3.7
Other	0.6	(5.1)		(5.1)
Total retail	143.4	2.0		2.4	%
Wholesale	50.0	9.5
Total energy sales	193.4	3.8	%

(*)Weather-adjusted KWH sales are estimated using statistical models of the historical relationship between temperatures and energy sales, and then removing the estimated effect of deviations from normal temperature conditions. Normal temperature conditions are defined as those experienced in the applicable service territory over a specified historical period. This metric is useful because it allows trends in historical operations to be evaluated apart from the influence of weather conditions. Management also considers this metric in developing long-term capital and financial plans.

Changes in retail energy sales are generally the result of changes in electricity usage by customers, weather, and the number of customers. Weather-adjusted retail energy sales increased 3.4 billion KWHs in 2021 as compared to 2020. Weather-adjusted residential usage increased primarily due to customer growth, largely offset by decreased customer usage resulting from shelter-in-place orders in effect during 2020. Weather-adjusted commercial and industrial usage increased primarily due to the negative impacts of the COVID-19 pandemic on energy sales being more severe in 2020.

See "Electric Operating Revenues" above for a discussion of significant changes in wholesale revenues related to changes in price and KWH sales.

Other Revenues

Other revenues increased $38 million, or 16.0%, in 2021 as compared to 2020. The increase was primarily due to increases in unregulated sales of products and services of $29 million at Alabama Power and $9 million at Georgia Power.

Fuel and Purchased Power Expenses

The mix of fuel sources for the generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the electric utilities purchase a portion of their electricity needs from the wholesale market.

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Southern Company and Subsidiary Companies 2021 Annual Report

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


	2021	2020
Total generation (in billions of KWHs)(a)	179	174
Total purchased power (in billions of KWHs)	18	18
Sources of generation (percent) —
Gas	48	52
Coal	22	18
Nuclear	18	18
Hydro	4	4
Wind, Solar, and Other	8	8
Cost of fuel, generated (in cents per net KWH) —
Gas(a)	3.07	2.03
Coal	2.85	2.91
Nuclear	0.75	0.78
Average cost of fuel, generated (in cents per net KWH)(a)	2.55	1.96
Average cost of purchased power (in cents per net KWH)(b)	5.85	4.65

(a)Excludes Central Alabama Generating Station KWHs and associated cost of fuel as its fuel is provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power" for additional information.

(b)Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.

In 2021, total fuel and purchased power expenses were $5.0 billion, an increase of $1.2 billion, or 32.4%, as compared to 2020. The increase was primarily the result of a $1.1 billion increase in the average cost of fuel generated and purchased and a $170 million increase in the volume of KWHs generated and purchased.

Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See Note 2 to the financial statements for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.

Fuel

In 2021, fuel expense was $4.0 billion, an increase of $1.0 billion, or 35.2%, as compared to 2020. The increase was primarily due to a 51.2% increase in the average cost of natural gas per KWH generated, a 25.7% increase in the volume of KWHs generated by coal, and a 12.2% decrease in the volume of KWHs generated by hydro, partially offset by a 4.9% decrease in the volume of KWHs generated by natural gas.

Purchased Power

In 2021, purchased power expense was $978 million, an increase of $179 million, or 22.4%, as compared to 2020. The increase was primarily due to a 25.8% increase in the average cost per KWH purchased primarily due to higher natural gas prices.

Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.

Cost of Other Sales

Cost of other sales increased $15 million, or 16.0%, in 2021 as compared to 2020 primarily due to an increase in unregulated power delivery construction and maintenance projects at Georgia Power.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $559 million, or 13.2%, in 2021 as compared to 2020. A portion of the increase in 2021 compared to 2020 reflects cost containment activities implemented to help offset the effects of the recessionary economy resulting from the beginning of the COVID-19 pandemic. The increase was primarily associated with increases of $174 million in transmission and distribution expenses, including $37 million of reliability NDR credits applied in 2020 at Alabama

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Southern Company and Subsidiary Companies 2021 Annual Report

Power, $133 million in scheduled generation outage and maintenance expenses, and $63 million in compensation and benefit expenses, as well as a $40 million loss on sales-type leases associated with PPAs at Southern Power's Garland and Tranquillity battery energy storage facilities. Also contributing to the increase was a $19 million increase in compliance and environmental expenses at the traditional electric operating companies and an $18 million decrease in nuclear property insurance refunds at Alabama Power and Georgia Power. See Notes 2 and 9 to the financial statements under "Alabama Power – Rate NDR" and "Lessor," respectively, for additional information.

Depreciation and Amortization

Depreciation and amortization increased $12 million, or 0.4%, in 2021 as compared to 2020. The increase was due to an increase of $111 million in depreciation associated with additional plant in service, partially offset by a net decrease of $90 million in amortization of regulatory assets primarily associated with CCR AROs under the terms of Georgia Power's 2019 ARP. See Note 2 to the financial statements under "Georgia Power – Rate Plans" for additional information.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $38 million, or 3.7%, in 2021 as compared to 2020. The increase primarily reflects a $25 million increase in municipal franchise fees at Georgia Power and a $21 million increase in property taxes primarily resulting from higher assessed values, partially offset by a $14 million decrease in utility license taxes at Alabama Power.

Estimated Loss on Plant Vogtle Units 3 and 4

Estimated probable loss on Plant Vogtle Units 3 and 4 increased $1.4 billion in 2021 as compared to 2020. The losses in each year were recorded to reflect Georgia Power's revised total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information.

Gain on Dispositions, Net

Gain on dispositions, net increased $17 million, or 40.5%, in 2021 as compared to 2020. The increase primarily reflects $41 million in gains at Southern Power primarily due to contributions of wind turbine equipment to various equity method investments in the first quarter 2021 and $14 million in gains at Alabama Power primarily from property sales, partially offset by a $39 million gain at Southern Power related to the sale of Plant Mankato in the first quarter 2020. See Notes 7 and 15 to the financial statements under "Southern Power" for additional information.

Allowance for Equity Funds Used During Construction

Allowance for equity funds used during construction increased $41 million, or 29.7%, in 2021 as compared to 2020. The increase was primarily associated with Georgia Power's construction of Plant Vogtle Units 3 and 4. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction – Regulatory Matters" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized decreased $8 million, or 0.8%, in 2021 as compared to 2020 primarily due to a decrease of approximately $30 million due to lower interest rates at the traditional electric operating companies and an $11 million net increase in capitalized interest, partially offset by an increase of approximately $33 million due to an increase in average outstanding long-term borrowings. See Note 8 to the financial statements for additional information.

Other Income (Expense), Net

Other income (expense), net increased $112 million, or 35.6%, in 2021 as compared to 2020 primarily related to a $135 million increase in non-service cost-related retirement benefits income, partially offset by a $12 million gain recorded by Southern Power in the third quarter 2020 associated with the Roserock solar facility litigation and an $8 million decrease in interest income. See Note 11 to the financial statements for additional information.

Income Taxes

Income taxes decreased $298 million, or 57.6%, in 2021 as compared to 2020. The decrease was primarily due to lower pre-tax earnings primarily resulting from higher charges in 2021 associated with the construction of Plant Vogtle Units 3 and 4 at Georgia Power and changes in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in February 2021 at Southern Power, partially offset by an increase in a valuation allowance on certain state tax credit carryforwards

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Southern Company and Subsidiary Companies 2021 Annual Report

at Georgia Power. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" and Note 10 to the financial statements for additional information.

Net Loss Attributable to Noncontrolling Interests

Substantially all noncontrolling interests relate to renewable projects at Southern Power. Net loss attributable to noncontrolling interests increased $68 million in 2021 as compared to 2020. The increased loss was primarily due to loss allocations to Southern Power's partners in the Garland and Tranquillity battery energy storage facilities, including $26 million allocated from the loss on sales-type leases. In addition, the increased loss was due to higher HLBV loss allocations to Southern Power's wind tax equity partners, including new partnerships entered into during 2020 and 2021, and lower income allocations to Southern Power's solar equity partners, totaling $29 million. See Notes 9 and 15 to the financial statements under "Lessor" and "Southern Power," respectively, for additional information.

Gas Business

Southern Company Gas distributes natural gas through utilities in four states and is involved in several other complementary businesses including gas pipeline investments, wholesale gas services (until the sale of Sequent on July 1, 2021), and gas marketing services.

A condensed statement of income for the gas business follows:


	2021		Increase (Decrease) from 2020
	(in millions)
Operating revenues	$	4,380	$	946
Cost of natural gas	1,619		647
Other operations and maintenance	1,072		106
Depreciation and amortization	536		36
Taxes other than income taxes	225		19

Gain on dispositions, net	(127)		(105)
Total operating expenses	3,325		703
Operating income	1,055		243
Earnings from equity method investments	50		(91)
Interest expense, net of amounts capitalized	238		7
Other income (expense), net	(53)		(94)
Income taxes	275		102
Net income	$	539	$	(51)

Seasonality of Results

During the period from November through March when natural gas usage and operating revenues are generally higher (Heating Season), more customers are connected to Southern Company Gas' distribution systems and natural gas usage is higher in periods of colder weather. Prior to the sale of Sequent, wholesale gas services' operating revenues were occasionally impacted due to peak usage by power generators in response to summer energy demands. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively equally over any given year. Thus, operating results can vary significantly from quarter to quarter as a result of seasonality. For 2021, the percentage of operating revenues and net income generated during the Heating Season (January through March and November through December) were 70% and 102%, respectively. For 2020, the percentage of operating revenues and net income generated during the Heating Season were 68% and 86%, respectively.

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Southern Company and Subsidiary Companies 2021 Annual Report

Operating Revenues

Operating revenues in 2021 were $4.4 billion, reflecting a $946 million, or 27.5%, increase compared to 2020. Details of operating revenues were as follows:


	2021
	(in millions)
Operating revenues – prior year	$	3,434
Estimated change resulting from –
Infrastructure replacement programs and base rate changes	146

Gas costs and other cost recovery	675

Wholesale gas services	114
Other	11
Operating revenues – current year	$	4,380

Revenues at the natural gas distribution utilities increased in 2021 compared to 2020 due to rate increases and continued investment in infrastructure replacement. See Note 2 to the financial statements under "Southern Company Gas" for additional information.

Revenues associated with gas costs and other cost recovery increased in 2021 compared to 2020 primarily due to higher natural gas cost recovery as a result of higher volumes of natural gas sold and an increase in natural gas prices. The natural gas distribution utilities have weather or revenue normalization mechanisms that mitigate revenue fluctuations from customer consumption changes. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. See "Cost of Natural Gas" herein for additional information.

Revenues from wholesale gas services increased in 2021 primarily due to higher volumes of natural gas sold and higher commercial activities as a result of Winter Storm Uri, partially offset by derivative losses, all prior to the sale of Sequent. See Note 15 to the financial statements under "Southern Company Gas" for additional information.

Southern Company Gas hedged its exposure to warmer-than-normal weather in Illinois for gas distribution operations and in Illinois and Georgia for gas marketing services. The remaining impacts of weather on earnings were immaterial.

Cost of Natural Gas

Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, the natural gas distribution utilities charge their 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. 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. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. Cost of natural gas at the natural gas distribution utilities represented 86.3% of the total cost of natural gas for 2021.

Gas marketing services customers are charged for actual and estimated natural gas consumed. Cost of natural gas includes the cost of fuel and associated transportation costs, lost and unaccounted for gas, adjustments to reduce the value of inventories to market value, if applicable, and gains and losses associated with certain derivatives.

Cost of natural gas was $1.6 billion, an increase of $647 million, or 66.6%, in 2021 compared to 2020, which reflects higher gas cost recovery in 2021 as a result of higher volumes sold and a 91.2% increase in natural gas prices compared to 2020.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $106 million, or 11.0%, in 2021 compared to 2020. The increase was primarily due to increases of $60 million in compensation expenses, $30 million of which was at Sequent, $10 million in facility costs, and $10 million in bad debt expense, which is passed through directly to customers and has no impact on net income.

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Southern Company and Subsidiary Companies 2021 Annual Report

Depreciation and Amortization

Depreciation and amortization increased $36 million, or 7.2%, in 2021 compared to 2020. The increase was primarily due to continued infrastructure investments at the natural gas distribution utilities. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" for additional information.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $19 million, or 9.2%, in 2021 compared to 2020. The increase was primarily due to a $15 million increase in revenue tax expenses as a result of higher natural gas revenues at Nicor Gas, which are passed through directly to customers and have no impact on net income.

Gain on Dispositions, Net

Gain on dispositions, net increased $105 million in 2021 compared to 2020. In 2021, Southern Company Gas recorded a $121 million gain on the sale of Sequent, as well as an additional $5 million gain from the sale of Pivotal LNG. In 2020, Southern Company Gas recorded a $22 million gain on the sale of Jefferson Island. See Note 15 to the financial statements under "Southern Company Gas" for additional information.

Earnings from Equity Method Investments

Earnings from equity method investments decreased $91 million, or 64.5%, in 2021 compared to 2020. The decrease was primarily due to impairment charges in 2021 totaling $84 million related to the PennEast Pipeline project. See Note 7 to the financial statements under "Southern Company Gas" for additional information.

Other Income (Expense), Net

Other income (expense), net decreased $94 million in 2021 compared to 2020. The decrease was largely due to $101 million in charitable contributions by Sequent prior to its sale.

Income Taxes

Income taxes increased $102 million, or 59.0%, in 2021 compared to 2020. The increase was primarily due to $114 million in additional tax expense resulting from the sale of Sequent, including changes in state tax apportionment rates, and higher pre-tax earnings at the natural gas distribution utilities, partially offset by $18 million of tax benefit resulting from the PennEast Pipeline project impairment charges in the second and third quarters of 2021. See Notes 7 and 15 to the financial statements under "Southern Company Gas" and Note 10 to the financial statements for additional information.

Other Business Activities

Southern Company's other business activities primarily include the parent company (which does not allocate operating expenses to business units); PowerSecure, which provides distributed energy and resilience solutions and deploys microgrids for commercial, industrial, governmental, and utility customers; Southern Holdings, which invests in various projects; and Southern Linc, which provides digital wireless communications for use by the Southern Company system and also markets these services to the public and provides fiber optics services within the Southeast.

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A condensed statement of operations for Southern Company's other business activities follows:


	2021		Increase (Decrease) from 2020
	(in millions)
Operating revenues	$	433	$	(11)
Cost of other sales	249		15
Other operations and maintenance	207		11
Depreciation and amortization	75		(2)
Taxes other than income taxes	4		—

Gain on dispositions, net	—		1
Total operating expenses	535		25
Operating income (loss)	(102)		(36)
Earnings from equity method investments	26		14
Interest expense	631		17
Impairment of leveraged leases	7		(199)

Other income (expense), net	94		103
Income taxes (benefit)	(227)		70
Net loss	$	(393)	$	193

Operating Revenues

Southern Company's operating revenues for these other business activities decreased $11 million, or 2.5%, in 2021 as compared to 2020 primarily due to a decrease at Southern Linc related to a contract for the design and construction of a fiber optic system completed in 2020.

Cost of Other Sales

Cost of other sales for these other business activities increased $15 million, or 6.4%, in 2021 as compared to 2020 primarily due to distributed infrastructure projects at PowerSecure.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses for these other business activities increased $11 million, or 5.6%, in 2021 as compared to 2020. The increase was primarily due to a $16 million increase at the parent company primarily related to director compensation expenses and an $11 million increase at PowerSecure primarily associated with higher bad debt expense, partially offset by a $17 million decrease at Southern Linc primarily related to the design and construction of a fiber optic system completed in 2020.

Earnings from Equity Method Investments

Earnings from equity method investments for these other business activities increased $14 million in 2021 as compared to 2020 primarily due to an increase in investment income at Southern Holdings.

Interest Expense

Interest expense for these other business activities increased $17 million, or 2.8%, in 2021 as compared to 2020 primarily due to an increase of approximately $64 million related to higher average outstanding long-term borrowings, partially offset by decreases of approximately $34 million due to lower interest rates and $6 million due to a reduction in losses associated with the extinguishment of debt at the parent company. See Note 8 to the financial statements for additional information.

Impairment of Leveraged Leases

Impairment charges related to leveraged lease investments at Southern Holdings decreased $199 million, or 96.6%, in 2021 as compared to 2020. See Notes 9 and 15 to the financial statements under "Southern Company Leveraged Lease" and "Southern Company," respectively, for additional information.

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Southern Company and Subsidiary Companies 2021 Annual Report

Other Income (Expense), Net

Other income (expense), net for these other business activities increased $103 million in 2021 as compared to 2020 primarily due to a $93 million pre-tax gain ($99 million gain after tax) recorded at Southern Holdings in 2021 related to the termination of leveraged leases and a $12 million decrease in charitable donations at the parent company. See Note 15 to the financial statements under "Southern Company" for additional information.

Income Taxes (Benefit)

The income tax benefit for these other business activities decreased $70 million, or 23.6%, in 2021 as compared to 2020 primarily due to the tax impacts related to the 2020 charges associated with leveraged lease investments and the 2021 leveraged lease dispositions at Southern Holdings, partially offset by lower pre-tax earnings at the parent company. See Notes 9, 10, and 15 to the financial statements under "Southern Company Leveraged Lease," "Effective Tax Rate," and "Southern Company," respectively, for additional information.

Alabama Power

Alabama Power's 2021 net income after dividends on preferred stock was $1.24 billion, representing an $88 million, or 7.7%, increase from 2020. The increase was primarily due to an increase in retail revenues associated with an adjustment effective in January 2021 to Rate RSE, net of a related customer refund, and higher customer usage. Also contributing to the increase were additional wholesale capacity revenues related to a power sales agreement that began in September 2020 and increased sales of unregulated products and services. These increases to income were partially offset by increases in operations and maintenance expenses and depreciation. See Note 2 to the financial statements under "Alabama Power – Rate RSE" for additional information.

A condensed income statement for Alabama Power follows:


	2021		Increase (Decrease) from 2020
	(in millions)
Operating revenues	$	6,413	$	583
Fuel	1,235		265
Purchased power	368		49
Other operations and maintenance	1,735		116
Depreciation and amortization	859		47
Taxes other than income taxes	410		(6)
Total operating expenses	4,607		471
Operating income	1,806		112
Allowance for equity funds used during construction	52		6
Interest expense, net of amounts capitalized	340		2
Other income (expense), net	107		7
Income taxes	372		35
Net income	1,253		88
Dividends on preferred stock	15		—
Net income after dividends on preferred stock	$	1,238	$	88

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Operating Revenues

Operating revenues for 2021 were $6.4 billion, reflecting a $583 million, or 10.0%, increase from 2020. Details of operating revenues were as follows:


	2021		2020
	(in millions)
Retail — prior year	$	5,213
Estimated change resulting from —
Rates and pricing	115
Sales growth	50
Weather	(15)
Fuel and other cost recovery	136
Retail — current year	$	5,499	$	5,213
Wholesale revenues —
Non-affiliates	377		269
Affiliates	171		46
Total wholesale revenues	548		315
Other operating revenues	366		302
Total operating revenues	$	6,413	$	5,830

Retail revenues increased $286 million, or 5.5%, in 2021 as compared to 2020. The significant factors driving this change are shown in the preceding table. The increase was primarily due to a Rate RSE increase effective January 1, 2021, increases in fuel and other cost recovery, and increases in commercial and industrial sales primarily due to the negative impacts of the COVID-19 pandemic on energy demand being more severe in 2020. These increases were offset by an increase in the accrual for a Rate RSE customer refund and milder weather in 2021 when compared to 2020. See Note 2 to the financial statements under "Alabama Power – Rate RSE" for additional information.

See "Energy Sales" herein for a discussion of changes in the volume of energy sold, including changes related to sales growth and weather.

Electric rates include provisions to recognize the recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 2 to the financial statements under "Alabama Power" for additional information.

Wholesale revenues from sales to non-affiliated utilities were as follows:


	2021		2020
	(in millions)
Capacity and other	$	173	$	127
Energy	204		142
Total non-affiliated	$	377	$	269

In 2021, wholesale revenues from sales to non-affiliates increased $108 million, or 40.1%, as compared to 2020 due to a $46 million increase in capacity revenues primarily related to a power sales agreement that began in September 2020 and a $62 million increase in energy revenues primarily due to higher natural gas prices. See Notes 2 and 15 to the financial statements under "Alabama Power – Certificates of Convenience and Necessity" and "Alabama Power," respectively, for additional information.

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not affect net income. Short-term opportunity energy sales are also included in wholesale energy sales to non-affiliates. These

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

In 2021, wholesale revenues from sales to affiliates increased $125 million, or 271.7%, as compared to 2020. The revenue increase reflects a 110.0% increase in 2021 KWH sales due to higher demand for Alabama Power's available lower cost generation and a 75.8% increase in the price of energy, primarily natural gas.

Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales and purchases are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.

In 2021, other operating revenues increased $64 million, or 21.2%, as compared to 2020 primarily due to a $29 million increase in unregulated sales of products and services, a $13 million increase in customer fees largely resulting from the COVID-19 pandemic-related temporary suspensions of disconnections and late fees in 2020, a $10 million increase in cogeneration steam revenue associated with higher natural gas prices, and an $8 million increase in transmission revenues primarily related to open access transmission tariff sales.

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2021 and the percent change from 2020 were as follows:


	2021
	Total KWHs	Total KWH Percent Change		Weather-Adjusted Percent Change(*)
	(in billions)
Residential	17.5	(0.9)	%	(0.7)	%
Commercial	12.7	2.3		2.9
Industrial	20.8	2.2		2.2
Other	0.1	(13.8)		(13.8)
Total retail	51.1	1.1		1.3	%
Wholesale
Non-affiliates	9.8	53.8
Affiliates	5.2	110.0
Total wholesale	15.0	69.6
Total energy sales	66.1	11.3	%

(*)Weather-adjusted KWH sales are estimated using statistical models of the historical relationship between temperatures and energy sales, and then removing the estimated effect of deviations from the normal temperature conditions. Normal temperature conditions are defined as those experienced in Alabama Power's service territory over a specified historical period. This metric is useful because it allows trends in historical operations to be evaluated apart from the influence of weather conditions. Management also considers this metric in developing long-term capital and financial plans.

Changes in retail energy sales are generally the result of changes in electricity usage by customers, weather, and the number of customers. Revenues attributable to changes in sales increased in 2021 when compared to 2020. In 2021, weather-adjusted residential KWH sales decreased 0.7% primarily due to safer-at-home guidelines in effect during 2020. Weather-adjusted commercial KWH sales increased 2.9% and industrial KWH sales increased 2.2% primarily due to the negative impacts of the COVID-19 pandemic on energy sales being more severe in 2020.

See "Operating Revenues" above for a discussion of significant changes in wholesale revenues from sales to non-affiliates and wholesale revenues from sales to affiliated companies related to changes in price and KWH sales.

Fuel and Purchased Power Expenses

The mix of fuel sources for generation of electricity is determined primarily by the unit cost of fuel consumed, demand, and the availability of generating units. Additionally, Alabama Power purchases a portion of its electricity needs from the wholesale market.

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Details of Alabama Power's generation and purchased power were as follows:


	2021	2020
Total generation (in billions of KWHs)(a)	58.5	53.8
Total purchased power (in billions of KWHs)	6.4	6.9
Sources of generation (percent)(a) —
Coal	46	40
Nuclear	26	28
Gas	19	22
Hydro	9	10
Cost of fuel, generated (in cents per net KWH) —
Coal	2.77	2.74
Nuclear	0.70	0.75
Gas(a)	2.89	2.13
Average cost of fuel, generated (in cents per net KWH)(a)	2.22	1.98
Average cost of purchased power (in cents per net KWH)(b)	6.52	4.82

(b)Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.

Fuel and purchased power expenses were $1.6 billion in 2021, an increase of $314 million, or 24.4%, compared to 2020. The increase was primarily due to a $196 million increase in the average cost of fuel and purchased power and a $117 million net increase related to the volume of KWHs generated and purchased.

Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. Alabama Power, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See Note 2 to the financial statements under "Alabama Power – Rate ECR" for additional information.

Fuel

Fuel expense was $1.2 billion in 2021, an increase of $265 million, or 27.3%, compared to 2020. The increase was primarily due to a 35.7% increase in the average cost of natural gas per KWH generated, which excludes tolling agreements, a 25.1% increase in the volume of KWHs generated by coal, and an 8.8% decrease in the volume of KWHs generated by hydro, partially offset by a 6.7% decrease in the average cost of nuclear fuel per KWH generated and a 3.6% decrease in the volume of KWHs generated by natural gas.

Purchased Power – Non-Affiliates

Purchased power expense from non-affiliates was $221 million in 2021, an increase of $30 million, or 15.7%, compared to 2020. The increase was primarily due to a 19.4% increase in the amount of energy purchased due to a new PPA that began in September 2020 and a 10.6% increase in the average cost of purchased power per KWH as a result of higher natural gas prices.

Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation.

Purchased Power – Affiliates

Purchased power expense from affiliates was $147 million in 2021, an increase of $19 million, or 14.8%, compared to 2020. The increase was primarily due to an 87.4% increase in the average cost of purchased power per KWH as a result of higher natural gas prices, partially offset by a 38.8% decrease in the volume of KWH purchased as Alabama Power's units generally dispatched at a lower cost than other available Southern Company system resources.

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Southern Company and Subsidiary Companies 2021 Annual Report

Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $116 million, or 7.2%, in 2021 as compared to 2020. A portion of the increase in 2021 compared to 2020 reflects cost containment activities implemented to help offset the effects of the recessionary economy resulting from the beginning of the COVID-19 pandemic. The increase was primarily due to a $59 million increase in generation expenses associated with scheduled outages and Rate CNP Compliance-related expenses primarily related to the addition of new environmental systems in 2021. Also contributing to the increase were increases of $55 million in transmission and distribution line maintenance expenses related to reliability NDR credits applied in 2020 and vegetation management expenses, $22 million in compensation and benefit expenses, and $11 million related to unregulated products and services, as well as a $10 million decrease in nuclear property insurance refunds. The increase was partially offset by a $36 million decrease in bad debt expense and a net decrease of $35 million to the NDR accrual in 2021 when compared to 2020. See Note 2 to the financial statements under "Alabama Power – Rate NDR" and " – Rate CNP Compliance" for additional information.

Depreciation and Amortization

Depreciation and amortization increased $47 million, or 5.8%, in 2021 as compared to 2020 primarily due to additional plant in service, including the purchase of the Central Alabama Generating Station in August 2020. See Notes 5 and 15 to the financial statements for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $2 million, or 0.6%, in 2021 as compared to 2020 primarily due to an increase of approximately $17 million associated with higher average outstanding borrowings, largely offset by a decrease of approximately $16 million related to lower interest rates. See Note 8 to the financial statements for additional information.

Other Income (Expense), Net

Other income (expense), net increased $7 million, or 7.0%, in 2021 as compared to 2020 primarily due to an increase in non-service cost-related retirement benefits income. See Note 11 to the financial statements for additional information.

Income Taxes

Income taxes increased $35 million, or 10.4%, in 2021 as compared to 2020 primarily due to higher pre-tax earnings. See Note 10 to the financial statements for additional information.

Georgia Power

Georgia Power's 2021 net income was $584 million, representing a $991 million, or 62.9%, decrease from the previous year. The decrease was primarily due to a $1.0 billion increase in after-tax charges related to the construction of Plant Vogtle Units 3 and 4. Also contributing to the decrease were higher non-fuel operations and maintenance costs, partially offset by higher retail revenues associated with sales growth. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information on the construction of Plant Vogtle Units 3 and 4.

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Southern Company and Subsidiary Companies 2021 Annual Report

A condensed income statement for Georgia Power follows:


	2021		Increase (Decrease) from 2020
	(in millions)
Operating revenues	$	9,260	$	951
Fuel	1,449		308
Purchased power	1,491		442
Other operations and maintenance	2,213		260
Depreciation and amortization	1,371		(54)
Taxes other than income taxes	476		32
Estimated loss on Plant Vogtle Units 3 and 4	1,692		1,367
Total operating expenses	8,692		2,355
Operating income	568		(1,404)
Allowance for equity funds used during construction	127		36
Interest expense, net of amounts capitalized	421		(4)
Other income (expense), net	142		53
Income taxes (benefit)	(168)		(320)
Net income	$	584	$	(991)

Operating Revenues

Operating revenues for 2021 were $9.3 billion, reflecting a $951 million, or 11.4%, increase from 2020. Details of operating revenues were as follows:


	2021		2020
	(in millions)
Retail — prior year	$	7,609
Estimated change resulting from —
Rates and pricing	80
Sales growth	152
Weather	(59)
Fuel cost recovery	696
Retail — current year	8,478		$	7,609
Wholesale revenues	197		115
Other operating revenues	585		585
Total operating revenues	$	9,260	$	8,309

Retail revenues increased $869 million, or 11.4%, in 2021 as compared to 2020. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing was primarily due to higher contributions from commercial and industrial customers with variable demand-driven pricing, fixed residential customer bill programs, the effects of higher KWH sales on ECCR tariff revenues, and base tariff increases in accordance with the 2019 ARP, partially offset by a decrease in the NCCR tariff, both effective January 1, 2021. See Note 2 to the financial statements under "Georgia Power – Rate Plans" for additional information.

See "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes related to the sales growth in 2021.

Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See Note 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" for additional information.

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Southern Company and Subsidiary Companies 2021 Annual Report

Wholesale revenues from power sales were as follows:


	2021		2020
	(in millions)
Capacity and other	$	63	$	51
Energy	134		64
Total	$	197	$	115

In 2021, wholesale revenues increased $82 million, or 71.3%, as compared to 2020 largely due to increases of $52 million related to the average cost of fuel primarily due to higher natural gas prices, $12 million in capacity revenues primarily from shared Southern Company power pool sales in accordance with the IIC, and $10 million in KWH sales associated with higher market demand.

Wholesale capacity revenues from PPAs are recognized in amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.

Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.

Other operating revenues were flat in 2021 compared to 2020. Increases of $33 million in unregulated sales associated with power delivery construction and maintenance projects and outdoor lighting and $13 million in customer fees, largely resulting from the COVID-19 pandemic-related temporary suspension of disconnections and late fees in 2020, were largely offset by decreases of $26 million in pole attachment revenues, $9 million associated with the timing of certain unregulated energy conservation projects, and $5 million from retail solar programs.

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2021 and the percent change from 2020 were as follows:


	2021
	Total KWHs	Total KWH Percent Change		Weather-Adjusted Percent Change(*)
	(in billions)
Residential	27.8	0.1	%		1.3	%
Commercial	31.3	2.9			3.4
Industrial	23.3	5.6			5.7
Other	0.5	(2.3)			(2.4)
Total retail	82.9	2.6			3.3	%
Wholesale	3.2	18.1
Total energy sales	86.1	3.1	%

(*)Weather-adjusted KWH sales are estimated using statistical models of the historical relationship between temperatures and energy sales, and then removing the estimated effect of deviations from normal temperature conditions. Normal temperature conditions are defined as those experienced in Georgia Power's service territory over a specified historical period. This metric is useful because it allows trends in historical operations to be evaluated apart from the influence of weather conditions. Management also considers this metric in developing long-term capital and financial plans.

Changes in retail energy sales are generally the result of changes in electricity usage by customers, weather, and the number of customers. Revenues attributable to changes in sales increased in 2021 when compared to 2020. In 2021, weather-adjusted residential KWH sales increased 1.3% compared to 2020 primarily due to customer growth, partially offset by decreased customer usage largely due to shelter-in-place orders in effect during 2020. Weather-adjusted commercial KWH sales increased 3.4% and

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Southern Company and Subsidiary Companies 2021 Annual Report

weather-adjusted industrial KWH sales increased 5.7% primarily due to the negative impacts of the COVID-19 pandemic on energy sales being more severe in 2020.

See "Operating Revenues" above for a discussion of significant changes in wholesale sales to non-affiliates and affiliated companies.

Fuel and Purchased Power Expenses

Fuel costs constitute one of the largest expenses for Georgia Power. The mix of fuel sources for the generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, Georgia Power purchases a portion of its electricity needs from the wholesale market.

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


	2021	2020
Total generation (in billions of KWHs)	58.1	56.8
Total purchased power (in billions of KWHs)	31.7	30.5
Sources of generation (percent) —
Gas	48	52
Nuclear	28	27
Coal	20	16
Hydro and other	4	5
Cost of fuel, generated (in cents per net KWH) —
Gas	3.05	2.19
Nuclear	0.79	0.80
Coal	2.99	3.23
Average cost of fuel, generated (in cents per net KWH)	2.39	1.96
Average cost of purchased power (in cents per net KWH)(*)	5.07	3.69

(*) Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.

Fuel and purchased power expenses were $2.9 billion in 2021, an increase of $750 million, or 34.2%, compared to 2020. The increase was due to an increase of $651 million related to the average cost of fuel and purchased power and an increase of $99 million related to the volume of KWHs generated and purchased.

Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See Note 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" for additional information.

Fuel

Fuel expense was $1.4 billion in 2021, an increase of $308 million, or 27.0%, compared to 2020. The increase was primarily due to a 39.3% increase in the average cost of natural gas per KWH generated and a 27.8% increase in the volume of KWHs generated by coal, partially offset by a 7.4% decrease in the average cost of coal per KWH generated and a decrease of 5.2% in the volume of KWHs generated by natural gas.

Purchased Power - Non-Affiliates

Purchased power expense from non-affiliates was $632 million in 2021, an increase of $92 million, or 17.0%, compared to 2020. The increase was primarily due to an increase of 23.4% in the average cost per KWH purchased primarily due to higher natural gas prices, partially offset by a decrease of 3.5% in the volume of KWHs purchased as Georgia Power units and Southern Company system resources generally dispatched at a lower cost than available market resources.

Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.

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Southern Company and Subsidiary Companies 2021 Annual Report

Purchased Power - Affiliates

Purchased power expense from affiliates was $859 million in 2021, an increase of $350 million, or 68.8%, compared to 2020. The increase was primarily due to an increase of 53.4% in the average cost per KWH purchased primarily due to higher natural gas prices and an increase of 8.4% in the volume of KWHs purchased due to lower cost Southern Company system resources as compared to available Georgia Power-owned generation and market resources.

Energy purchases from affiliates will vary depending on the demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $260 million, or 13.3%, in 2021 as compared to 2020. A portion of the increase in 2021 compared to 2020 reflects cost containment activities implemented to help offset the effects of the recessionary economy resulting from the beginning of the COVID-19 pandemic. The increase was primarily due to increases of $104 million in transmission and distribution expenses associated with vegetation and asset management activities, $63 million in generation expenses associated with outage and non-outage maintenance costs and environmental projects, $28 million in certain compensation and benefit expenses, and $8 million in maintenance costs at corporate and field support facilities, as well as an $8 million decrease in nuclear property insurance refunds.

Depreciation and Amortization

Depreciation and amortization decreased $54 million, or 3.8%, in 2021 as compared to 2020 primarily due to an $88 million decrease in amortization of regulatory assets related to CCR AROs under the terms of the 2019 ARP, partially offset by a $39 million increase in depreciation associated with additional plant in service. See Note 2 to the financial statements under "Georgia Power – Rate Plans – 2019 ARP" for additional information.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $32 million, or 7.2%, in 2021 as compared to 2020 primarily due to a $25 million increase in municipal franchise fees largely related to higher retail revenues and a $9 million increase in property taxes primarily resulting from an increase in the assessed value of property.

Estimated Loss on Plant Vogtle Units 3 and 4

Estimated probable loss on Plant Vogtle Units 3 and 4 increased $1.4 billion in 2021 as compared to 2020. The losses in each year were recorded to reflect revisions to the total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information.

Allowance for Equity Funds Used During Construction

Allowance for equity funds used during construction increased $36 million, or 39.6%, in 2021 as compared to 2020 primarily due to a higher AFUDC base largely associated with the construction of Plant Vogtle Units 3 and 4. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized decreased $4 million, or 0.9%, in 2021 as compared to 2020 primarily due to an increase of $16 million in amounts capitalized largely associated with the construction of Plant Vogtle Units 3 and 4, partially offset by an $11 million increase in interest expense primarily associated with higher average outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein and Note 8 to the financial statements for additional information on borrowings and Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

Other Income (Expense), Net

Other income (expense), net increased $53 million, or 59.6%, in 2021 as compared to 2020 primarily due to a $50 million increase in non-service cost-related retirement benefits income. See Note 11 to the financial statements for additional information on Georgia Power's net periodic pension and other postretirement benefit costs.

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Southern Company and Subsidiary Companies 2021 Annual Report

Income Taxes (Benefit)

In 2021, income tax benefit was $168 million compared to income tax expense of $152 million for 2020, a change of $320 million. The change was primarily due to lower pre-tax earnings resulting from higher charges in 2021 associated with the construction of Plant Vogtle Units 3 and 4, partially offset by an increase in a valuation allowance on certain state tax credit carryforwards. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" and Note 10 to the financial statements for additional information.

Mississippi Power

Mississippi Power's net income was $159 million in 2021 compared to $152 million in 2020. The increase was primarily due to revenues resulting from an increase in base rates that became effective for the first billing cycle of April 2021 and higher customer usage, as well as an increase in other income (expense), net, partially offset by an increase in operations and maintenance expenses.

A condensed income statement for Mississippi Power follows:


	2021		Increase (Decrease) from 2020
	(in millions)
Operating revenues	$	1,322	$	150
Fuel	470		120
Purchased power	26		4
Other operations and maintenance	313		29
Depreciation and amortization	180		(3)
Taxes other than income taxes	128		4
Total operating expenses	1,117		154
Operating income	205		(4)
Interest expense, net of amounts capitalized	60		—
Other income (expense), net	35		18
Income taxes	21		7
Net income	$	159	$	7

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Southern Company and Subsidiary Companies 2021 Annual Report

Operating Revenues

Operating revenues for 2021 were $1.3 billion, reflecting a $150 million, or 12.8%, increase from 2020. Details of operating revenues were as follows:


	2021		2020
	(in millions)
Retail — prior year	$	821
Estimated change resulting from —
Rates and pricing	14
Sales growth	7
Weather	(1)
Fuel and other cost recovery	34
Retail — current year	875		$	821
Wholesale revenues —
Non-affiliates	230		215
Affiliates	188		111
Total wholesale revenues	418		326
Other operating revenues	29		25
Total operating revenues	$	1,322	$	1,172

Total retail revenues for 2021 increased $54 million, or 6.6%, compared to 2020 primarily due to an increase in fuel and other cost recovery revenues primarily as a result of higher recoverable fuel costs, an increase in revenues in accordance with new PEP rates that became effective for the first billing cycle of April 2021, and an increase in customer usage. See Note 2 to the financial statements under "Mississippi Power" for additional information.

See "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes related to sales and weather.

Electric rates for Mississippi Power include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel and emissions portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. See Note 2 to the financial statements under "Mississippi Power – Fuel Cost Recovery" for additional information.

Wholesale revenues from power sales to non-affiliated utilities, including FERC-regulated MRA sales as well as market-based sales, were as follows:


	2021		2020
	(in millions)
Capacity and other	$	3	$	3
Energy	227		212
Total non-affiliated	$	230	$	215

Wholesale revenues from sales to non-affiliates increased $15 million, or 7.0%, compared to 2020. The increase was primarily associated with higher natural gas prices.

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. In addition, Mississippi Power provides service under long-term contracts with rural electric cooperative associations and a municipality located in southeastern Mississippi under full requirements cost-based electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 14.3% of

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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. Short-term opportunity energy sales are also included in sales for resale to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above Mississippi Power's variable cost to produce the energy.

Wholesale revenues from sales to affiliates increased $77 million, or 69.4%, in 2021 compared to 2020. The increase was primarily due to an $86 million increase associated with higher natural gas prices, partially offset by a $10 million decrease associated with lower KWH sales.

Wholesale revenues from sales to affiliates will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2021 and the percent change from 2020 were as follows:


	2021
	Total KWHs	Total KWH Percent Change		Weather-Adjusted Percent Change(*)
	(in millions)
Residential	2,047	1.2	%	0.2	%
Commercial	2,559	1.8		2.7
Industrial	4,615	1.3		1.3
Other	34	(3.3)	%	(3.3)
Total retail	9,255	1.4	%	1.4	%
Wholesale
Non-affiliated	3,611	(4.6)
Affiliated	4,742	(9.3)
Total wholesale	8,353	(7.3)
Total energy sales	17,608	(2.9)	%

(*)Weather-adjusted KWH sales are estimated using statistical models of the historical relationship between temperatures and energy sales, and then removing the estimated effect of deviations from normal temperature conditions. Normal temperature conditions are defined as those experienced in Mississippi Power's service territory over a specified historical period. This metric is useful because it allows trends in historical operations to be evaluated apart from the influence of weather conditions. Management also considers this metric in developing long-term capital and financial plans.

Changes in retail energy sales are generally the result of changes in electricity usage by customers, weather, and the number of customers. Revenues attributable to changes in sales increased in 2021 when compared to 2020. Weather-adjusted residential KWH sales increased 0.2% compared to 2020 due to increased customer growth, partially offset by decreased customer usage. Weather-adjusted commercial KWH sales increased 2.7% and industrial KWH sales increased 1.3% primarily due to the negative impacts of the COVID-19 pandemic on energy sales being more severe in 2020.

See "Operating Revenues" above for a discussion of significant changes in wholesale revenues to affiliated companies.

Fuel and Purchased Power Expenses

The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, Mississippi Power purchases a portion of its electricity needs from the wholesale market.

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Southern Company and Subsidiary Companies 2021 Annual Report

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


	2021	2020
Total generation (in millions of KWHs)	17,377	17,833
Total purchased power (in millions of KWHs)	675	688
Sources of generation (percent) –
Gas	92	94
Coal	8	6
Cost of fuel, generated (in cents per net KWH) –
Gas	2.85	1.97
Coal	3.24	3.62
Average cost of fuel, generated (in cents per net KWH)	2.88	2.08
Average cost of purchased power (in cents per net KWH)	3.90	3.27

Fuel and purchased power expenses were $496 million in 2021, an increase of $124 million, or 33.3%, as compared to 2020. The increase was primarily due to an increase in the average cost of natural gas.

Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clauses. See Note 2 to the financial statements under "Mississippi Power – Fuel Cost Recovery" and Note 1 to the financial statements under "Fuel Costs" for additional information.

Fuel expense increased $120 million, or 34.3%, in 2021 compared to 2020 primarily due to a 44.7% increase in the average cost of natural gas per KWH generated, partially offset by a 4.8% decrease in the volume of KWHs generated by natural gas.

Energy purchases will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $29 million, or 10.2%, in 2021 compared to 2020. A portion of the increase in 2021 compared to 2020 reflects cost containment activities implemented to help offset the effects of the recessionary economy resulting from the beginning of the COVID-19 pandemic. The increase was primarily due to increases of $7 million associated with the Kemper County energy facility (primarily related to increases in dismantlement activities and less salvage proceeds in 2021), $7 million in generation expenses associated with outage and non-outage maintenance, $6 million in distribution operations and maintenance, and $6 million in compensation and benefit expenses.

Other Income (Expense), Net

Other income (expense), net increased $18 million, or 105.9%, in 2021 compared to 2020. The increase was primarily due to a $9 million decrease in charitable donations and increases of $6 million in non-service cost-related retirement benefits income and $3 million in interest associated with a sales-type lease. See Notes 9 and 11 to the financial statements for additional information.

Income Taxes

Income taxes increased $7 million, or 50.0%, in 2021 compared to 2020 due to higher pre-tax earnings and an increase associated with lower flowback of excess deferred income taxes associated with new PEP rates that became effective for the first billing cycle of April 2021. See Note 2 to the financial statements under "Mississippi Power – Performance Evaluation Plan" and Note 10 to the financial statements for additional information.

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Southern Company and Subsidiary Companies 2021 Annual Report

Southern Power

Net income attributable to Southern Power for 2021 was $266 million, a $28 million increase from 2020. The increase was primarily due to a net increase in revenues associated with new PPAs and a tax benefit due to changes in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in February 2021, partially offset by an increase in other operations and maintenance expenses primarily associated with scheduled outages and maintenance and a gain recorded in 2020 associated with the Roserock solar facility litigation. See Note 10 to the financial statements for additional information.

A condensed statement of income follows:


	2021		Increase (Decrease) from 2020
	(in millions)
Operating revenues	$	2,216	$	483
Fuel	802		332
Purchased power	139		65
Other operations and maintenance	423		70
Depreciation and amortization	517		23
Taxes other than income taxes	45		6
Loss on sales-type leases	40		40
Gain on dispositions, net	(41)		(2)
Total operating expenses	1,925		534
Operating income	291		(51)
Interest expense, net of amounts capitalized	147		(4)
Other income (expense), net	10		(9)
Income taxes (benefit)	(13)		(16)
Net income	167		(40)
Net loss attributable to noncontrolling interests	(99)		(68)
Net income attributable to Southern Power	$	266	$	28

Operating Revenues

Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities, and PPA energy revenues from Southern Power's generation facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into an accessible wholesale market, or, to the extent those generation assets are part of the FERC-approved IIC, it may sell power into the Southern Company power pool.

Natural Gas Capacity and Energy Revenue

Capacity revenues generally represent the greatest contribution to operating income and are designed to provide recovery of fixed costs plus a return on investment.

Energy is generally sold at variable cost or is indexed to published natural gas indices. Energy revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.

Solar and Wind Energy Revenue

Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have capacity revenue. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy generated from the respective facility and sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors.

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See FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" herein for additional information regarding Southern Power's PPAs.

Operating Revenues Details

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


	2021		2020
	(in millions)
PPA capacity revenues	$	408	$	384
PPA energy revenues	1,311		1,019
Total PPA revenues	1,719		1,403
Non-PPA revenues	467		316
Other revenues	30		14
Total operating revenues	$	2,216	$	1,733

Operating revenues for 2021 were $2.2 billion, a $483 million, or 28% increase from 2020. The increase in operating revenues was primarily due to the following:

•PPA capacity revenues increased $24 million, or 6%, primarily due to a net increase in sales associated with new natural gas PPAs and increased capacity sales under existing natural gas PPAs.

•PPA energy revenues increased $292 million, or 29%, primarily due to an increase in sales under existing natural gas PPAs resulting from a $206 million increase in the price of fuel and purchased power and a $79 million net increase in sales associated with new natural gas PPAs. Also contributing to the increase was $15 million related to new wind PPAs which began during 2020 and 2021, partially offset by an $11 million decrease in sales under existing wind PPAs.

•Non-PPA revenues increased $151 million, or 48%, due to a $197 million increase in the market price of energy, partially offset by a $46 million decrease in the volume of KWHs sold through short-term sales.

•Other revenues increased $16 million, or 114%, primarily due to transmission revenues related to new PPAs.

Fuel and Purchased Power Expenses

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


	Total KWHs	Total KWH % Change	Total KWHs
	2021		2020
	(in billions of KWHs)
Generation	44		44
Purchased power	3		3
Total generation and purchased power	47	—%	47
Total generation and purchased power (excluding solar, wind, fuel cells, and tolling agreements)	28	—%	28

Southern Power's PPAs for natural gas generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the Southern Company power pool for capacity owned directly by Southern Power.

Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the Southern Company power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.

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


	2021		2020
	(in millions)
Fuel	$	802	$	470
Purchased power	139		74
Total fuel and purchased power expenses	$	941	$	544

In 2021, total fuel and purchased power expenses increased $397 million, or 73%, compared to 2020. Fuel expense increased $332 million, or 71%, primarily due to an increase in the average cost of fuel. Purchased power expense increased $65 million, or 88%, due to an increase associated with the average cost of purchased power.

Other Operations and Maintenance Expenses

In 2021, other operations and maintenance expenses increased $70 million, or 20%, compared to 2020. The increase was primarily due to increases of $21 million in scheduled outage and maintenance expenses, $15 million in transmission expenses primarily related to new PPAs, $10 million in compensation and benefit expenses, $8 million in expenses associated with new wind facilities placed in service during 2020 and 2021, and $5 million related to the allocation of uncollected settlements by the Energy Reliability Council of Texas market as a result of Winter Storm Uri.

Depreciation and Amortization

In 2021, depreciation and amortization increased $23 million, or 5%, compared to 2020 primarily due to new wind facilities placed in service during 2020 and 2021.

Loss on Sales-Type Leases

In 2021, a $40 million loss on sales-type leases was recorded upon commencement of the Garland and Tranquillity battery energy storage facilities' PPAs, $26 million of which was allocated through noncontrolling interests to Southern Power's partners in the projects. The loss was due to ITCs retained and expected to be realized by Southern Power and its partners. See Notes 9 and 15 to the financial statements under "Lessor" and "Southern Power," respectively, for additional information.

Gain on Dispositions, Net

In 2021, gain on dispositions, net increased $2 million, or 5%, compared to 2020. Gains on dispositions totaled $41 million in 2021 primarily due to contributions of wind turbine equipment to various equity method investments in the first quarter 2021. A $39 million gain was also recorded in the first quarter 2020 related to the sale of Plant Mankato. See Notes 7 and 15 to the financial statements under "Southern Power" and "Southern Power – Sales of Natural Gas and Biomass Plants," respectively, for additional information.

Other Income (Expense), Net

In 2021, other income (expense), net decreased $9 million, or 47%, compared to 2020 primarily due to a $12 million gain recorded in the third quarter 2020 associated with the Roserock solar facility litigation.

Income Taxes (Benefit)

In 2021, income tax benefit was $13 million compared to income tax expense of $3 million for 2020, a change of $16 million. The change was primarily due to changes in state apportionment methodology resulting from tax legislation enacted by the State of Alabama in February 2021 and the tax impact from the sale of Plant Mankato in January 2020. See Notes 1, 10, and 15 to the financial statements under "Income Taxes," "Effective Tax Rate," and "Southern Power," respectively, for additional information.

Net Loss Attributable to Noncontrolling Interests

In 2021, net loss attributable to noncontrolling interests increased $68 million compared to 2020. The increased loss was primarily due to loss allocations to the partners in the Garland and Tranquillity battery energy storage facilities, including $26 million allocated from the loss on sales-type leases. In addition, the increased loss was due to higher HLBV loss allocations to wind tax equity partners, including new partnerships entered into during 2020 and 2021, and lower income allocations to solar equity partners, totaling $29 million. See Notes 9 and 15 to the financial statements under "Lessor" and "Southern Power," respectively, for additional information.

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Southern Company Gas

Operating Metrics

Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold.

Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. Southern Company Gas has various regulatory mechanisms, such as weather and revenue normalization and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its utility's respective service territory. Southern Company Gas also utilizes weather hedges to limit the negative income impacts in the event of warmer-than-normal weather.

The number of customers served by gas distribution operations and gas marketing services can be impacted by natural gas prices, economic conditions, and competition from alternative fuels. Gas distribution operations and gas marketing services' customers are primarily located in Georgia and Illinois.

Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas. Wholesale gas services' physical sales volumes represent the daily average natural gas volumes sold to its customers.

Seasonality of Results

During the Heating Season, natural gas usage and operating revenues are generally higher as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Prior to the sale of Sequent on July 1, 2021, wholesale gas services' operating revenues occasionally were impacted due to peak usage by power generators in response to summer energy demands. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing Southern Company Gas' annual results. Thus, Southern Company Gas' operating results can vary significantly from quarter to quarter as a result of seasonality, which is illustrated in the table below.


	Percent Generated During Heating Season
	Operating Revenues		Net Income
2021	70	%	102	%
2020	68	%	86	%

Net Income

Net income attributable to Southern Company Gas in 2021 was $539 million, a decrease of $51 million, or 8.6%, compared to 2020. The decrease was primarily due to $85 million of deferred income taxes and an $80 million decrease at gas pipeline investments primarily due to impairment charges related to the PennEast Pipeline project, partially offset by a $93 million increase at wholesale gas services primarily due to the gain on the sale of Sequent and a $22 million increase at gas distribution operations primarily due to base rate increases and continued investment in infrastructure replacement. See Note 7 to the financial statements under "Southern Company Gas" for additional information on the PennEast Pipeline project and Note 15 to the financial statements under "Southern Company Gas" for additional information on the sale of Sequent.

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A condensed income statement for Southern Company Gas follows:



	2021		Increase (Decrease) from 2020
	(in millions)
Operating revenues	$	4,380	$	946
Cost of natural gas	1,619		647

Other operations and maintenance	1,072		106
Depreciation and amortization	536		36
Taxes other than income taxes	225		19

Gain on dispositions, net	(127)		(105)

Total operating expenses	3,325		703
Operating income	1,055		243

Earnings from equity method investments	50		(91)
Interest expense, net of amounts capitalized	238		7
Other income (expense), net	(53)		(94)

Income taxes	275		102




Net Income	$	539	$	(51)

Operating Revenues

Operating revenues in 2021 were $4.4 billion, reflecting a $946 million, or 27.5%, increase compared to 2020. Details of operating revenues were as follows:


	2021
	(in millions)
Operating revenues – prior year	$	3,434
Estimated change resulting from –
Infrastructure replacement programs and base rate changes	146
Gas costs and other cost recovery	675

Wholesale gas services	114
Other	11
Operating revenues – current year	$	4,380

Revenues at the natural gas distribution utilities increased in 2021 due to rate increases and continued investment in infrastructure replacement. See Note 2 to the financial statements under "Southern Company Gas" for additional information.

Revenues associated with gas costs and other cost recovery increased in 2021 primarily due to higher natural gas cost recovery as a result of higher volumes of natural gas sold and an increase in natural gas prices. The natural gas distribution utilities have weather or revenue normalization mechanisms that mitigate revenue fluctuations from customer consumption changes. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. See "Cost of Natural Gas" herein for additional information.

Revenues from wholesale gas services increased in 2021 primarily due to higher volumes of natural gas sold and higher commercial activities as a result of Winter Storm Uri, partially offset by derivative losses, all prior to the sale of Sequent. See "Segment Information – Wholesale Gas Services" herein and Note 15 to the financial statements under "Southern Company Gas" for additional information.

Heating Degree Days

Southern Company Gas' natural gas distribution utilities have various regulatory mechanisms that limit their exposure to weather changes. Southern Company Gas also uses hedges for any remaining exposure to warmer-than-normal weather in Illinois for gas

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distribution operations and in Illinois and Georgia for gas marketing services; therefore, weather typically does not have a significant net income impact. The following table presents Heating Degree Days information for Illinois and Georgia, the primary locations where Southern Company Gas' operations are impacted by weather.


	Years Ended December 31,			2021 vs. normal		2021 vs. 2020
	Normal(*)	2021	2020	(warmer)		(warmer)
	(in thousands)
Illinois	5,747	5,326	5,477	(7.3)	%	(2.8)	%
Georgia	2,371	2,113	2,122	(10.9)	%	(0.4)	%

(*)Normal represents the 10-year average from January 1, 2011 through December 31, 2020 for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, based on information obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center.

Customer Count

The following table provides the number of customers served by Southern Company Gas at December 31, 2021 and 2020:


	2021		2020
	(in thousands, except market share %)
Gas distribution operations	4,337		4,308
Gas marketing services
Energy customers(*)	603		666
Market share of energy customers in Georgia	28.7	%	28.9	%

(*)Gas marketing services' customers are primarily located in Georgia and Illinois. December 31, 2020 also includes approximately 50,000 customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2020.

Southern Company Gas anticipates customer growth and uses a variety of targeted marketing programs to attract new customers and to retain existing customers.

Cost of Natural Gas

Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, gas distribution operations 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. Gas distribution operations defers or accrues 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. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. Cost of natural gas at gas distribution operations represented 86.3% of the total cost of natural gas for 2021.

In 2021, cost of natural gas was $1.6 billion, an increase of $647 million, or 66.6%, compared to 2020, which reflects higher gas cost recovery in 2021 as a result of higher volumes sold and a 91.2% increase in natural gas prices compared to 2020.

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Volumes of Natural Gas Sold

The following table details the volumes of natural gas sold during all periods presented.


			2021 vs. 2020
	2021	2020	% Change
Gas distribution operations (mmBtu in millions)
Firm	656	623	5.3	%
Interruptible	98	92	6.5
Total	754	715	5.5	%
Wholesale gas services (mmBtu in millions/day)
Daily physical sales(*)	6.6	6.9	(4.3)	%
Gas marketing services (mmBtu in millions)
Firm:
Georgia	34	33	3.0	%
Illinois	7	9	(22.2)
Other	11	13	(15.4)

Interruptible large commercial and industrial	14	14	—
Total	66	69	(4.3)	%

(*) Daily physical sales for 2021 reflect amounts through the sale of Sequent on July 1, 2021.

Other Operations and Maintenance Expenses

In 2021, other operations and maintenance expenses increased $106 million, or 11.0%, compared to 2020. The increase was primarily due to increases of $60 million in compensation expenses, $30 million of which was at Sequent, $10 million in facility costs, and $10 million in bad debt expense, which is passed through directly to customers and has no impact on net income.

Depreciation and Amortization

In 2021, depreciation and amortization increased $36 million, or 7.2%, compared to 2020. The increase was primarily due to continued infrastructure investments at the natural gas distribution utilities. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" for additional information.

Taxes Other Than Income Taxes

In 2021, taxes other than income taxes increased $19 million, or 9.2%, compared to 2020. The increase was primarily due to a $15 million increase in revenue tax expenses as a result of higher natural gas revenues at Nicor Gas, which are passed through directly to customers and have no impact on net income.

Gain on Dispositions, Net

In 2021, gain on dispositions, net increased $105 million compared to 2020. In 2021, Southern Company Gas recorded a $121 million gain on the sale of Sequent, as well as an additional $5 million gain from the sale of Pivotal LNG. In 2020, Southern Company Gas recorded a $22 million gain on the sale of Jefferson Island. See Note 15 to the financial statements under "Southern Company Gas" for additional information.

Earnings from Equity Method Investments

In 2021, earnings from equity method investments decreased $91 million, or 64.5%, compared to 2020. The decrease was primarily due to impairment charges in 2021 totaling $84 million related to the PennEast Pipeline project. See Note 7 to the financial statements under "Southern Company Gas" for additional information.

Other Income (Expense), Net

In 2021, other income (expense), net decreased $94 million compared to 2020. The decrease was largely due to $101 million in charitable contributions by Sequent prior to its sale.

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Income Taxes

In 2021, income taxes increased $102 million, or 59.0%, compared to 2020. The increase was primarily due to $114 million in additional tax expense resulting from the sale of Sequent, including changes in state tax apportionment rates, and higher pre-tax earnings at gas distribution operations, partially offset by $18 million of tax benefit resulting from the PennEast Pipeline project impairment charges in the second and third quarters of 2021 at gas pipeline investments. See Notes 7 and 15 to the financial statements under "Southern Company Gas" and Note 10 to the financial statements for additional information.

Segment Information


	2021						2020
	Operating Revenues		Operating Expenses		Net Income (Loss)		Operating Revenues		Operating Expenses		Net Income (Loss)
	(in millions)						(in millions)
Gas distribution operations	$	3,679	$	2,971	$	412	$	2,952	$	2,297	$	390
Gas pipeline investments	32		11		19		32		12		99
Wholesale gas services	188		(53)		107		74		54		14
Gas marketing services	475		350		88		408		289		89
All other	38		78		(87)		36		43		(2)
Intercompany eliminations	(32)		(32)		—		(68)		(73)		—
Consolidated	$	4,380	$	3,325	$	539	$	3,434	$	2,622	$	590

Gas Distribution Operations

Gas distribution operations is the largest component of Southern Company Gas' business and is subject to regulation and oversight by regulatory agencies in each of the states it serves. These agencies approve natural gas rates designed to provide Southern Company Gas with the opportunity to generate revenues to recover the cost of natural gas delivered to its customers and its fixed and variable costs, including depreciation, interest expense, operations and maintenance, taxes, and overhead costs, and to earn a reasonable return on its investments.

With the exception of Atlanta Gas Light, Southern Company Gas' second largest utility that operates in a deregulated natural gas market and has a straight-fixed-variable rate design that minimizes the variability of its revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed. Southern Company Gas has various regulatory and other mechanisms, such as weather and revenue normalization mechanisms and weather derivative instruments, that limit its exposure to changes in customer consumption, including weather changes within typical ranges in its natural gas distribution utilities' service territories.

In 2021, net income increased $22 million, or 5.6%, compared to 2020. Operating revenues increased $727 million primarily due to higher gas cost recovery, rate increases, and continued investment in infrastructure replacement. Gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas. Operating expenses increased $674 million primarily due to a $540 million increase in cost of gas as a result of higher natural gas prices and higher volumes sold, largely as a result of colder weather in the first quarter 2021 compared to 2020, higher depreciation resulting from additional assets placed in service, higher taxes other than income taxes due to higher pass through taxes, and higher compensation expenses. Other income and expense decreased $10 million primarily due to a decrease in non-service cost-related retirement benefits income. Interest expense, net of amounts capitalized increased $15 million primarily due to additional debt issued to finance continued investments. Income taxes increased $6 million primarily due to higher pre-tax earnings.

See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" and " – Infrastructure Replacement Programs and Capital Projects" for additional information. Also see Note 11 to the financial statements for additional information on retirement benefits.

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Gas Pipeline Investments

Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including SNG, PennEast Pipeline, Dalton Pipeline, and Atlantic Coast Pipeline (until its sale on March 24, 2020). In 2021, net income decreased $80 million, or 80.8%, compared to 2020. The decrease was primarily due to impairment charges totaling $84 million ($67 million after tax) related to the PennEast Pipeline project. See Note 7 to the financial statements under "Southern Company Gas" for information regarding the September 2021 cancellation of the PennEast Pipeline project.

Wholesale Gas Services

Prior to the sale of Sequent, wholesale gas services was involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services, and wholesale gas marketing. Southern Company Gas positioned the business to generate positive economic earnings on an annual basis even under low volatility market conditions that can result from a number of factors. When market price volatility increased, wholesale gas services was positioned to capture significant value and generate stronger results. Operating expenses primarily reflected employee compensation and benefits. See Note 15 to the financial statements under "Southern Company Gas" for information regarding the sale of Sequent.

In 2021, net income increased $93 million compared to 2020. The increase was primarily due to a $114 million increase in operating revenues due to higher commercial activity driven by natural gas price volatility that was generated by cold weather, partially offset by unfavorable storage and transportation derivatives due to widening transportation spreads, as well as a $121 million gain on the sale of Sequent, partially offset by a $14 million increase in other operating expenses primarily related to an increase in variable compensation, a $101 million decrease in other income and (expense) related to higher charitable contributions, and a $29 million increase in income tax expense due to higher pre-tax earnings.

Gas Marketing Services

Gas marketing services provides energy-related products and services to natural gas markets and participants in customer choice programs that were approved in various states to increase competition. These programs allow customers to choose their natural gas supplier while the local distribution utility continues to provide distribution and transportation services. Gas marketing services is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts.

In 2021, net income decreased $1 million, or 1.1%, compared to 2020. The decrease was primarily due to an increase in operating expenses primarily related to a $73 million increase in the cost of gas in 2021 resulting from higher natural gas prices, largely offset by a $67 million increase in operating revenues due to higher natural gas prices and increased retail price spreads.

All Other

All other includes natural gas storage businesses, including Jefferson Island through its sale on December 1, 2020, fuels operations through the sale of Southern Company Gas' interest in Pivotal LNG on March 24, 2020, AGL Services Company, and Southern Company Gas Capital, as well as various corporate operating expenses that are not allocated to the reportable segments and interest income (expense) associated with affiliate financing arrangements.

In 2021, net loss increased $85 million compared to 2020. The increase was primarily due to additional tax expense due to changes in state apportionment rates as a result of the sale of Sequent. See Note 10 to the financial statements and Note 15 to the financial statements under "Southern Company Gas" for additional information.

FUTURE EARNINGS POTENTIAL

General

Prices for electric service provided by the traditional electric operating companies and natural gas distributed by the natural gas distribution utilities to retail customers are set by state PSCs or other applicable state regulatory agencies under cost-based regulatory principles. Retail rates and earnings are reviewed through various regulatory mechanisms and/or processes and may be adjusted periodically within certain limitations. Effectively operating pursuant to these regulatory mechanisms and/or processes and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the traditional electric operating companies and natural gas distribution utilities for the foreseeable future. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Southern Power continues to focus on long-term PPAs. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Utility Regulation" herein and Note 2 to the financial statements for additional information about regulatory matters.

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Each Registrant's results of operations are not necessarily indicative of its future earnings potential. The disposition activities described in Note 15 to the financial statements have reduced earnings for the applicable Registrants. The level of the Registrants' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Registrants' primary businesses of selling electricity and/or distributing natural gas, as described further herein.

For the traditional electric operating companies, these factors include the ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs during a time of increasing costs, including those related to projected long-term demand growth, stringent environmental standards, including CCR rules, safety, system reliability and resiliency, fuel, restoration following major storms, and capital expenditures, including constructing new electric generating plants and expanding and improving the transmission and distribution systems; continued customer growth; and the trend of reduced electricity usage per customer, especially in residential and commercial markets. For Georgia Power, completing construction of Plant Vogtle Units 3 and 4 and the related cost recovery proceedings is another major factor.

Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, which could contribute to a net reduction in customer usage.

Global and U.S. economic conditions have been significantly affected by a series of demand and supply shocks that caused a global and national economic recession in 2020. Most prominently, the COVID-19 pandemic has negatively impacted global supply chains and business operations as suppliers continue to experience difficulties keeping up with strong demand for factory goods, which is being driven by low business inventories. In addition, rising inflation in 2021 and 2022 has resulted in increasing costs for many goods and services. The combination of rising inoculation rates in the U.S. population and the federal COVID-19 relief package contributed to increased economic recovery in 2021; however, fiscal support of business and personal incomes is declining. The drivers, speed, and depth of the 2020 economic contraction were unprecedented and have reduced energy demand across the Southern Company system's service territory, primarily in the commercial and industrial classes. Retail electric revenues attributable to changes in sales increased in 2021 when compared to 2020 primarily due to the normalization of economic activity; however, retail electric sales continued to be negatively impacted by the COVID-19 pandemic when compared to pre-pandemic trends. Recovery is expected to continue in 2022, but the impacts of new COVID-19 variants, as well as responses to the COVID-19 pandemic by both customers and governments, could significantly affect the pace of recovery. The ultimate extent of the negative impact on revenues depends on the depth and duration of the economic contraction in the Southern Company system's service territory and cannot be determined at this time. See RESULTS OF OPERATIONS herein for information on COVID-19-related impacts on energy demand in the Southern Company system's service territory during 2021.

The level of future earnings for Southern Power's competitive wholesale electric business depends on numerous factors including the parameters of the wholesale market and the efficient operation of its wholesale generating assets; Southern Power's ability to execute its growth strategy through the development or acquisition of renewable facilities and other energy projects while containing costs; regulatory matters; customer creditworthiness; total electric generating capacity available in Southern Power's market areas; Southern Power's ability to successfully remarket capacity as current contracts expire; renewable portfolio standards; availability of federal and state ITCs and PTCs, which could be impacted by future tax legislation; transmission constraints; cost of generation from units within the Southern Company power pool; and operational limitations. See "Income Tax Matters" herein, Note 10 to the financial statements, and Note 15 to the financial statements under "Southern Power" for additional information.

The level of future earnings for Southern Company Gas' primary business of distributing natural gas and its complementary businesses in the gas pipeline investments and gas marketing services sectors depends on numerous factors. These factors include the natural gas distribution utilities' ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs, including those related to projected long-term demand growth, safety, system reliability and resilience, natural gas, and capital expenditures, including expanding and improving the natural gas distribution systems; the completion and subsequent operation of ongoing infrastructure and other construction projects; customer creditworthiness; certain city-wide bans on the use of natural gas in new construction; and Southern Company Gas' ability to re-contract storage rates at favorable prices. The volatility of natural gas prices has an impact on Southern Company Gas' customer rates, its long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services business to capture value from locational and seasonal spreads. Additionally, changes in commodity prices, primarily driven by tight gas supplies and diminished gas production, subject a portion of Southern Company Gas' operations to earnings variability. Additional economic factors may contribute to this environment. If current economic conditions continue to improve, the demand for natural gas may increase, which may cause natural gas prices to rise and drive higher volatility in the natural gas markets on a longer-term basis. Alternatively, a significant drop in oil and natural gas prices could lead to a consolidation of natural gas producers or reduced levels of natural gas production.

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Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, government incentives to reduce overall energy usage, the prices of electricity and natural gas, and the price elasticity of demand. Demand for electricity and natural gas in the Registrants' service territories is primarily driven by the pace of economic growth or decline that may be affected by changes in regional and global economic conditions, which may impact future earnings.

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 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.

As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of, or the sale of interests in, certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company. In addition, Southern Power and Southern Company Gas regularly consider and evaluate joint development arrangements as well as acquisitions and dispositions of businesses and assets as part of their business strategies. See Note 15 to the financial statements for additional information.

Environmental Matters

The Southern Company system's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, avian and other wildlife and habitat protection, and other natural resources. The Southern Company system maintains comprehensive environmental compliance and GHG strategies to assess both current and upcoming requirements and compliance costs associated with these environmental laws and regulations. New or revised environmental laws and regulations could further affect many areas of operations for the Subsidiary Registrants. The costs required to comply with environmental laws and regulations and to achieve stated goals, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, may impact future electric generating unit retirement and replacement decisions (which are subject to approval from the traditional electric operating companies' respective state PSCs), results of operations, cash flows, and/or financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as well as related upgrades to the Southern Company system's transmission and distribution (electric and natural gas) systems. A major portion of these costs is expected to be recovered through retail and wholesale rates, including existing ratemaking and billing provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed herein cannot be determined at this time and will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, the outcome of pending and/or future legal challenges, and the ability to continue recovering the related costs, through rates for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern Power.

Alabama Power and Mississippi Power recover environmental compliance costs through separate mechanisms, Rate CNP Compliance and the ECO Plan, respectively. Georgia Power's base rates include an ECCR tariff that allows for the recovery of environmental compliance costs. The natural gas distribution utilities of Southern Company Gas generally recover environmental remediation expenditures through rate mechanisms approved by their applicable state regulatory agencies. See Notes 2 and 3 to the financial statements for additional information.

Southern Power's PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations. Since Southern Power's units are generally newer natural gas and renewable generating facilities, costs associated with environmental compliance for these facilities have been less significant than for similarly situated coal or older natural gas generating facilities. Environmental, natural resource, and land use concerns, including the applicability of air quality limitations, the potential presence of wetlands or threatened and endangered species, the availability of water withdrawal rights, uncertainties regarding impacts such as increased light or noise, and concerns about potential adverse health impacts can, however, increase the cost of siting and operating any type of future facility. The impact of such laws, regulations, and other considerations on Southern Power and subsequent recovery through PPA provisions cannot be determined at this time.

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Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas, which could negatively affect results of operations, cash flows, and/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which may have the potential to affect their demand for electricity and natural gas.

Although the timing, requirements, and estimated costs could change as environmental laws and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are initiated or completed, estimated capital expenditures through 2026 based on the current environmental compliance strategy for the Southern Company system and the traditional electric operating companies are as follows:


	2022		2023		2024		2025		2026		Total
	(in millions)
Southern Company	$	98	$	111	$	146	$	72	$	58	$	485
Alabama Power	49		35		50		33		28		195
Georgia Power	37		75		91		34		25		262
Mississippi Power	12		1		5		5		5		28

These estimates do not include any costs associated with potential regulation of GHG emissions. See "Global Climate Issues" herein for additional information. The Southern Company system also anticipates substantial expenditures associated with ash pond closure and groundwater monitoring under the CCR Rule and related state rules, which are reflected in the applicable Registrants' ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" herein and Note 6 to the financial statements for additional information.

Environmental Laws and Regulations

Air Quality

The Southern Company system reduced SO2 and NOX air emissions by 99% and 93%, respectively, from 1990 to 2020. The Southern Company system reduced mercury air emissions by 98% from 2005 to 2020.

The EPA finalized regional haze regulations in 2005 and 2017. These regulations require states and various federal agencies to develop and implement plans to reduce pollutants that impair visibility and demonstrate reasonable progress toward the goal of restoring natural visibility conditions in certain areas, including national parks and wilderness areas. States were required to submit state implementation plans for the second 10-year planning period (2018 through 2028) by July 31, 2021; however, plans have not yet been submitted by the applicable states in the Southern Company system's service territory. These plans could require further reductions in particulate matter, SO2, and/or NOX, which could result in increased compliance costs at affected electric generating units.

Water Quality

In 2014, the EPA finalized requirements under Section 316(b) of the Clean Water Act (CWA) to regulate cooling water intake structures (CWIS) to minimize their effects on fish and other aquatic life at existing power plants. The regulation requires plant-specific studies to determine applicable CWIS changes to protect organisms. The results of these plant-specific studies, which are ongoing within the Southern Company system, are being submitted with each plant's next National Pollutant Discharge Elimination System (NPDES) permit cycle. The Southern Company system anticipates applicable CWIS changes may include fish-friendly CWIS screens with fish return systems and minor additions of monitoring equipment at certain plants. The impact of this rule will depend on the outcome of these plant-specific studies, any additional protective measures required to be incorporated into each plant's NPDES permit based on site-specific factors, and the outcome of any legal challenges.

In October 2020, the EPA published the final steam electric ELG reconsideration rule (ELG Reconsideration Rule), a reconsideration of the 2015 ELG rule's limits on bottom ash transport water and flue gas desulfurization wastewater that extends the latest applicability date for both discharges to December 31, 2025. The ELG Reconsideration Rule also updates the voluntary incentive program and provides new subcategories for low utilization electric generating units and electric generating units that will permanently cease coal combustion by 2028. As required by the ELG Reconsideration Rule, on October 13, 2021, Alabama Power and Georgia Power each submitted initial notices of planned participation (NOPP) for applicable units seeking to qualify for these subcategories.

Alabama Power submitted its NOPP to the Alabama Department of Environmental Management (ADEM) indicating plans to retire Plant Barry Unit 5 (700 MWs) and to cease using coal and begin operating solely on natural gas at Plant Barry Unit 4 (350

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MWs) and Plant Gaston Unit 5 (880 MWs). Alabama Power, as agent for SEGCO, indicated plans to retire Plant Gaston Units 1 through 4 (1,000 MWs). These plans are expected to be completed on or before the compliance date of December 31, 2028. The NOPP submittals are subject to the review of the ADEM. Retirement of Plant Barry Unit 5 could occur as early as 2023, subject to completion of the acquisition of the Calhoun Generating Station and certain operating conditions. See Notes 2 and 7 to the financial statements under "Alabama Power – Certificates of Convenience and Necessity" and "SEGCO," respectively, for additional information.

The assets for which Alabama Power has indicated retirement, due to early closure or repowering of the unit to natural gas, have net book values totaling approximately $1.5 billion (excluding capitalized asset retirement costs which are recovered through Rate CNP Compliance) at December 31, 2021. Based on an Alabama PSC order, Alabama Power is authorized to establish a regulatory asset to record the unrecovered investment costs, including the plant asset balance and the site removal and closure costs, associated with unit retirements caused by environmental regulations (Environmental Accounting Order). Under the Environmental Accounting Order, the regulatory asset would be amortized and recovered over an affected unit's remaining useful life, as established prior to the decision regarding early retirement, through Rate CNP Compliance. See Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance" and " – Environmental Accounting Order" for additional information.

Georgia Power submitted its NOPP to the Georgia Environmental Protection Division (EPD) indicating plans to retire Plant Wansley Units 1 and 2 (926 MWs based on 53.5% ownership), Plant Bowen Units 1 and 2 (1,400 MWs), and Plant Scherer Unit 3 (614 MWs based on 75% ownership) on or before the compliance date of December 31, 2028. Georgia Power intends to pursue compliance with the ELG Reconsideration Rule for Plant Scherer Units 1 and 2 (137 MWs based on 8.4% ownership) through the voluntary incentive program by no later than December 31, 2028. Georgia Power intends to comply with the ELG Rules for Plant Bowen Units 3 and 4 through the generally applicable requirements by December 31, 2025; therefore, no NOPP submission was required for these units. The NOPP submittals and generally applicable requirements are subject to the review of the Georgia EPD.

The units for which Georgia Power has indicated early retirement plans have net book values totaling approximately $2.2 billion (excluding capitalized asset retirement costs which are recovered through the ECCR tariff) at December 31, 2021. A final decision regarding the future operation of Georgia Power's impacted units and the timing of any retirements are subject to review by the Georgia PSC as a part of Georgia Power's 2022 IRP proceeding. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plan" for additional information.

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

The ELG Reconsideration Rule is expected to require capital expenditures and increased operational costs for the traditional electric operating companies and SEGCO. However, the ultimate impact of the ELG Reconsideration Rule will depend on the Southern Company system's final assessment of compliance options, the incorporation of these assessments into each of the traditional electric operating company's IRP process, the incorporation of these new requirements into each plant's NPDES permit, and the outcome of legal challenges. The ELG Reconsideration Rule has been challenged by several environmental organizations and the cases have been consolidated in the U.S. Court of Appeals for the Fourth Circuit. The case is being held in abeyance while the EPA undertakes a new rulemaking to revise the ELG Reconsideration Rule. A proposed rule is expected in the fall of 2022. Any revisions could require changes in the traditional electric operating companies' compliance strategies.

Coal Combustion Residuals

In 2015, the EPA finalized non-hazardous solid waste regulations for the management and disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments (ash ponds) at active electric generating power plants. The CCR Rule requires landfills and ash ponds to be evaluated against a set of performance criteria and potentially closed if certain criteria are not met. Closure of existing landfills and ash ponds requires installation of equipment and infrastructure to manage CCR in accordance with the CCR Rule. In addition to the federal CCR Rule, the States of Alabama and Georgia finalized state regulations regarding the management and disposal of CCR within their respective states. In 2019, the State of Georgia received partial approval from the EPA for its state CCR permitting program. The State of Mississippi has not developed a state CCR permit program.

The Holistic Approach to Closure: Part A rule, finalized in August 2020, revised the deadline to stop sending CCR and non-CCR wastes to unlined surface impoundments to April 11, 2021 and established a process for the EPA to approve extensions to the deadline. The traditional electric operating companies stopped sending CCR and non-CCR wastes to their unlined impoundments prior to April 11, 2021 and, therefore, did not submit requests for extensions. On January 11, 2022, the EPA proposed determinations on deadline extension requests for other non-affiliated facilities, which reflected its positions on a variety of CCR Rule compliance requirements including closure standards, groundwater monitoring, and corrective action. The traditional electric operating companies are in the process of reviewing these determinations to determine how the EPA's current positions may

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impact their closure plans and groundwater monitoring efforts. The ultimate impact of the EPA's announced positions on the traditional electric operating companies cannot be determined at this time, but may be material.

Based on requirements for closure and monitoring of landfills and ash ponds pursuant to the CCR Rule and applicable 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 closure methodologies, schedules, and/or costs 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 FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements," Note 2 to the financial statements under "Georgia Power – Rate Plans," and Note 6 to the financial statements for additional information.

Environmental Remediation

The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and Southern Company Gas conduct studies to determine the extent of any required cleanup and have recognized the estimated costs to clean up known impacted sites in their financial statements. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia (which represent substantially all of Southern Company Gas' accrued remediation costs) have all received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental remediation costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies. The traditional electric operating companies and Southern Company Gas may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under "Environmental Remediation" for additional information.

Global Climate Issues

In 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule), which would have required states to develop unit-specific CO2 emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. On January 19, 2021, the U.S. Court of Appeals for the District of Columbia Circuit vacated and remanded the ACE Rule back to the EPA. On October 29, 2021, the U.S. Supreme Court granted four petitions for writs of certiorari asking the court to review the District of Columbia Circuit's decision. The U.S. Supreme Court's review will focus on the extent of the EPA's authority to regulate GHG emissions from the power sector under Section 111(d) of the Clean Air Act.

On February 19, 2021, the United States officially rejoined the Paris Agreement. The Paris Agreement establishes a non-binding universal framework for addressing GHG emissions based on nationally determined emissions reduction contributions and sets in place a process for tracking progress towards the goals every five years. On April 22, 2021 President Biden announced a new target for the United States to achieve a 50% to 52% reduction in economy-wide GHG emissions from 2005 levels by 2030. The target was accepted by the United Nations as the United States' nationally determined emissions reduction contribution under the Paris Agreement.

Additional GHG policies, including legislation, may emerge in the future requiring the United States to transition to a lower GHG emitting economy; however, associated impacts are currently unknown. The Southern Company system has transitioned from an electric generating mix of 70% coal and 15% natural gas in 2007 to a mix of 22% coal and 48% natural gas in 2021. This transition has been supported in part by the Southern Company system retiring over 5,600 MWs of coal-fired generating capacity since 2010 and converting over 3,400 MWs of generating capacity from coal to natural gas since 2015, as well as constructing and/or acquiring over 11,000 MWs of renewable resource capacity since 2010. See "Environmental Laws and Regulations – Water Quality" herein for information on plans to retire or convert to natural gas additional coal-fired generating capacity. In addition, Southern Company Gas has replaced over 6,000 miles of pipe material that was more prone to fugitive emissions (unprotected steel and cast-iron pipe), resulting in mitigation of more than 3.3 million metric tons of CO2 equivalents from its natural gas distribution system since 1998.

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The following table provides the Registrants' 2020 and preliminary 2021 GHG emissions based on equity share of facilities:


	2020	Preliminary 2021
	(in million metric tons of CO2 equivalent)
Southern Company(*)	75	82
Alabama Power(*)	28	34
Georgia Power	21	23
Mississippi Power	8	8
Southern Power	12	11
Southern Company Gas(*)	1	1

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

Southern Company system management has established an intermediate goal of a 50% reduction in GHG emissions from 2007 levels by 2030 and a long-term goal of net zero GHG emissions by 2050. Based on the preliminary 2021 emissions, the Southern Company system has achieved an estimated GHG emission reduction of 47% since 2007. In 2020, the COVID-19 pandemic resulted in reduced electricity usage by customers, which led to a higher than expected decline in GHG emissions. In 2021, increased customer demand combined with increased utilization of the coal generating fleet due to higher natural gas prices resulted in an increase in GHG emissions from 2020 levels. Southern Company system management expects to achieve sustained GHG emissions reductions of at least 50% as early as 2025. Southern Company system management, working with applicable regulators, plans to transition its generating fleet in a manner responsible to customers, communities, employees, and other stakeholders. Achievement of these goals is dependent on many factors, including natural gas prices and the pace and extent of development and deployment of low- to no-GHG energy technologies and negative carbon concepts. Southern Company system management plans to continue to pursue a diverse portfolio including low-carbon and carbon-free resources and energy efficiency resources; continue to transition the Southern Company system's generating fleet and make the necessary related investments in transmission and distribution systems; continue its research and development with a particular focus on technologies that lower GHG emissions, including methods of removing carbon from the atmosphere; and constructively engage with policymakers, regulators, investors, customers, and other stakeholders to support outcomes leading to a net zero future.

Regulatory Matters

See OVERVIEW – "Recent Developments" herein and Note 2 to the financial statements for a discussion of regulatory matters related to Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas, including items that could impact the applicable registrants' future earnings, cash flows, and/or financial condition.

Construction Programs

The Subsidiary Registrants are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, expanding and improving the electric transmission and electric and natural gas distribution systems, and undertaking projects to comply with environmental laws and regulations.

For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information. Also see Note 2 to the financial statements under "Alabama Power – Certificates of Convenience and Necessity" for information regarding Alabama Power's construction of Plant Barry Unit 8.

See Note 15 to the financial statements under "Southern Power" for information about costs relating to Southern Power's construction of renewable energy facilities.

Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" for additional information on Southern Company Gas' construction program.

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See FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" herein for additional information regarding the Registrants' capital requirements for their construction programs, including estimated totals for each of the next five years.

Southern Power's Power Sales Agreements

General

Southern Power has PPAs with some of the traditional electric operating companies, other investor-owned utilities, IPPs, municipalities, and other load-serving entities, as well as commercial and industrial customers. The PPAs are expected to provide Southern Power with a stable source of revenue during their respective terms.

Many of Southern Power's PPAs have provisions that require Southern Power or the counterparty to post collateral or an acceptable substitute guarantee if (i) S&P or Moody's downgrades the credit ratings of the respective company to an unacceptable credit rating, (ii) the counterparty is not rated, or (iii) the counterparty fails to maintain a minimum coverage ratio.

Southern Power is working to maintain and expand its share of the wholesale markets. During 2021, Southern Power continued to be successful in remarketing up to 2,025 MWs of annual natural gas generation capacity to load-serving entities through several PPAs extending over the next 16 years. Market demand is being driven by load-serving entities replacing expired purchase contracts and/or retired generation, as well as planning for future growth.

Natural Gas

Southern Power's electricity sales from natural gas facilities are primarily through long-term PPAs that consist of two types of agreements. The first type, referred to as a unit or block sale, is a customer purchase from a dedicated generating unit where all or a portion of the generation from that unit is reserved for that customer. Southern Power typically has the ability to serve the unit or block sale customer from an alternate resource. The second type, referred to as requirements service, provides that Southern Power serve the customer's capacity and energy requirements from a combination of the customer's own generating units and from Southern Power resources not dedicated to serve unit or block sales. Southern Power has rights to purchase power provided by the requirements customers' resources when economically viable.

As a general matter, substantially all of the PPAs provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel or purchased power relating to the energy delivered under such PPAs. To the extent a particular generating facility does not meet the operational requirements contemplated in the PPAs, Southern Power may be responsible for excess fuel costs. With respect to fuel transportation risk, most of Southern Power's PPAs provide that the counterparties are responsible for the availability of fuel transportation to the particular generating facility.

Capacity charges that form part of the PPA payments are designed to recover fixed and variable operation and maintenance costs based on dollars-per-kilowatt year. In general, to reduce Southern Power's exposure to certain operation and maintenance costs, Southern Power has LTSAs. See Note 1 to the financial statements under "Long-Term Service Agreements" for additional information.

Solar and Wind

Income Tax Matters

Consolidated Income Taxes

The impact of certain tax events at Southern Company and/or its other subsidiaries can, and does, affect each Registrant's ability to utilize certain tax credits. See "Tax Credits" and ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Accounting for Income Taxes" herein and Note 10 to the financial statements for additional information.

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Tax Credits

The Tax Reform Legislation, as modified by the 2021 Consolidated Appropriations Act signed into law in December 2020, retained solar energy incentives as described in the following table:


ITC Percentage			Date Project Commenced Construction
30%			Prior to December 31, 2019
26%			From 2020 through 2022
22%			During 2023

A permanent 10% ITC will remain for projects that commence construction on or after January 1, 2024 and any projects placed in service after December 31, 2025, regardless of when construction began.

In addition, various tax legislation has retained or extended wind energy incentives as described in the following table:


PTC Percentage			Year Project Commenced Construction
100%			2016
80%			2017
60%			2018
40%			2019
60%			2020 or 2021
0%			2022 and after

Southern Company has received ITCs and PTCs in connection with investments in solar, wind, fuel cell facilities, and battery energy storage facilities (co-located with existing solar facilities) primarily at Southern Power and Georgia Power.

Southern Power's ITCs relate to its investment in new solar facilities and battery energy storage facilities (co-located with existing solar facilities) that are acquired or constructed and its PTCs relate to the first 10 years of energy production from its wind facilities, which have had, and may continue to have, a material impact on Southern Power's cash flows and net income. At December 31, 2021, Southern Company and Southern Power had approximately $1.2 billion and $0.8 billion, respectively, of unutilized federal ITCs and PTCs, which are currently expected to be fully utilized by 2024, but could be further delayed. Since 2018, Southern Power has been utilizing tax equity partnerships for wind, solar, and battery energy storage projects, where the tax partner takes significantly all of the respective federal tax benefits. These tax equity partnerships are consolidated in Southern Company's and Southern Power's financial statements using the HLBV methodology to allocate partnership gains and losses. See Note 1 to the financial statements under "General" for additional information on the HLBV methodology and Note 1 to the financial statements under "Income Taxes" and Note 10 to the financial statements under "Deferred Tax Assets and Liabilities – Tax Credit Carryforwards" and "Effective Tax Rate" for additional information regarding utilization and amortization of credits and the tax benefit related to associated basis differences.

General Litigation and Other Matters

The Registrants are involved in various matters being litigated and/or regulatory and other matters that could affect future earnings, cash flows, and/or financial condition. The ultimate outcome of such pending or potential litigation against each Registrant and any subsidiaries or regulatory and other matters cannot be determined at this time; however, for current proceedings and/or matters not specifically reported herein or in Notes 2 and 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings and/or matters would have a material effect on such Registrant's financial statements. See Notes 2 and 3 to the financial statements for a discussion of various contingencies, including matters being litigated, regulatory matters, and other matters which may affect future earnings potential.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

The Registrants prepare their financial statements in accordance with GAAP. Significant accounting policies are described in the notes to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the results of operations and related disclosures of the applicable Registrants (as indicated in the section descriptions herein). Different assumptions and measurements could produce estimates that are significantly different from those recorded in the

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financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.

Utility Regulation (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas)

The traditional electric operating companies and the natural gas distribution utilities are subject to retail regulation by their respective state PSCs or other applicable state regulatory agencies and wholesale regulation by the FERC. These regulatory agencies set the rates the traditional electric operating companies and the natural gas distribution utilities are permitted to charge customers based on allowable costs, including a reasonable ROE. As a result, the traditional electric operating companies and the natural gas distribution utilities apply accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards for rate regulated entities also impacts their financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the traditional electric operating companies and the natural gas distribution utilities; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the results of operations and financial condition of the applicable Registrants than they would on a non-regulated company.

Revenues related to regulated utility operations as a percentage of total operating revenues in 2021 for the applicable Registrants were as follows: 88% for Southern Company, 98% for Alabama Power, 96% for Georgia Power, 99.7% for Mississippi Power, and 84% for Southern Company Gas.

As reflected in Note 2 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the financial statements of the applicable Registrants.

Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4

(Southern Company and Georgia Power)

In 2016, the Georgia PSC approved the Vogtle Cost Settlement Agreement, which resolved certain prudency matters in connection with Georgia Power's fifteenth VCM report. In 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor, as well as a modification of the Vogtle Cost Settlement Agreement. The Georgia PSC's related order stated that under the modified Vogtle Cost Settlement Agreement, (i) none of the $3.3 billion of costs incurred through December 31, 2015 should be disallowed as imprudent; (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) 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; (iv) Georgia Power would have the burden of proof to show that any capital costs above $5.68 billion were prudent; (v) Georgia Power's total project capital cost forecast of $7.3 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds) was found reasonable and did not represent a cost cap; and (vi) a prudence proceeding on cost recovery will occur subsequent to achieving fuel load for Unit 4. In its 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.

As of December 31, 2021, Georgia Power revised its total project capital cost forecast to $10.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). This forecast includes construction contingency of $150 million and is based on projected in-service dates at the end of the first quarter 2023 and the fourth quarter 2023 for Units 3 and 4, respectively. Since 2018, established construction contingency and additional costs totaling $2.2 billion have been assigned to the base capital cost forecast. Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power will not seek rate recovery for 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 and has not sought rate recovery for the construction contingency costs. After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these

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matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded total pre-tax charges to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018; $149 million ($111 million after tax) and $176 million ($131 million after tax) in the second quarter and the fourth quarter 2020, respectively; and $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) in the first quarter 2021, the second quarter 2021, the third quarter 2021, and the fourth quarter 2021, respectively.

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 (as defined in Note 2 to the financial statements under "Georgia Power – Nuclear Construction – Joint Owner Contracts") 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. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction – Joint Owner Contracts" for additional information on the Global Amendments.

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. 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.

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. In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction and testing activities at Plant Vogtle Units 3 and 4.

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. Findings resulting from such 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. 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.

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2, 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 above, 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.

Given the significant complexity involved in estimating the future costs to complete construction and start-up of Plant Vogtle Units 3 and 4 and the significant management judgment necessary to assess the related uncertainties surrounding future rate recovery of any projected cost increases, as well as the potential impact on results of operations and cash flows, Southern Company and Georgia Power consider these items to be critical accounting estimates. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information.

Accounting for Income Taxes (Southern Company, Mississippi Power, Southern Power, and Southern Company Gas)

The consolidated income tax provision and deferred income tax assets and liabilities, as well as any unrecognized tax benefits and valuation allowances, require significant judgment and estimates. These estimates are supported by historical tax return data, reasonable projections of taxable income, the ability and intent to implement tax planning strategies if necessary, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. The effective tax rate reflects the statutory tax rates and calculated apportionments for the various states in which the Southern Company system operates.

Southern Company files a consolidated federal income tax return and the Registrants file various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and each subsidiary is allocated an amount of tax similar to that which would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability. Certain deductions and credits can be limited or utilized at the consolidated or combined level resulting in tax credit and/or state NOL carryforwards that would not otherwise result on a stand-alone basis. Utilization of these carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of Southern Company's and its subsidiaries' current financial position and results of operations, including currently available information about future years, to estimate when future taxable income will be realized.

Current and deferred state income tax liabilities and assets are estimated based on laws of multiple states that determine the income to be apportioned to their jurisdictions. States have various filing methodologies and utilize specific formulas to calculate the apportionment of taxable income. The calculation of deferred state taxes considers apportionment factors and filing methodologies that are expected to apply in future years. The apportionments and methodologies which are ultimately finalized in a manner inconsistent with expectations could have a material effect on the financial statements of the applicable Registrants.

Given the significant judgment involved in estimating tax credit and/or state NOL carryforwards and multi-state apportionments for all subsidiaries, the applicable Registrants consider deferred income tax liabilities and assets to be critical accounting estimates.

Asset Retirement Obligations (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas)

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). 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.

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associated with the Southern Company system's rail lines and natural gas pipelines. However, liabilities for the removal of these assets have not been recorded because the settlement timing for certain retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these retirement obligations will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.

The cost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule and the related state rules. The traditional electric operating companies have periodically updated, and expect to continue periodically updating, their related cost estimates and ARO liabilities for each CCR unit as additional information related to these assumptions becomes available. Some of these updates have been, and future updates may be, material. See Note 6 to the financial statements for additional information, including increases to AROs related to ash ponds recorded during 2021 by certain Registrants.

Given the significant judgment involved in estimating AROs, the applicable Registrants consider the liabilities for AROs to be critical accounting estimates.

Pension and Other Postretirement Benefits (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas)

The applicable Registrants' calculations of pension and other postretirement benefits expense are dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term rate of return (LRR) on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the applicable Registrants believe the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect their pension and other postretirement benefit costs and obligations.

Key elements in determining the applicable Registrants' pension and other postretirement benefit expense are the LRR and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. For purposes of determining the applicable Registrants' liabilities related to the pension and other postretirement benefit plans, Southern Company discounts the future related cash flows using a single-point discount rate for each plan developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. The discount rate assumption impacts both the service cost and non-service costs components of net periodic benefit costs as well as the projected benefit obligations.

The LRR on pension and other postretirement benefit plan assets is based on Southern Company's investment strategy, as described in Note 11 to the financial statements, historical experience, and expectations that consider external actuarial advice, and represents the average rate of earnings expected over the long term on the assets invested to provide for anticipated future benefit payments. Southern Company determines the amount of the expected return on plan assets component of non-service costs by applying the LRR of various asset classes to Southern Company's target asset allocation. The LRR only impacts the non-service costs component of net periodic benefit costs for the following year and is set annually at the beginning of the year.

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The following table illustrates the sensitivity to changes in the applicable Registrants' long-term assumptions with respect to the discount rate, salary increases, and the long-term rate of return on plan assets:

Increase/(Decrease) in

25 Basis Point Change in:

Total Benefit Expense for 2022

Projected Obligation for Pension Plan at December 31, 2021

Projected Obligation for

Other Postretirement

Benefit Plans at December 31, 2021

(in millions)

Discount rate:

Southern Company

$44/$(43)

$610/$(575)

$53/$(51)

Alabama Power

$12/$(12)

$149/$(140)

$14/$(13)

Georgia Power

$12/$(12)

$180/$(170)

$18/$(17)

Mississippi Power

$2/$(2)

$27/$(26)

$2/$(2)

Southern Company Gas

$–/$–

$40/$(38)

$6/$(6)

Salaries:

Southern Company

$26/$(24)

$131/$(127)

$–/$–

Alabama Power

$8/$(7)

$37/$(36)

$–/$–

Georgia Power

$7/$(7)

$37/$(36)

$–/$–

Mississippi Power

$1/$(1)

$6/$(6)

$–/$–

Southern Company Gas

$–/$–

$2/$(2)

$–/$–

Long-term return on plan assets:

Southern Company

$41/$(41)

N/A

Alabama Power

$10/$(10)

N/A

Georgia Power

$13/$(13)

N/A

Mississippi Power

$2/$(2)

N/A

Southern Company Gas

$3/$(3)

N/A

See Note 11 to the financial statements for additional information regarding pension and other postretirement benefits.

Asset Impairment (Southern Company, Southern Power, and Southern Company Gas)

Goodwill (Southern Company and Southern Company Gas)

The acquisition method of accounting requires the assets acquired and liabilities assumed to be recorded at the date of acquisition at their respective estimated fair values. The applicable Registrants have recognized goodwill as of the date of their acquisitions, as a residual over the fair values of the identifiable net assets acquired. Goodwill is tested for impairment at the reporting unit level on an annual basis in the fourth quarter of the year as well as on an interim basis as events and changes in circumstances occur, including, but not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. A reporting unit is the operating segment, or a business one level below the operating segment (a component), if discrete financial information is prepared and regularly reviewed by management. Components are aggregated if they have similar economic characteristics.

As part of the impairment tests, the applicable Registrant may perform an initial qualitative assessment to determine whether it is more likely than not that the fair value of each reporting unit is less than its carrying amount before applying the quantitative goodwill impairment test. If the applicable Registrant elects to perform the qualitative assessment, it evaluates relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market conditions, cost factors, financial performance, entity specific events, and events specific to each reporting unit. If the applicable Registrant determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, or it elects not to perform a qualitative assessment, it compares the fair value of the reporting unit to its carrying value to determine if the fair value is greater than its carrying value.

Goodwill for Southern Company and Southern Company Gas was $5.3 billion and $5.0 billion, respectively, at December 31, 2021. For its 2021 annual impairment test, Southern Company Gas performed the quantitative assessment and confirmed that the

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fair value of all of its reporting units with goodwill exceeded their carrying value. For its 2020 and 2019 annual impairment tests, Southern Company Gas performed the qualitative assessment and determined that it was more likely than not that the fair value of all of its reporting units with goodwill exceeded their carrying amounts, and therefore no quantitative assessment was required. For its annual impairment tests for PowerSecure, Southern Company performed the quantitative assessment, which resulted in the fair value of goodwill at PowerSecure exceeding its carrying value in all years presented. However, Southern Company recorded goodwill impairment charges totaling $34 million in 2019 as a result of its decision to sell certain PowerSecure business units. See Note 15 to the financial statements under "Southern Company" for additional information. The COVID-19 pandemic and the related impacts on the worldwide economy have disrupted supply chains, reduced labor availability and productivity, and reduced economic activity in the United States. These effects have had a variety of adverse impacts on Southern Company and its subsidiaries, including PowerSecure. If these factors continue to negatively affect the operating results of PowerSecure and its businesses, a portion of the associated goodwill of $263 million may become impaired. The ultimate outcome of this matter cannot be determined at this time.

The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can significantly impact the applicable Registrant's results of operations. Fair values and useful lives are determined based on, among other factors, the expected future period of benefit of the asset, the various characteristics of the asset, and projected cash flows. As the determination of an asset's fair value and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, the applicable Registrants consider these estimates to be critical accounting estimates.

See Note 1 to the financial statements under "Goodwill and Other Intangible Assets and Liabilities" for additional information regarding the applicable Registrants' goodwill.

Long-Lived Assets (Southern Company, Southern Power, and Southern Company Gas)

The applicable Registrants assess their other long-lived assets for impairment whenever events or changes in circumstances indicate that an asset's carrying amount may not be recoverable. If an indicator exists, the asset is tested for recoverability by comparing the asset carrying value to the sum of the undiscounted expected future cash flows directly attributable to the asset's use and eventual disposition. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded equal to the difference between the carrying value and the fair value of the asset. In addition, when assets are identified as held for sale, an impairment loss is recognized to the extent the carrying value of the assets or asset group exceeds their fair value less cost to sell. A high degree of judgment is required in developing estimates related to these evaluations, which are based on projections of various factors, some of which have been quite volatile in recent years. Impairments of long-lived assets of the traditional electric utilities and natural gas distribution utilities are generally related to specific regulatory disallowances.

Southern Power's investments in long-lived assets are primarily generation assets. Excluding the natural gas distribution utilities, Southern Company Gas' investments in long-lived assets are primarily natural gas transportation and storage facility assets, whether in service or under construction.

For Southern Power, examples of impairment indicators could include significant changes in construction schedules, current period losses combined with a history of losses or a projection of continuing losses, a significant decrease in market prices, the inability to remarket generating capacity for an extended period, the unplanned termination of a customer contract, or the inability of a customer to perform under the terms of the contract. For Southern Company Gas, examples of impairment indicators could include, but are not limited to, significant changes in the U.S. natural gas storage market, construction schedules, current period losses combined with a history of losses or a projection of continuing losses, a significant decrease in market prices, the inability to renew or extend customer contracts or the inability of a customer to perform under the terms of the contract, attrition rates, or the inability to deploy a development project.

As the determination of the expected future cash flows generated from an asset, an asset's fair value, and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, the applicable Registrants consider these estimates to be critical accounting estimates.

During 2021 and 2020, Southern Company recorded impairment charges totaling $7 million ($6 million after tax) and $206 million ($105 million after tax), respectively, related to its leveraged lease investments. During 2021, Southern Company Gas recorded total pre-tax charges of $84 million ($67 million after tax) related to its equity method investment in the PennEast Pipeline project. During 2019, Southern Company Gas recorded pre-tax impairment charges of $91 million ($69 million after-tax) related to a natural gas storage facility and approximately $24 million ($17 million after tax) related to the sale of Pivotal LNG. See Notes 7 and 9 to the financial statements under "Southern Company Gas" and "Southern Company Leveraged Lease," respectively, and Note 15 to the financial statements for additional information on recent asset impairments.

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Revenue Recognition (Southern Power)

Southern Power's power sale transactions, which include PPAs, are classified in one of four general categories: leases, non-derivatives or normal sale derivatives, derivatives designated as cash flow hedges, and derivatives not designated as hedges. Southern Power's revenues are dependent upon significant judgments used to determine the appropriate transaction classification, which must be documented upon the inception of each contract. The two categories with the most judgment required for Southern Power are described further below.

Lease Transactions

Southern Power considers the terms of a sales contract to determine whether it should be accounted for as a lease. A contract is or contains a lease if the contract conveys the right to control the use of identified property, plant, or equipment for a period of time in exchange for consideration. If the contract meets the criteria for a lease, Southern Power performs further analysis to determine whether the lease is classified as operating, financing, or sales-type. Generally, Southern Power's power sales contracts that are determined to be leases are accounted for as operating leases and the capacity revenue is recognized on a straight-line basis over the term of the contract and is included in Southern Power's operating revenues. Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered. For those contracts that are determined to be sales-type leases, capacity revenues are recognized by accounting for interest income on the net investment in the lease and are included in Southern Power's operating revenues. See Note 9 to the financial statements for additional information.

Non-Derivative and Normal Sale Derivative Transactions

If the power sales contract is not classified as a lease, Southern Power further considers whether the contract meets the definition of a derivative. If the contract does meet the definition of a derivative, Southern Power will assess whether it can be designated as a normal sale contract. The determination of whether a contract can be designated as a normal sale contract requires judgment, including whether the sale of electricity involves physical delivery in quantities within Southern Power's available generating capacity and that the purchaser will take quantities expected to be used or sold in the normal course of business.

Contracts that do not meet the definition of a derivative or are designated as normal sales are accounted for as executory contracts. For contracts that have a capacity charge, the revenue is generally recognized in the period that it becomes billable. Revenues related to energy and ancillary services are recognized in the period the energy is delivered or the service is rendered. See Note 4 to the financial statements for additional information.

Acquisition Accounting (Southern Power)

Southern Power may acquire generation assets as part of its overall growth strategy. At the time of an acquisition, Southern Power will assess if these assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, 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, primarily related to acquired PPAs). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition. The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired.

Determining the fair value of assets acquired and liabilities assumed requires management judgment and Southern Power may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions, and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred by Southern Power for potential or successful acquisitions are expensed as incurred.

See Note 13 to the financial statements for additional fair value information and Note 15 to the financial statements for additional information on recent acquisitions.

Variable Interest Entities (Southern Power)

Southern Power enters into partnerships with varying ownership structures. Upon entering into these arrangements, membership interests and other variable interests are evaluated to determine if the legal entity is a VIE. If the legal entity is a VIE, Southern Power will assess if it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE, making it the primary beneficiary. Making this determination may require significant management judgment.

If Southern Power is the primary beneficiary and is considered to have a controlling ownership, the assets, liabilities, and results of operations of the entity are consolidated. If Southern Power is not the primary beneficiary, the legal entity is generally accounted for under the equity method of accounting. Southern Power reconsiders its conclusions as to whether the legal entity is

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a VIE and whether it is the primary beneficiary for events that impact the rights of variable interests, such as ownership changes in membership interests.

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.

Contingent Obligations (All Registrants)

The Registrants are subject to a number of federal and state laws and regulations, as well as other factors and conditions that subject them to environmental, litigation, and other risks. See FUTURE EARNINGS POTENTIAL herein and Notes 2 and 3 to the financial statements for more information regarding certain of these contingencies. The Registrants periodically evaluate their exposure to such risks and record reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the results of operations, cash flows, or financial condition of the Registrants.

Recently Issued Accounting Standards

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 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 FINANCIAL CONDITION AND LIQUIDITY – "Overview" and "Financing Activities" herein and Note 14 to the financial statements under "Interest Rate Derivatives" for additional information.

FINANCIAL CONDITION AND LIQUIDITY

Overview

The financial condition of each Registrant remained stable at December 31, 2021. The Registrants' cash requirements primarily consist of funding ongoing operations, including unconsolidated subsidiaries, as well as common stock dividends, capital expenditures, and debt maturities. Southern Power's cash requirements also include distributions to noncontrolling interests. Capital expenditures and other investing activities for the traditional electric operating companies include investments to build new generation facilities to meet projected long-term demand requirements and to replace units being retired as part of the generation fleet transition, to maintain existing generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing generating units and closures of ash ponds, to expand and improve transmission and distribution facilities, and for restoration following major storms. Southern Power's capital expenditures and other investing activities may include acquisitions or new construction associated with its overall growth strategy and to maintain its existing generation fleet's performance. Southern Company Gas' capital expenditures and other investing activities include investments to meet projected long-term demand requirements, to maintain existing natural gas distribution systems as well as to update and expand these systems, and to comply with environmental regulations. See "Cash Requirements" herein for additional information.

Operating cash flows provide a substantial portion of the Registrants' cash needs. During 2021, Southern Power utilized tax credits, which provided $288 million in operating cash flows. For the three-year period from 2022 through 2024, each Registrant's

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projected stock dividends, capital expenditures, and debt maturities, as well as distributions to noncontrolling interests for Southern Power, are expected to exceed its operating cash flows. Southern Company plans to finance future cash needs in excess of its operating cash flows through one or more of the following: accessing borrowings from financial institutions, issuing debt and hybrid securities in the capital markets, and/or through its stock plans. Each Subsidiary Registrant plans to finance its future cash needs in excess of its operating cash flows primarily through external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. In addition, Southern Power plans to utilize tax equity partnership contributions. The Registrants plan to use commercial paper to manage seasonal variations in operating cash flows and for other working capital needs and continue to monitor their access to short-term and long-term capital markets as well as their bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital" and "Financing Activities" herein for additional information.

To facilitate an orderly transition from LIBOR to alternative benchmark rate(s), the Registrants have established an initiative to assess and mitigate risks associated with the discontinuation of LIBOR. As part of this initiative, several alternative benchmark rates have been, and continue to be, evaluated and implemented. Substantially all of the Registrants' credit facilities allow for LIBOR to be phased out and replaced with the Secured Overnight Financing Rate and interest rate derivatives address the LIBOR transition through the adoption of the ISDA 2020 IBOR Fallbacks Protocol and subsequent amendments. None of the Registrants expects the transition from LIBOR to have a material impact.

The Registrants' investments in their qualified pension plans and Alabama Power's and Georgia Power's investments in their nuclear decommissioning trust funds increased in value at December 31, 2021 as compared to December 31, 2020. No contributions to the qualified pension plan were made during 2021 and no mandatory contributions to the qualified pension plans are anticipated during 2022. See Notes 6 and 11 to the financial statements under "Nuclear Decommissioning" and "Pension Plans," respectively, for additional information.

At the end of 2021, the market price of Southern Company's common stock was $68.58 per share (based on the closing price as reported on the NYSE) and the book value was $26.30 per share, representing a market-to-book value ratio of 261%, compared to $61.43, $26.48, and 232%, respectively, at the end of 2020.

Cash Requirements

Capital Expenditures

Total estimated capital expenditures, including LTSA and nuclear fuel commitments, for the Registrants through 2026 based on their current construction programs are as follows:


	2022		2023		2024		2025		2026
	(in billions)
Southern Company(a)(b)(c)	$	8.7	$	8.6	$	7.5	$	7.2	$	7.1
Alabama Power(a)	1.9		1.8		1.7		1.7		1.7
Georgia Power(b)	4.4		4.5		3.5		3.5		3.4
Mississippi Power	0.3		0.3		0.2		0.2		0.2
Southern Power(c)	0.1		0.2		0.1		0.1		0.1
Southern Company Gas	1.7		1.7		1.8		1.7		1.7

(a)Includes expenditures of approximately $0.3 billion and $0.1 billion for the construction of Plant Barry Unit 8 in 2022 and 2023, respectively. See Note 2 to the financial statements under "Alabama Power" for additional information.

(b)Includes expenditures of approximately $1.3 billion and $0.9 billion for the construction of Plant Vogtle Units 3 and 4 in 2022 and 2023, respectively.

(c)Excludes approximately $0.3 billion in 2022, $0.5 billion in 2023, and $0.8 billion per year for 2024 through 2026 for Southern Power's planned acquisitions and placeholder growth, which may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy.

These capital expenditures include estimates to comply with environmental laws and regulations, but do not include any potential compliance costs associated with any future regulation of CO2 emissions from fossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters" herein for additional information. At December 31, 2021, significant purchase commitments were outstanding in connection with the Registrants' construction programs.

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Southern Company and Subsidiary Companies 2021 Annual Report

The traditional electric operating companies also anticipate expenditures associated with closure and monitoring of ash ponds and landfills in accordance with the CCR Rule and the related state rules, which are reflected in the applicable Registrants' ARO liabilities. The cost estimates for Alabama Power and Mississippi Power are based on closure-in-place for all ash ponds. The cost estimates for Georgia Power are based on a combination of closure-in-place for some ash ponds and closure by removal for others. These anticipated costs are likely to change, and could change materially, as assumptions and details pertaining to closure are refined and compliance activities continue. Current estimates of these costs through 2026 are provided in the table below. Material expenditures in future years for ARO settlements will also be required for ash ponds, nuclear decommissioning (for Alabama Power and Georgia Power), and other liabilities reflected in the applicable Registrants' AROs, as discussed further in Note 6 to the financial statements. Also see FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein.


	2022		2023		2024		2025		2026
	(in millions)
Southern Company	$	687	$	688	$	767	$	907	$	888
Alabama Power	320		330		346		364		299
Georgia Power	317		307		368		489		555
Mississippi Power	16		20		23		30		16

The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation and/or regulation; the cost, availability, and efficiency of construction labor, equipment, and materials; project scope and design changes; abnormal weather; delays in construction due to judicial or regulatory action; storm impacts; and the cost of capital. The continued impacts of the COVID-19 pandemic could also impair the ability to develop, construct, and operate facilities, as discussed further in Item 1A herein. In addition, there can be no assurance that costs related to capital expenditures and AROs will be fully recovered. Additionally, expenditures associated with Southern Power's planned acquisitions may vary due to market opportunities and the execution of its growth strategy. See Note 15 to the financial statements under "Southern Power" for additional information regarding Southern Power's plant acquisitions and construction projects.

The construction program of Georgia Power includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.

See FUTURE EARNINGS POTENTIAL – "Construction Programs" herein for additional information.

Other Significant Cash Requirements

Long-term debt maturities and the interest payable on long-term debt each represent a significant cash requirement for the Registrants. See Note 8 to the financial statements for information regarding the Registrants' long-term debt at December 31, 2021, the weighted average interest rate applicable to each long-term debt category, and a schedule of long-term debt maturities over the next five years. The Registrants plan to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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Southern Company and Subsidiary Companies 2021 Annual Report

Fuel and purchased power costs represent a significant component of funding ongoing operations for the traditional electric operating companies and Southern Power. See Note 3 to the financial statements under "Commitments" for information on Southern Company Gas' commitments for pipeline charges, storage capacity, and gas supply. Total estimated costs for fuel and purchased power commitments at December 31, 2021 for the applicable Registrants are provided in the table below. Fuel costs include purchases of coal (for the traditional electric operating companies) and natural gas (for the traditional electric operating companies and Southern Power), as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery; the amounts reflected below have been estimated based on the NYMEX future prices at December 31, 2021. As discussed under "Capital Expenditures" herein, estimated expenditures for nuclear fuel are included in the applicable Registrants' construction programs for the years 2022 through 2026. Nuclear fuel commitments at December 31, 2021 that extend beyond 2026 are included in the table below. Purchased power costs represent estimated minimum obligations for various PPAs for the purchase of capacity and energy, except for those accounted for as leases, which are discussed in Note 9 to the financial statements.


	2022		2023		2024		2025		2026		Thereafter
	(in millions)
Southern Company(*)	$	3,740	$	1,983	$	1,302	$	969	$	753	$	5,803
Alabama Power	1,170		581		446		358		203		1,182
Georgia Power(*)	1,405		795		440		348		329		4,118
Mississippi Power	539		235		168		109		98		491
Southern Power	626		372		248		154		123		12

(*)Excludes capacity payments related to Plant Vogtle Units 1 and 2, which are discussed in Note 3 to the financial statements under "Commitments."

Georgia Power's 2022 IRP filing included a request for six PPAs, which are expected to be accounted for as leases, that are contingent upon approval by the Georgia PSC. Five of the six PPAs are with Southern Power and are also contingent upon approval by the FERC. The expected capacity payments associated with the PPAs total $6 million in 2024, $79 million in 2025, $86 million in 2026, and $908 million thereafter, of which $5 million in 2024, $68 million in 2025, $75 million in 2026, and $748 million thereafter relate to the affiliate PPAs with Southern Power. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plan" for additional information.

The traditional electric operating companies and Southern Power have entered into LTSAs for the purpose of securing maintenance support for certain of their generating facilities. See Note 1 to the financial statements under "Long-term Service Agreements" for additional information. As discussed under "Capital Expenditures" herein, estimated expenditures related to LTSAs are included in the applicable Registrants' construction programs for the years 2022 through 2026. Total estimated payments for LTSA commitments at December 31, 2021 that extend beyond 2026 are provided in the following table and include price escalation based on inflation indices:


	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power
	(in millions)
LTSA commitments (after 2026)	$	1,918	$	203	$	347	$	137	$	1,231

In addition, Southern Power has certain other operations and maintenance agreements. Total estimated costs for these commitments at December 31, 2021 are provided in the table below.


	2022		2023		2024		2025		2026		Thereafter
	(in millions)
Southern Power's operations and maintenance agreements	$	77	$	65	$	62	$	47	$	36	$	303

See Note 9 to the financial statements for information on the Registrants' operating lease obligations, including a maturity analysis of the lease liabilities over the next five years and thereafter.

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Southern Company and Subsidiary Companies 2021 Annual Report

Sources of Capital

Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. Southern Company does not expect to issue any equity in the capital markets through 2026 but may issue equity through its stock plans during this time. See Note 8 to the financial statements under "Equity Units" for information on stock purchase contracts associated with Southern Company's equity units.

The Subsidiary Registrants plan to obtain the funds to meet their future capital needs from sources similar to those they used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. In addition, Southern Power plans to utilize tax equity partnership contributions (as discussed further herein).

The amount, type, and timing of any financings in 2022, as well as in subsequent years, will be contingent on investment opportunities and the Registrants' capital requirements and will depend upon prevailing market conditions, regulatory approvals (for certain of the Subsidiary Registrants), and other factors. See "Cash Requirements" herein for additional information.

Southern Power utilizes tax equity partnerships as one of its financing sources, where the tax partner takes significantly all of the federal tax benefits. These tax equity partnerships are consolidated in Southern Power's financial statements and are accounted for using HLBV methodology to allocate partnership gains and losses. During 2021, Southern Power obtained tax equity funding for the Deuel Harvest wind facility, the Garland and Tranquillity battery energy storage facilities, and existing tax equity partnerships totaling $299 million. See Notes 1 and 15 to the financial statements under "General" and "Southern Power," respectively, for additional information.

The issuance of securities by the traditional electric operating companies and Nicor Gas is generally subject to the approval of the applicable state PSC or other applicable state regulatory agency. The issuance of all securities by Mississippi Power and short-term securities by Georgia Power is generally subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, Southern Company, the traditional electric operating companies, and Southern Power (excluding its subsidiaries), Southern Company Gas Capital, and Southern Company Gas (excluding its other subsidiaries) file registration statements with the SEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the securities registered under the 1933 Act, are closely monitored and appropriate filings are made to ensure flexibility in the capital markets.

The Registrants generally obtain financing separately without credit support from any affiliate. See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company in the Southern Company system, except in the case of Southern Company Gas, as described below.

The traditional electric operating companies and SEGCO may utilize a Southern Company subsidiary organized to issue and sell commercial paper at their request and for their benefit. Proceeds from such issuances for the benefit of an individual company are loaned directly to that company. The obligations of each traditional electric operating company and SEGCO under these arrangements are several and there is no cross-affiliate credit support. Alabama Power also maintains its own separate commercial paper program.

Southern Company Gas Capital obtains external financing for Southern Company Gas and its subsidiaries, other than Nicor Gas, which obtains financing separately without credit support from any affiliates. Southern Company Gas maintains commercial paper programs at Southern Company Gas Capital and Nicor Gas. Nicor Gas' commercial paper program supports its working capital needs as Nicor Gas is not permitted to make money pool loans to affiliates. All of the other Southern Company Gas subsidiaries benefit from Southern Company Gas Capital's commercial paper program.

By regulation, Nicor Gas is restricted, 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 subsidiary retained earnings restricted to dividend totaled $1.3 billion. This restriction did not impact Southern Company Gas' ability to meet its cash obligations, nor does management expect such restriction to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.

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Southern Company and Subsidiary Companies 2021 Annual Report

Certain Registrants' current liabilities frequently exceed their current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. The Registrants generally plan to refinance long-term debt as it matures. See Note 8 to the financial statements for additional information. Also see "Financing Activities" herein for information on financing activities that occurred subsequent to December 31, 2021. The following table shows the amount by which current liabilities exceeded current assets at December 31, 2021 for the applicable Registrants:


At December 31, 2021	Southern Company		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Current liabilities in excess of current assets	$	1,956	$	1,544	$	57	$	748	$	471

The Registrants believe the need for working capital can be adequately met by utilizing operating cash flows, as well as commercial paper, lines of credit, and short-term bank notes, as market conditions permit. In addition, under certain circumstances, the Subsidiary Registrants may utilize equity contributions and/or loans from Southern Company.

Bank Credit Arrangements

At December 31, 2021, the Registrants' unused committed credit arrangements with banks were as follows:


At December 31, 2021	Southern Company parent		Alabama Power		Georgia Power		Mississippi Power		Southern Power(a)		Southern Company Gas(b)		SEGCO		Southern Company
	(in millions)
Unused committed credit	$	1,998	$	1,250	$	1,726	$	275	$	568	$	1,747	$	30	$	7,594

(a)At December 31, 2021, Southern Power also had two continuing letters of credit facilities for standby letters of credit, of which $12 million was unused. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(b)Includes $1.047 billion and $700 million at Southern Company Gas Capital and Nicor Gas, respectively.

Subject to applicable market conditions, the Registrants, Nicor Gas, and SEGCO expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, the Registrants, Nicor Gas, and SEGCO may extend the maturity dates and/or increase or decrease the lending commitments thereunder. A portion of the unused credit with banks is allocated to provide liquidity support to 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. See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information.

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Southern Company and Subsidiary Companies 2021 Annual Report

Short-term Borrowings

The Registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Power's subsidiaries are not issuers or obligors under its commercial paper program. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of the Registrants' short-term borrowings were as follows:


	Short-term Debt at the End of the Period
	Amount Outstanding						Weighted Average Interest Rate
	December 31,						December 31,
	2021		2020		2019		2021		2020		2019
	(in millions)
Southern Company	$	1,440	$	609	$	2,055	0.4	%	0.3	%	2.1	%

Georgia Power	—		60		365		—		0.3		2.2
Mississippi Power	—		25		—		—		0.4		—
Southern Power	211		175		549		0.3		0.3		2.2
Southern Company Gas:
Southern Company Gas Capital	$	379	$	220	$	372	0.3	%	0.3	%	2.1	%
Nicor Gas	830		104		278		0.4	%	0.2		1.8
Southern Company Gas Total	$	1,209	$	324	$	650	0.4	%	0.2	%	2.0	%


	Short-term Debt During the Period(*)
	Average Amount Outstanding						Weighted Average Interest Rate						Maximum Amount Outstanding
	2021		2020		2019		2021		2020		2019		2021		2020		2019
	(in millions)												(in millions)
Southern Company	$	1,141	$	1,017	$	1,240	0.3	%	1.6	%	2.6	%	$	1,809	$	2,113	$	2,914
Alabama Power	27		20		17		0.1		1.1		2.6		200		155		190
Georgia Power	95		264		371		0.2		1.7		2.7		407		478		935
Mississippi Power	15		9		—		0.2		1.6		—		81		40		—
Southern Power	133		64		76		0.2		1.5		2.7		520		550		578
Southern Company Gas:
Southern Company Gas Capital	$	206	$	316	$	302	0.2	%	1.4	%	2.6	%	$	485	$	641	$	490
Nicor Gas	420		49		91		0.4		1.4		2.3		897		278		278
Southern Company Gas Total	$	626	$	365	$	393	0.4	%	1.4	%	2.5	%

(*) Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2021, 2020, and 2019.

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Southern Company and Subsidiary Companies 2021 Annual Report

Analysis of Cash Flows

Net cash flows provided from (used for) operating, investing, and financing activities in 2021 and 2020 are presented in the following table:


Net cash provided from (used for):	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
2021
Operating activities	$	6,169	$	2,053	$	2,747	$	246	$	951	$	663
Investing activities	(7,353)		(1,961)		(3,590)		(257)		(803)		(1,379)
Financing activities	1,945		438		867		33		(195)		745

2020
Operating activities	$	6,696	$	1,742	$	2,784	$	298	$	901	$	1,207
Investing activities	(7,030)		(2,122)		(3,503)		(323)		374		(1,417)
Financing activities	(576)		16		676		(222)		(1,372)		180

Fluctuations in cash flows from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Southern Company

Net cash provided from operating activities decreased $0.5 billion in 2021 as compared to 2020 largely due to decreased fuel cost recovery at the traditional electric operating companies and under recovered natural gas costs at the natural gas distribution utilities, partially offset by customer bill credits issued in 2020 at Georgia Power and the timing of customer receivable collections.

The net cash used for investing activities in 2021 and 2020 was primarily related to the Subsidiary Registrants' construction programs.

The net cash provided from financing activities in 2021 was primarily related to net issuances of long-term and short-term debt, partially offset by common stock dividend payments. The net cash used for financing activities in 2020 was primarily related to common stock dividend payments and net repayments of short-term bank debt and commercial paper, partially offset by net issuances of long-term debt and issuances of common stock.

Alabama Power

Net cash provided from operating activities increased $311 million in 2021 as compared to 2020 primarily due to an increase in retail revenues associated with a Rate RSE adjustment effective in January 2021 and higher customer usage, as well as the timing of fossil fuel stock purchases and receivable collections, partially offset by decreased fuel cost recovery.

The net cash used for investing activities in 2021 and 2020 was primarily related to gross property additions.

The net cash provided from financing activities in 2021 and 2020 was primarily related to capital contributions from Southern Company and net long-term debt issuances, partially offset by common stock dividend payments.

Georgia Power

Net cash provided from operating activities decreased $37 million in 2021 as compared to 2020 primarily due to decreased fuel cost recovery, partially offset by the timing of customer receivable collections and vendor payments and customer bill credits issued in 2020 associated with Tax Reform and 2018 and 2019 earnings in excess of the allowed retail ROE range.

The net cash used for investing activities in 2021 and 2020 was primarily related to gross property additions, including approximately $1.3 billion and $1.4 billion, respectively, related to the construction of Plant Vogtle Units 3 and 4. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information on construction of Plant Vogtle Units 3 and 4.

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Southern Company and Subsidiary Companies 2021 Annual Report

The net cash provided from financing activities in 2021 and 2020 was primarily related to capital contributions from Southern Company, borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, and net issuances and reofferings of other debt, partially offset by common stock dividend payments.

Mississippi Power

Net cash provided from operating activities decreased $52 million in 2021 as compared to 2020 primarily due to the timing of vendor payments and decreased fuel cost recovery, partially offset by the timing of receivable collections.

The net cash used for investing activities in 2021 and 2020 was primarily related to gross property additions.

The net cash provided from financing activities in 2021 was primarily related to the issuance of senior notes and capital contributions from Southern Company, partially offset by debt redemptions, common stock dividend payments, and a decrease in commercial paper borrowings. The net cash used for financing activities in 2020 was primarily related to debt repayments and redemptions and a return of capital and common stock dividends paid to Southern Company, partially offset by debt issuances and capital contributions from Southern Company.

Southern Power

Net cash provided from operating activities increased $50 million in 2021 as compared to 2020 primarily due to the timing of vendor payments.

The net cash used for investing activities in 2021 was primarily related to the acquisition of the Deuel Harvest wind facility and ongoing construction activities. The net cash provided from investing activities in 2020 was primarily related to proceeds from the disposition of Plant Mankato, partially offset by ongoing construction activities and the acquisition of the Beech Ridge II wind facility. See Note 15 to the financial statements under "Southern Power" for additional information.

The net cash used for financing activities in 2021 was primarily related to a return of capital to Southern Company and common stock dividend payments, partially offset by net capital contributions from noncontrolling interests and net issuances of senior notes. The net cash used for financing activities in 2020 was primarily related to the repayment of senior notes at maturity, common stock dividend payments, and net repayments of short-term bank debt and commercial paper, partially offset by net contributions from noncontrolling interests.

Southern Company Gas

Net cash provided from operating activities decreased $544 million in 2021 as compared to 2020 primarily due to natural gas cost under recovery, reflecting an increase in the cost of gas purchased during Winter Storm Uri, as well as the timing of vendor payments.

The net cash used for investing activities in 2021 and 2020 was primarily related to construction of transportation and distribution assets recovered through base rates and infrastructure investment recovered through replacement programs at gas distribution operations, partially offset by proceeds from dispositions. See Note 15 to the financial statements for additional information.

The net cash provided from financing activities in 2021 was primarily related to net issuances of long-term and short-term debt and capital contributions from Southern Company, partially offset by common stock dividend payments. The net cash provided from financing activities in 2020 was primarily related to proceeds from issuances of senior notes and first mortgage bonds, as well as capital contributions from Southern Company, partially offset by common stock dividend payments and net repayments of short-term borrowings.

Significant Balance Sheet Changes

Southern Company

Significant balance sheet changes in 2021 for Southern Company included:

•an increase of $3.7 billion in long-term debt (including securities due within one year) related to new issuances;

•an increase of $3.5 billion in total property, plant, and equipment primarily related to the Subsidiary Registrants' construction programs (net of pre-tax charges totaling $1.7 billion recorded during 2021 at Georgia Power for estimated probable losses associated with the construction of Plant Vogtle Units 3 and 4);

•decreases of $1.8 billion and $0.7 billion in other regulatory assets and employee benefit obligations, respectively, and an increase of $1.7 billion in prepaid pension costs primarily due to actuarial gains related to increases in the assumed discount rates and actual asset returns associated with retirement benefit plans;

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Southern Company and Subsidiary Companies 2021 Annual Report

•increases of $1.0 billion and $0.5 billion in AROs and regulatory assets associated with AROs, respectively, primarily related to cost estimate updates at the traditional electric operating companies for ash pond facilities;

•an increase of $0.8 billion in notes payable due to an increase in commercial paper borrowings and short-term bank debt;

•an increase of $0.7 billion in accumulated deferred income taxes primarily related to the utilization of tax credits in 2021, an increase in under recovered fuel and natural gas costs, and an increase in property-related timing differences; and

•an increase of $0.7 billion in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Southern Company" herein.

See "Financing Activities" herein and Notes 2, 5, 6, 8, 10, and 11 to the financial statements for additional information.

Alabama Power

Significant balance sheet changes in 2021 for Alabama Power included:

•an increase of $1.3 billion in total property, plant, and equipment primarily related to construction of distribution and transmission facilities, increases to AROs, construction of Plant Barry Unit 8, and the installation of equipment to comply with environmental standards;

•an increase of $0.9 billion in total common stockholder's equity primarily due to capital contributions from Southern Company;

•an increase of $0.8 billion in long-term debt (including securities due within one year) primarily due to a net increase in outstanding senior notes;

•an increase of $0.5 billion in cash and cash equivalents, as discussed further under "Analysis of Cash Flows – Alabama Power" herein; and

•an increase of $0.5 billion in prepaid pension and other postretirement benefit costs primarily due to actuarial gains related to increases in the assumed discount rates and actual asset returns associated with retirement benefit plans.

See "Financing Activities – Alabama Power" herein and Notes 5, 6, 8, and 11 to the financial statements for additional information.

Georgia Power

Significant balance sheet changes in 2021 for Georgia Power included:

•an increase of $0.9 billion in total property, plant, and equipment primarily related to the construction of generation, transmission, and distribution facilities (net of pre-tax charges totaling $1.7 billion for estimated probable losses on Plant Vogtle Units 3 and 4);

•an increase of $0.8 billion in long-term debt (including securities due within one year) primarily due to a net increase in outstanding senior notes and borrowings from the FFB for construction of Plant Vogtle Units 3 and 4;

•an increase of $0.7 billion in common stockholder's equity related to capital contributions from Southern Company and net income, partially offset by dividends paid to Southern Company;

•a decrease of $0.7 billion in other regulatory assets, deferred and an increase of $0.6 billion in prepaid pension costs primarily due to actuarial gains related to increases in the assumed discount rates and actual asset returns associated with retirement benefit plans;

•increases of $0.6 billion and $0.4 billion in AROs and regulatory assets associated with AROs, respectively, primarily due to cost estimate updates for ash pond closures; and

•an increase of $0.4 billion in deferred under recovered fuel clause revenues resulting from higher fuel and purchased power costs.

See "Financing Activities – Georgia Power" herein and Notes 2, 5, 6, 8, and 11 to the financial statements for additional information.

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Southern Company and Subsidiary Companies 2021 Annual Report

Mississippi Power

Significant balance sheet changes in 2021 for Mississippi Power included:

•an increase of $125 million in common stockholder's equity related to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company;

•an increase of $92 million in long-term debt (including securities due within one year) primarily due to the issuance of senior notes, partially offset by the redemption of revenue bonds and bank term loans; and

•an increase of $79 million in prepaid pension costs and a decrease of $71 million in other regulatory assets, deferred primarily due to actuarial gains related to increases in the assumed discount rates and actual asset returns associated with retirement benefit plans.

See "Financing Activities – Mississippi Power" herein and Notes 8 and 11 to the financial statements for additional information.

Southern Power

Significant balance sheet changes in 2021 for Southern Power included:

•an increase of $681 million in property, plant, and equipment in service primarily due to the acquisition of the Deuel Harvest wind facility and the Glass Sands wind facility being placed in service;

•a decrease of $262 million in accumulated deferred income tax assets and an increase of $92 million in accumulated deferred income tax liabilities primarily related to the utilization of ITCs in 2021;

•a decrease of $173 million in common stockholder's equity primarily due to a return of capital to Southern Company and common stock dividend payments, partially offset by net income; and

•an increase of $161 million in net investment in sales-type leases recorded upon commencement of the Garland and Tranquillity battery energy storage facilities' PPAs.

See Notes 5, 9, 10, and 15 to the financial statements for additional information.

Southern Company Gas

Significant balance sheet changes in 2021 for Southern Company Gas included:

•an increase of $1.06 billion in total property, plant, and equipment primarily related to the construction of transportation and distribution assets recovered through base rates and infrastructure investment recovered through replacement programs;

•an increase of $885 million in notes payable due to issuances of short-term debt and an increase in commercial paper borrowings;

•decreases of $516 million in energy marketing receivables and $494 million in energy marketing trade payables due to the sale of Sequent;

•an increase of $473 million in natural gas cost under recovery, including $207 million in other regulatory assets, deferred, reflecting an increase in the cost of gas purchased during Winter Storm Uri;

•an increase of $290 million in accumulated deferred income taxes primarily due to an increase in natural gas cost under recovery and changes in state apportionment rates as a result of the sale of Sequent; and

•an increase of $276 million in long-term debt (including securities due within one year) primarily due to net issuances of senior notes and first mortgage bonds.

See "Financing Activities – Southern Company Gas" herein and Notes 2, 5, 8, 10, and 15 to the financial statements for additional information.

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Southern Company and Subsidiary Companies 2021 Annual Report

Financing Activities

The following table outlines the Registrants' long-term debt financing activities for the year ended December 31, 2021:


	Issuances/Reofferings						Maturities, Redemptions, and Repurchases
Company	Senior Notes		Revenue Bonds		Other Long-Term Debt		Senior Notes		Revenue Bonds		Other Long-Term Debt(a)
	(in millions)
Southern Company parent	$	1,600	$	—	$	2,476	$	1,500	$	—	$	800
Alabama Power	1,300		—		—		200		65		207
Georgia Power	750		122		440		325		69		105
Mississippi Power	525		—		—		—		320		100
Southern Power	400		—		—		300		—		—
Southern Company Gas	450		—		200		300		—		30
Other	—		—		—		—		—		14
Elimination(b)	—		—		—		—		—		(7)
Southern Company	$	5,025	$	122	$	3,116	$	2,625	$	454	$	1,249

(a)Includes reductions in finance lease obligations resulting from cash payments under finance leases and, for Georgia Power, principal amortization payments for FFB borrowings.

(b)Represents reductions in affiliate finance lease obligations at Georgia Power, which are eliminated in Southern Company's consolidated financial statements.

Except as otherwise described herein, the Registrants used the proceeds of debt issuances for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital. The Subsidiary Registrants also used the proceeds for their construction programs.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Registrants plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

Southern Company

During 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.

In January 2021, Southern Company borrowed $25 million pursuant to a short-term uncommitted bank credit arrangement, which it repaid in March 2021.

In February 2021, Southern Company issued $600 million aggregate principal amount of Series 2021A 0.60% Senior Notes due February 26, 2024 and $400 million aggregate principal amount of Series 2021B 1.75% Senior Notes due March 15, 2028.

In May 2021, Southern Company issued $1.0 billion aggregate principal amount of Series 2021A 3.75% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due September 15, 2051.

Also in May 2021, Southern Company redeemed all of its $1.5 billion aggregate principal amount of 2.35% Senior Notes due July 1, 2021.

In September 2021, Southern Company issued €1.25 billion (approximately $1.476 billion) aggregate principal amount of Series 2021B 1.875% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due September 15, 2081. Southern Company's obligations under these notes were effectively converted to fixed-rate U.S. dollars at issuance for the first six years through cross-currency swaps, mitigating foreign currency exchange risk associated with the interest and principal payments during this period. See Note 14 to the financial statements under "Foreign Currency Derivatives" for additional information.

In October 2021, Southern Company redeemed all $800 million aggregate principal amount of its Series 2016A 5.25% Junior Subordinated Notes due October 1, 2076.

In November 2021, Southern Company issued $600 million aggregate principal amount of Series 2021C Floating Rate Senior Notes due May 10, 2023.

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Southern Company and Subsidiary Companies 2021 Annual Report

Alabama Power

In March 2021, Alabama Power extended the maturity dates from March 2021 to March 2026 on its three bank term loan agreements with an aggregate principal amount of $45 million, currently bearing interest based on three-month LIBOR.

In June 2021, Alabama Power repaid at maturity $200 million aggregate principal amount of its Series 2011B 3.950% Senior Notes.

Also in June 2021, Alabama Power issued $600 million aggregate principal amount of Series 2021A 3.125% Senior Notes due July 15, 2051.

In July 2021, Alabama Power redeemed all of its approximately $206 million aggregate principal amount of Series E Junior Subordinated Notes due October 1, 2042. The Series E Junior Subordinated Notes were held by an affiliated trust, Alabama Power Capital Trust V, which applied the redemption proceeds to the simultaneous redemption of (i) its Flexible Trust Preferred Securities totaling approximately $200 million, which were guaranteed by Alabama Power, and (ii) shares of its common securities totaling approximately $6 million that were held by Alabama Power.

In November 2021, Alabama Power repaid at maturity $65 million aggregate principal amount of The Industrial Development Board of the Town of Columbia (Alabama) Tax Exempt Variable Rate Demand Revenue Bonds (Alabama Power Company Project), Series 1997.

Also in November 2021, Alabama Power issued $700 million aggregate principal amount of Series 2021B 3.00% Senior Notes due March 15, 2052.

Subsequent to December 31, 2021, Alabama Power received a capital contribution totaling $625 million from Southern Company and announced the redemption in February 2022 of all $550 million aggregate principal amount of its Series 2017A 2.45% Senior Notes due March 30, 2022.

Georgia Power

In February 2021, Georgia Power issued $750 million aggregate principal amount of Series 2021A 3.25% Senior Notes due March 15, 2051. An amount equal to the net proceeds of the senior notes is being allocated to finance or refinance, in whole or in part, one or more renewable energy projects and/or expenditures and programs related to enabling opportunities for diverse and small businesses/suppliers.

In March 2021, Georgia Power redeemed all $325 million aggregate principal amount of its Series 2016B 2.40% Senior Notes due April 1, 2021.

Also in March 2021, Georgia Power extended the maturity date of its $125 million term loan from June 2021 to June 2022.

In June 2021, Georgia Power purchased and held approximately $69 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2008. In August 2021, Georgia Power reoffered these bonds to the public.

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. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4. During 2021, Georgia Power made principal amortization payments of $96 million under the FFB Credit Facilities. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" for additional information.

In August 2021, Georgia Power reoffered to the public $53 million aggregate principal amount of Development Authority of Floyd County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Hammond Project), First Series 2010, which it had previously purchased and held.

Subsequent to December 31, 2021, Georgia Power redeemed all $400 million aggregate principal amount of its Series 2012B 2.85% Senior Notes due May 15, 2022.

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Southern Company and Subsidiary Companies 2021 Annual Report

Mississippi Power

In June 2021, Mississippi Power issued $200 million aggregate principal amount of Series 2021A Floating Rate Senior Notes due June 28, 2024 and $325 million aggregate principal amount of Series 2021B 3.10% Senior Notes due July 30, 2051. An amount equal to the net proceeds of the Series 2021B Senior Notes is being allocated to finance or refinance, in whole or in part, one or more renewable energy projects and/or expenditures and programs related to enabling opportunities for diverse and small businesses/suppliers.

In July 2021, Mississippi Power redeemed all $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021 at par plus accrued interest and a make-whole premium.

Also in July 2021, Mississippi Power repaid its $60 million and $15 million floating rate bank term loans, with maturity dates in December 2021 and January 2022, respectively.

In October 2021, Mississippi Power repaid $25 million previously borrowed under its $125 million revolving credit arrangement that matures in March 2023.

In December 2021, Mississippi Power redeemed all $50 million aggregate principal amount of Mississippi Business Finance Corporation Revenue Bonds, First Series 2010 due December 1, 2040.

Subsequent to December 31, 2021, Mississippi Power received a capital contribution totaling $50 million from Southern Company.

Southern Power

In January 2021, Southern Power issued $400 million aggregate principal amount of Series 2021A 0.90% Senior Notes due January 15, 2026. An amount equal to the net proceeds of the senior notes was allocated to finance or refinance, in whole or in part, one or more renewable energy projects.

In November 2021, Southern Power redeemed all $300 million aggregate principal amount of its Series 2016E 2.500% Senior Notes due December 15, 2021.

Southern Company Gas

In February 2021, Atlanta Gas Light repaid at maturity $30 million aggregate principal amount of 9.1% medium-term notes.

In March 2021, Nicor Gas entered into three short-term floating rate bank loans in an aggregate principal amount of $300 million, each bearing interest based on one-month LIBOR.

In June 2021, Southern Company Gas Capital redeemed all $300 million aggregate principal amount of its 3.50% Senior Notes due September 15, 2021.

In August 2021, Nicor Gas issued in a private placement $50 million aggregate principal amount of 1.42% Series First Mortgage Bonds due August 31, 2026 and $50 million aggregate principal amount of 2.19% Series First Mortgage Bonds due August 31, 2033. In October 2021, Nicor Gas issued in a private placement $100 million aggregate principal amount of 1.77% Series First Mortgage Bonds due October 28, 2028. Nicor Gas also entered into an agreement to issue in a private placement additional first mortgage bonds with aggregate principal amounts of $100 million and $75 million expected to be issued in August 2022 and October 2022, respectively.

In September 2021, Southern Company Gas Capital, as borrower, and Southern Company Gas, as guarantor, issued $450 million aggregate principal amount of Series 2021A 3.15% Senior Notes due September 30, 2051.

Credit Rating Risk

At December 31, 2021, the Registrants did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain Registrants to BBB and/or Baa2 or below. These contracts are primarily for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and, for Georgia Power, construction of new generation at Plant Vogtle Units 3 and 4.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2021 Annual Report

The maximum potential collateral requirements under these contracts at December 31, 2021 were as follows:


Credit Ratings	Southern Company(*)		Alabama Power		Georgia Power		Mississippi Power		Southern Power(*)		Southern Company Gas
	(in millions)
At BBB and/or Baa2	$	41	$	1	$	—	$	—	$	40	$	—
At BBB- and/or Baa3	419		2		61		1		357		—
At BB+ and/or Ba1 or below	1,934		407		939		307		1,186		9

(*)Southern Power has PPAs that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPAs require credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade. Southern Power had $105 million of cash collateral posted related to PPA requirements at December 31, 2021.

The amounts in the previous table for the traditional electric operating companies and Southern Power include certain agreements that could require collateral if either Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Registrants to access capital markets and would be likely to impact the cost at which they do so.

Mississippi Power and its largest retail customer, Chevron, have agreements under which Mississippi Power provides retail service to the Chevron refinery in Pascagoula, Mississippi through at least 2038. The agreements grant Chevron a security interest in the co-generation assets owned by Mississippi Power located at the refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of Mississippi Power's credit rating to below investment grade by two of the three rating agencies.

On October 27, 2021, S&P downgraded the Southern Company issuer credit rating to BBB+ from A-. Due to S&P's consolidated rating methodology, the downgrade of Southern Company's issuer credit rating resulted in the downgrade of the senior unsecured long-term debt rating of Alabama Power and the long-term issuer rating of Nicor Gas to A- from A, the senior unsecured long-term debt ratings of Atlanta Gas Light, Georgia Power, Mississippi Power, and Southern Company Gas Capital to BBB+ from A-, and the senior unsecured long-term debt ratings of Southern Company and Southern Power to BBB from BBB+. S&P revised its credit rating outlook for Southern Company and its subsidiaries to stable from negative.

Market Price Risk

As a result of the sale of Sequent on July 1, 2021, Southern Company Gas' market risk exposure decreased significantly. The other Registrants had no material change in market risk exposure for the year ended December 31, 2021 when compared to the year ended December 31, 2020. See Note 14 to the financial statements for an in-depth discussion of the Registrants' derivatives, as well as Note 1 to the financial statements under "Financial Instruments" for additional information. See Note 15 to the financial statements under "Southern Company Gas" for information regarding the sale of Sequent.

Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities that sell natural gas directly to end-use customers continue to have limited exposure to market volatility in interest rates, foreign currency exchange rates, commodity fuel prices, and prices of electricity. The traditional electric operating companies and certain of the natural gas distribution utilities manage fuel-hedging programs implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. Mississippi Power also manages wholesale fuel-hedging programs under agreements with its wholesale customers. Because energy from Southern Power's facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, Southern Power's exposure to market volatility in commodity fuel prices and prices of electricity is generally limited. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional electric operating companies and Southern Power may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

Certain of Southern Company Gas' non-regulated operations (primarily Sequent until its sale on July 1, 2021) routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and OTC energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Southern Company Gas' gas marketing services business also actively

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2021 Annual Report

manages storage positions through a variety of hedging transactions for the purpose of managing exposures arising from changing natural gas prices. These hedging instruments are used to substantially protect economic margins (as spreads between wholesale and retail natural gas prices widen between periods) and thereby minimize exposure to declining earnings. Some of these economic hedge activities may not qualify, or may not be designated, for hedge accounting treatment.

The following table provides information related to variable interest rate exposure on long-term debt (including amounts due within one year) at December 31, 2021 for the applicable Registrants:


At December 31, 2021	Southern Company(*)			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas
	(in millions, except percentages)
Long-term variable interest rate exposure	$	4,464		$	834		$	797		$	234		$	500
Weighted average interest rate on long-term variable interest rate exposure	0.84		%	0.21		%	0.21		%	0.32		%	0.49		%
Impact on annualized interest expense of 100 basis point change in interest rates	$	45		$	8		$	8		$	2		$	5

(*)Includes $2.0 billion of long-term variable interest rate exposure at the Southern Company parent entity.

The Registrants may enter into interest rate derivatives designated as hedges, which are intended to mitigate interest rate volatility related to forecasted debt financings and existing fixed and floating rate obligations. See Note 14 to the financial statements under "Interest Rate Derivatives" for additional information.

Southern Company and Southern Power had foreign currency denominated debt at December 31, 2021 and have each mitigated exposure to foreign currency exchange rate risk through the use of foreign currency swaps. See Note 14 to the financial statements under "Foreign Currency Derivatives" for additional information.

Changes in fair value of energy-related derivative contracts for Southern Company and Southern Company Gas for the years ended December 31, 2021 and 2020 are provided in the table below. At December 31, 2021 and 2020, substantially all of the traditional electric operating companies' and certain of the natural gas distribution utilities' energy-related derivative contracts were designated as regulatory hedges and were related to the applicable company's fuel-hedging program.


	Southern Company(a)		Southern Company Gas(a)
	(in millions)
Contracts outstanding at December 31, 2019, assets (liabilities), net	$	(21)	$	72
Contracts realized or settled	(14)		(98)
Current period changes(b)	142		127

Contracts outstanding at December 31, 2020, assets (liabilities), net	$	107	$	101
Contracts realized or settled	(252)		(85)
Current period changes(b)	243		(84)
Sale of Sequent	76		76
Contracts outstanding at December 31, 2021, assets (liabilities), net	$	174	$	8

(a)Excludes cash collateral held on deposit in broker margin accounts of $3 million, $28 million, and $99 million at December 31, 2021, 2020, and 2019, respectively, and immaterial premium and intrinsic value associated with weather derivatives for all periods presented.

(b)The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2021 Annual Report

The net hedge volumes of energy-related derivative contracts for natural gas purchased (sold) at December 31, 2021 and 2020 for Southern Company and Southern Company Gas were as follows:


	Southern Company	Southern Company Gas
	mmBtu Volume (in millions)
At December 31, 2021:
Commodity – Natural gas swaps	57	—
Commodity – Natural gas options	253	68
Total hedge volume	310	68

At December 31, 2020:
Commodity – Natural gas swaps	262	—
Commodity – Natural gas options	574	523
Total hedge volume	836	523

Southern Company Gas' derivative contracts are comprised of both long and short natural gas positions. A long position is a contract to purchase natural gas, and a short position is a contract to sell natural gas. The volumes presented above for Southern Company Gas represent the net of long natural gas positions of 74 million mmBtu and short natural gas positions of 6 million mmBtu at December 31, 2021 and the net of long natural gas positions of 4.42 billion mmBtu and short natural gas positions of 3.90 billion mmBtu at December 31, 2020.

For the Southern Company system, the weighted average swap contract cost per mmBtu was approximately $0.74 per mmBtu below market prices at December 31, 2021 and was equal to market prices at December 31, 2020. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. Substantially all of the traditional electric operating companies' natural gas hedge gains and losses are recovered through their respective fuel cost recovery clauses.

The Registrants use over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. In addition, Southern Company Gas uses exchange-traded market-observable contracts, which are categorized as Level 1. See Note 13 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts for Southern Company and Southern Company Gas at December 31, 2021 were as follows:


	Fair Value Measurements of Contracts at
	December 31, 2021
	Total Fair Value		Maturity
			2022		2023 – 2024		2025 – 2026
	(in millions)
Southern Company
Level 1(a)	$	15	$	14	$	1	$	—
Level 2(b)	159		93		65		1

Southern Company total(c)	$	174	$	107	$	66	$	1









Southern Company Gas
Level 1(a)	$	15	$	14	$	1	$	—
Level 2(b)	(7)		(7)		—		—

Southern Company Gas total(c)	$	8	$	7	$	1	$	—

(a)Valued using NYMEX futures prices.

(b)Level 2 amounts for Southern Company Gas are valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.

(c)Excludes cash collateral of $3 million as well as immaterial premium and associated intrinsic value associated with weather derivatives.

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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2021 Annual Report

The Registrants are exposed to risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts, as applicable. The Registrants 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. Therefore, the Registrants do not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 14 to the financial statements.

Credit Risk

Southern Company (except as discussed herein), the traditional electric operating companies, and Southern Power are not exposed to any concentrations of credit risk. Southern Company Gas' exposure to concentrations of credit risk is discussed herein.

Southern Company Gas

Gas Distribution Operations

Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of the 16 Marketers in Georgia. The credit risk exposure to the Marketers varies seasonally, with the lowest exposure in the non-peak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The provisions of Atlanta Gas Light's tariff allow Atlanta Gas Light to obtain credit security support in an amount equal to a minimum of two times a Marketer's highest month's estimated bill from Atlanta Gas Light. For 2021, the four largest Marketers based on customer count, which includes SouthStar, accounted for 15% of Southern Company Gas' operating revenues and 17% of operating revenues for Southern Company Gas' gas distribution operations segment.

Several factors are designed to mitigate Southern Company Gas' risks from the increased concentration of credit that has resulted from deregulation. In addition to the security support described above, Atlanta Gas Light bills intrastate delivery service to Marketers in advance rather than in arrears. Atlanta Gas Light accepts credit support in the form of cash deposits, letters of credit/surety bonds from acceptable issuers, and corporate guarantees from investment-grade entities. Southern Company Gas reviews the adequacy of credit support coverage, credit rating profiles of credit support providers, and payment status of each Marketer. Southern Company Gas believes that adequate policies and procedures are in place to properly quantify, manage, and report on Atlanta Gas Light's credit risk exposure to Marketers.

Atlanta Gas Light also faces potential credit risk in connection with assignments of interstate pipeline transportation and storage capacity to Marketers. Although Atlanta Gas Light assigns this capacity to Marketers, in the event that a Marketer fails to pay the interstate pipelines for the capacity, the interstate pipelines would likely seek repayment from Atlanta Gas Light.

Wholesale Gas Services

Following the sale of Sequent on July 1, 2021, Southern Company Gas no longer has exposure to counterparty credit risk for wholesale gas services. See Note 15 to the financial statements under "Southern Company Gas" for information on the sale of Sequent.

Gas Marketing Services

Southern Company Gas obtains credit scores for its firm residential and small commercial customers using a national credit reporting agency, enrolling only those customers that meet or exceed Southern Company Gas' credit threshold. Southern Company Gas considers potential interruptible and large commercial customers based on reviews of publicly available financial statements and commercially available credit reports. Prior to entering into a physical transaction, Southern Company Gas also assigns physical wholesale counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements.

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Item 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


			Page
The Southern Company and Subsidiary Companies:
Report of Independent Registered Public Accounting Firm			II-74
Consolidated Statements of Income for the Years Ended December 31 , 2021, 2020, and 2019			II-78
Consolidated Statements of Comprehensive Income for the Years Ended December 31 , 2021, 2020, and 2019			II-79
Consolidated Statements of Cash Flows for the Years Ended December 31 , 2021, 2020, and 2019			II-80
Consolidated Balance Sheets at December 31 , 2021 and 2020			II-81
Consolidated Statements of Stockholders' Equity for the Years Ended December 31 , 2021, 2020, and 2019			II-83

Alabama Power:
Report of Independent Registered Public Accounting Firm			II-84
Statements of Income for the Years Ended December 31 , 2021, 2020, and 2019			II-86
Statements of Comprehensive Income for the Years Ended December 31 , 2021, 2020, and 2019			II-87
Statements of Cash Flows for the Years Ended December 31 , 2021, 2020, and 2019			II-88
Balance Sheets at December 31 , 2021 and 2020			II-89
Statements of Common Stockholder's Equity for the Years Ended December 31 , 2021, 2020, and 2019			II-91

Georgia Power:
Report of Independent Registered Public Accounting Firm			II-92
Statements of Income for the Years Ended December 31 , 2021, 2020, and 2019			II-95
Statements of Comprehensive Income for the Years Ended December 31 , 2021, 2020, and 2019			II-96
Statements of Cash Flows for the Years Ended December 31 , 2021, 2020, and 2019			II-97
Balance Sheets at December 31 , 2021 and 2020			II-98
Statements of Common Stockholder's Equity for the Years Ended December 31 , 2021, 2020, and 2019			II-100

Mississippi Power:
Report of Independent Registered Public Accounting Firm			II-101
Statements of Income for the Years Ended December 31 , 2021, 2020, and 2019			II-103
Statements of Comprehensive Income for the Years Ended December 31 , 2021, 2020, and 2019			II-104
Statements of Cash Flows for the Years Ended December 31 , 2021, 2020, and 2019			II-105
Balance Sheets at December 31 , 2021 and 2020			II-106
Statements of Common Stockholder's Equity for the Years Ended December 31 , 2021, 2020, and 2019			II-108

Southern Power and Subsidiary Companies:
Report of Independent Registered Public Accounting Firm			II-109
Consolidated Statements of Income for the Years Ended December 31 , 2021, 2020, and 2019			II-111
Consolidated Statements of Comprehensive Income for the Years Ended December 31 , 2021, 2020, and 2019			II-112
Consolidated Statements of Cash Flows for the Years Ended December 31 , 2021, 2020, and 2019			II-113
Consolidated Balance Sheets at December 31 , 2021 and 2020			II-114
Consolidated Statements of Stockholders' Equity for the Years Ended December 31 , 2021, 2020, and 2019			II-116

Southern Company Gas and Subsidiary Companies:
Report of Independent Registered Public Accounting Firm			II-117
Consolidated Statements of Income for the Years Ended December 31 , 2021, 2020, and 2019			II-121
Consolidated Statements of Comprehensive Income for the Years Ended December 31 , 2021, 2020, and 2019			II-122
Consolidated Statements of Cash Flows for the Years Ended December 31 , 2021, 2020, and 2019			II-123
Consolidated Balance Sheets at December 31 , 2021 and 2020			II-124
Consolidated Statements of Common Stockholder's Equity for the Years Ended December 31 , 2021, 2020, and 2019			II-126

Combined Notes to Financial Statements			II-127

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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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Table of Contents Index to Financial Statements

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:

•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 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.

•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 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:

•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.

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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.

•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 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.

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 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 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.

Critical Audit Matters

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.

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 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 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.

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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.

How the Critical Audit Matter Was Addressed in the Audit

/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.

Critical Audit Matter

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 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.

Critical Audit Matter

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:

•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.

•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.

Critical Audit Matter

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 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 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.

•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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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


Note		Page
1	Summary of Significant Accounting Policies	II-128
2	Regulatory Matters	II-143
3	Contingencies, Commitments, and Guarantees	II-165
4	Revenue from Contracts with Customers	II-171
5	Property, Plant, and Equipment	II-174
6	Asset Retirement Obligations	II-179
7	Consolidated Entities and Equity Method Investments	II-182
8	Financing	II-186
9	Leases	II-194
10	Income Taxes	II-204
11	Retirement Benefits	II-211
12	Stock Compensation	II-238
13	Fair Value Measurements	II-241
14	Derivatives	II-249
15	Acquisitions and Dispositions	II-260
16	Segment and Related Information	II-264

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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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

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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

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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:

•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;

•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;

•Investments related to the hydro operations of Plants Sinclair (45 MWs), North Highlands (30 MWs), and Burton (6 MWs);

•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;

•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;

•Related transmission costs necessary to support the proposed retirements and renewable resources previously described;

•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

•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.

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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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.

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)

Decoupled, including straight-fixed-variable rates(c)

Regulatory infrastructure program rates(d)

Bad debt rider(e)

Energy efficiency plan(f)

Annual base rate adjustment mechanism(g)

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

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.

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

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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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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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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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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Southern Company and Subsidiary Companies 2021 Annual Report


	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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Southern Company and Subsidiary Companies 2021 Annual Report

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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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	$	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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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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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

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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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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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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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


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.


	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	%


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


	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


	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


	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


	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	$	—


	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


	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)


	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)


	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


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


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)


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)


	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	$	—


		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


	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


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


	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


	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


			Page
Southern Company			II-270
Alabama Power			II-271
Georgia Power			II-272
Mississippi Power			II-273
Southern Power			II-274
Southern Company Gas			II-275


			Additions
Description	Balance at Beginning of Period		Charged to Income		Charged to Other Accounts		Deductions(a)		Balance at End of Period
	(in millions)
Provision for uncollectible accounts:

Southern Company(b)
2021	$	118	$	51	$	(23)	$	68	$	78
2020	49		78		27		36		118
2019	50		68		—		69		49

Alabama Power
2021	$	43	$	(7)	$	—	$	22	$	14
2020	22		25		—		4		43
2019	10		24		—		12		22

Georgia Power(b)
2021	$	26	$	16	$	(23)	$	17	$	2
2020	2		14		23		13		26
2019	2		13		—		13		2

Mississippi Power
2021	$	1	$	1	$	—	$	1	$	1
2020	1		1		—		1		1
2019	1		2		—		2		1

Southern Power
2021	$	—	$	5	$	—	$	—	$	5
2020	—		—		—		—		—
2019	—		—		—		—		—

Southern Company Gas
2021	$	40	$	26	$	—	$	27	$	39
2020	18		35		4		17		40
2019	30		29		—		41		18


(2)	Plan of acquisition, reorganization, arrangement, liquidation or succession
	Southern Company
		(a)	1	—	Stock Purchase Agreement, dated as of May 20, 2018, by and among Southern Company, 700 Universe, LLC, and NextEra Energy and Amendment No. 1 thereto dated as of January 1, 2019. (Designated in Form 8-K dated May 23, 2018, File No. 1-3526, as Exhibit 2(a)1 and in Form 10-K for the year ended December 31, 2018, File No. 1-3526, as Exhibit 2(a)3.)
	Southern Power
		(e)	1	—	Membership Interest Purchase Agreement, dated as of April 17, 2019, by and between Southern Power and The City of Austin d/b/a Austin Energy. (Designated in Form 8-K dated June 13, 2019, File No. 001-37803, as Exhibit 2.1.)
		(e)	2	—	Letter Agreement, dated as of May 24, 2019, by and between Southern Power and The City of Austin d/b/a Austin Energy. (Designated in Form 8-K dated June 13, 2019, File No. 001-37803, as Exhibit 2.2.)

(3)	Articles of Incorporation and By-Laws
	Southern Company
		(a)	1	—	Restated Certificate of Incorporation of Southern Company, dated February 12, 2019. (Designated in Form 10-K for the year ended December 31, 2018, File No. 1-3526, as Exhibit 3(a)1.)
		(a)	2	—	Amended and Restated By-laws of Southern Company effective December 9, 2019, and as presently in effect. (Designated in Form 8-K dated December 9, 2019, File No. 1-3526, as Exhibit 3.1.)

	Alabama Power
		(b)	1	—	Charter of Alabama Power and amendments thereto through September 7, 2017. (Designated in Registration Nos. 2-59634 as Exhibit 2(b), 2-60209 as Exhibit 2(c), 2-60484 as Exhibit 2(b), 2-70838 as Exhibit 4(a)-2, 2-85987 as Exhibit 4(a)-2, 33-25539 as Exhibit 4(a)-2, 33-43917 as Exhibit 4(a)-2, in Form 8-K dated February 5, 1992, File No. 1-3164, as Exhibit 4(b)-3, in Form 8-K dated July 8, 1992, File No. 1-3164, as Exhibit 4(b)-3, in Form 8-K dated October 27, 1993, File No. 1-3164, as Exhibits 4(a) and 4(b), in Form 8-K dated November 16, 1993, File No. 1-3164, as Exhibit 4(a), in Certificate of Notification, File No. 70-8191, as Exhibit A, in Form 10-K for the year ended December 31, 1997, File No. 1-3164, as Exhibit 3(b)2, in Form 8-K dated August 10, 1998, File No. 1-3164, as Exhibit 4.4, in Form 10-K for the year ended December 31, 2000, File No. 1-3164, as Exhibit 3(b)2, in Form 10-K for the year ended December 31, 2001, File No. 1-3164, as Exhibit 3(b)2, in Form 8-K dated February 5, 2003, File No. 1-3164, as Exhibit 4.4, in Form 10-Q for the quarter ended March 31, 2003, File No 1-3164, as Exhibit 3(b)1, in Form 8-K dated February 5, 2004, File No. 1-3164, as Exhibit 4.4, in Form 10-Q for the quarter ended March 31, 2006, File No. 1-3164, as Exhibit 3(b)(1), in Form 8-K dated December 5, 2006, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated September 12, 2007, File No. 1-3164, as Exhibit 4.5, in Form 8-K dated October 17, 2007, File No. 1-3164, as Exhibit 4.5, in Form 10-Q for the quarter ended March 31, 2008, File No. 1-3164, as Exhibit 3(b)1, and in Form 8-K dated September 5, 2017, File No. 1-3164, as Exhibit 4.1.)
		(b)	2	—	Amended and Restated By-laws of Alabama Power effective February 10, 2014, and as presently in effect. (Designated in Form 8-K dated February 10, 2014, File No 1-3164, as Exhibit 3.1.)


	Georgia Power
		(c)	1	—	Charter of Georgia Power and amendments thereto through October 9, 2007. (Designated in Registration Nos. 2-63392 as Exhibit 2(a)-2, 2-78913 as Exhibits 4(a)-(2) and 4(a)-(3), 2-93039 as Exhibit 4(a)-(2), 2-96810 as Exhibit 4(a)-2, 33-141 as Exhibit 4(a)-(2), 33-1359 as Exhibit 4(a)(2), 33-5405 as Exhibit 4(b)(2), 33-14367 as Exhibits 4(b)-(2) and 4(b)-(3), 33-22504 as Exhibits 4(b)-(2), 4(b)-(3) and 4(b)-(4), in Form 10-K for the year ended December 31, 1991, File No. 1-6468, as Exhibits 4(a)(2) and 4(a)(3), in Registration No. 33-48895 as Exhibits 4(b)-(2) and 4(b)-(3), in Form 8-K dated December 10, 1992, File No. 1-6468 as Exhibit 4(b), in Form 8-K dated June 17, 1993, File No. 1-6468, as Exhibit 4(b), in Form 8-K dated October 20, 1993, File No. 1-6468, as Exhibit 4(b), in Form 10-K for the year ended December 31, 1997, File No. 1-6468, as Exhibit 3(c)2, in Form 10-K for the year ended December 31, 2000, File No. 1-6468, as Exhibit 3(c)2, in Form 8-K dated June 27, 2006, File No. 1-6468, as Exhibit 3.1, and in Form 8-K dated October 3, 2007, File No. 1-6468, as Exhibit 4.5.)
		(c)	2	—	By-laws of Georgia Power as amended effective November 9, 2016, and as presently in effect. (Designated in Form 8-K dated November 9, 2016, File No. 1-6468, as Exhibit 3.1.)
	Mississippi Power
		(d)	1	—	Amended and Restated Articles of Incorporation of Mississippi Power dated July 22, 2020. (Designated in Form 10-Q for the quarter ended June 30, 2020, File No. 001-11229, as Exhibit 3(d)1.)
		(d)	2	—	By-laws of Mississippi Power as amended effective July 22, 2020, and as presently in effect. (Designated in Form 10-Q for the quarter ended June 30, 2020, File No. 001-11229, as Exhibit 3(d)2.)
	Southern Power
		(e)	1	—	Certificate of Incorporation of Southern Power Company dated January 8, 2001. (Designated in Registration No. 333-98553 as Exhibit 3.1.)
		(e)	2	—	By-laws of Southern Power Company effective January 8, 2001. (Designated in Registration No. 333-98553 as Exhibit 3.2.)
	Southern Company Gas
		(f)	1	—	Amended and Restated Articles of Incorporation of Southern Company Gas dated July 11, 2016. (Designated in Form 8-K dated July 8, 2016, File No. 1-14174, as Exhibit 3.1.)
		(f)	2	—	Amended and Restated By-laws of Southern Company Gas effective October 23, 2018. (Designated in Form 10-Q for the quarter ended June 30, 2019, File No. 1-14174, as Exhibit 3(e).)

(4)	Instruments Describing Rights of Security Holders, Including Indentures
	With respect to each of Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power Company, and Southern Company Gas, such Registrant has excluded certain instruments with respect to long-term debt that does not exceed 10% of the total assets of such Registrant and its subsidiaries. Each such Registrant agrees, upon request of the SEC, to furnish copies of any or all such instruments to the SEC.
	Southern Company
		(a)	1	—	Senior Note Indenture dated as of January 1, 2007, between Southern Company and Computershare Trust Company, N.A., as successor Trustee, and certain indentures supplemental thereto through November 10, 2021. (Designated in Form 8-K dated January 11, 2007, File No. 1-3526, as Exhibit 4.1, in Form 8-K dated August 21, 2013, File No. 1-3526, as Exhibit 4.2, in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(a), in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(d), in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(e), in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(f), in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(g), in Form 8-K dated April 1, 2020, File No. 1-3526, as Exhibit 4.2, in Form 8-K dated Fe bruary 23, 2021, F ile No. 1-3526, as Exhibit 4.4(a), in Form 8-K dated February 23 , 2021, File No. 1-3526, as Exhibit 4.4(b), and in Form 8-K dated November 5, 2021, File No. 1-3526, as Exhibit 4.4.)


	(a)	2	—	Subordinated Note Indenture dated as of October 1, 2015, between The Southern Company and Computershare Trust Company, N.A., as successor Trustee, and certain indentures supplemental thereto through September 16, 2021. (Designated in Form 8-K dated October 1, 2015, File No. 1-3526, as Exhibit 4.3, in Form 8-K dated December 5, 2016, File No. 1-3526, as Exhibit 4.4, in Form 10-Q for the quarter ended June 30, 2017, File No. 1-3526 as Exhibit 4(a)1, in Form 8-K dated November 17, 2017, File No. 1-3526, as Exhibit 4.4, in Form 8-K dated August 13, 2019, File No. 1-3526, as Exhibit 4.4(a), in Form 8-K dated August 13, 2019, File No. 1-3526, as Exhibit 4.4(b), in Form 8-K dated January 6, 2020, File No. 1-3526 as Exhibit 4.4, in Form 8-K dated September 15, 2020, File No. 1-3526, as Exhibit 4.4(a), in Form 8-K dated September 15, 2020, File No. 1-3526, as Exhibit 4.4(b), in Form 8-K dated May 3, 2021, File No. 1-3526 , as Exhibit 4.4, and in Form 8-K dated September 13, 2021, File No. 1-3526, as Exhibit 4.4.)
	(a)	3	—	Purchase Contract and Pledge Agreement, dated as of August 16, 2019, between Southern Company and U.S. Bank National Association, as Purchase Contract Agent, Collateral Agent, Custodial Agent, and Securities Intermediary. (Designated in Form 8-K dated August 13, 2019, File No. 1-3526, as Exhibit 4.9.)
*	(a)	4	—	Description of securities registered pursuant to Section 12 of the Securities Exchange Act of 1934, as amended.
Alabama Power
	(b)	1	—	Subordinated Note Indenture dated as of January 1, 1997, between Alabama Power and Regions Bank, as Successor Trustee, and certain indentures supplemental thereto through October 2, 2002. (Designated in Form 8-K dated January 9, 1997, File No. 1-3164, as Exhibits 4.1, and in Form 8-K dated September 26, 2002, File No. 3164, as Exhibit 4.9-B.)
	(b)	2	—	Senior Note Indenture dated as of December 1, 1997, between Alabama Power and Regions Bank, as Successor Trustee, and certain indentures supplemental thereto through November 18, 2021. (Designated in Form 8-K dated December 4, 1997, File No. 1-3164, as Exhibit 4.1, in Form 8-K dated December 6, 2002, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated February 11, 2003, File No. 1-3164, as Exhibit 4.2(a), in Form 8-K dated March 12, 2003, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 8, 2008, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated February 26, 2009, File No. 1-3164 as Exhibit 4.2, in Form 8-K dated March 3, 2011, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated May 18, 2011, File No. 1-3164, as Exhibit 4.2(b), in Form 8-K dated January 10, 2012, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated November 27, 2012, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated December 3, 2013, File No. 1-3164, as Exhibit 4.2, in Form 8-K dated August 20, 2014, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated March 5, 2015, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated April 9, 2015, File No. 1-3164, as Exhibit 4.6(b), in Form 8-K dated January 8, 2016, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated February 27, 2017, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated November 2, 2017, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated June 21, 2018, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated September 12, 2019, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated August 24, 2020, File No. 1-3164, as Exhibit 4.6, in Form 8-K dated June 7, 2021, F ile No. 1-3164, as Exhibit 4.6, and in Form 8-K dated November 15, 2021, F ile No. 1-3164, as Exhibit 4 .6.)
	(b)	3	—	Description of securities registered pursuant to Section 12 of the Securities Exchange Act of 1934, as amended. (Designated in Form 10-K for the year ended December 31, 2019, File No. 1-3164, as Exhibit 4(b)5.)
Georgia Power
	(c)	1	—	Senior Note Indenture dated as of January 1, 1998, between Georgia Power and Computershare Trust Company, N.A., as Successor Trustee, and certain indentures supplemental thereto through February 26, 2021. (Designated in Form 8-K dated January 21, 1998, File No. 1-6468, as Exhibits 4.1, in Form 8-K dated April 10, 2003, File No. 1-6468, as Exhibit 4.1, in Form 8-K dated March 6, 2007, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated February 4, 2009, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated May 24, 2010, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated August 26, 2010, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated February 29, 2012, File No. 1-6468, as Exhibit 4.2, in Form 8-K dated March 12, 2013, File No. 1-6468, as Exhibit 4.2(a), in Form 8-K dated March 2, 2016, File No. 1-6468, as Exhibit 4.2(a), in Form 8-K dated March 2, 2016, File No. 1-6468, as Exhibit 4.2(b), in Form 8-K dated February 28, 2017, File No. 1-6468, as Exhibit 4.2(b), in Form 8-K dated September 4, 2019, File No. 1-6468, as Exhibit 4.2(a), in Form 8-K dated September 4, 2019, File No. 1-6468, as Exhibit 4.2(b), in Form 8-K dated January 8, 2020, File No. 1-6468, as Exhibit 4.2(b), in Form 8-K dated January 8, 2020, File No. 1-6468, as Exhibit 4.2(c), and in Form 8-K dated February 22, 2021, File No. 1-6468, as Exhi bit 4.2.)


	(c)	2	—	Subordinated Note Indenture, dated as of September 1, 2017, between Georgia Power and Computershare Trust Company, N.A., as Successor Trustee, and First Supplemental Indenture thereto dated as of September 21, 2017. (Designated in Form 8-K dated September 18, 2017, File No. 1-6468, as Exhibit 4.3, and in Form 8-K dated September 18, 2017, File No. 1-6468, as Exhibit 4.4.)
	(c)	3	—	Amended and Restated Loan Guarantee Agreement, dated as of March 22, 2019, between Georgia Power and the DOE. (Designated in Form 8-K dated March 22, 2019, File No. 1-6468, as Exhibit 4.1.)
	(c)	4	—	Note Purchase Agreement among Georgia Power, the DOE, and the Federal Financing Bank dated as of February 20, 2014. (Designated in Form 8-K dated February 20, 2014, File No. 1-6468, as Exhibit 4.2.)
	(c)	5	—	Future Advance Promissory Note dated February 20, 2014 made by Georgia Power to the FFB. (Designated in Form 8-K dated February 20, 2014, File No. 1-6468, as Exhibit 4.3.)
	(c)	6	—	Amended and Restated Deed to Secure Debt, Security Agreement and Fixture Filing, dated as of March 22, 2019, by Georgia Power to PNC Bank, National Association, doing business as Midland Loan Services Inc., a division of PNC Bank, National Association. (Designated in Form 8-K dated March 22, 2019, File No. 1-6468, as Exhibit 4.4.)
	(c)	7	—	Amended and Restated Owners Consent to Assignment and Direct Agreement and Amendment to Plant Alvin W. Vogtle Additional Units Ownership Participation Agreement, dated as of March 22, 2019, among Georgia Power, the other Vogtle Owners, the DOE, and PNC Bank, National Association, doing business as Midland Loan Services Inc., a division of PNC Bank, National Association. (Designated in Form 8-K dated March 22, 2019, File No. 1-6468, as Exhibit 4.5.)
	(c)	8	—	Note Purchase Agreement, dated as of March 22, 2019, between Georgia Power, the DOE, and the FFB. (Designated in Form 8-K dated March 22, 2019, File No. 1-6468, as Exhibit 4.2.)
	(c)	9	—	Promissory Note of Georgia Power, dated as of March 22, 2019. (Designated in Form 8-K dated March 22, 2019, File No. 1-6468, as Exhibit 4.3.)
	(c)	10	—	Description of securities registered pursuant to Section 12 of the Securities Exchange Act of 1934, as amended. (Designated in Form 10-K for the year ended December 31, 2019, File No. 1-6468, as Exhibit 4(c)10.)
Mississippi Power
	(d)	1	—	Senior Note Indenture dated as of May 1, 1998, between Mississippi Power and Computershare Trust Company, N.A., as Successor Trustee, and certain indentures supplemental thereto through June 29, 2021. (Designated in Form 8-K dated May 14, 1998, File No. 001-11229, as Exhibit 4.1, in Form 8-K dated October 11, 2011, File No. 001-11229, as Exhibit 4.2(b), in Form 8-K dated March 5, 2012, File No. 001-11229, as Exhibit 4.2(b), in Form 8-K dated March 22, 2018, File No. 001-11229, as Exhibit 4.2(b), in Form 8-K dated June 24, 2021, F ile No. 001-11229, as Exhibit 4.2(a), and in Form 8-K dated June 24, 2021, File No. 001-11229, as Exhibit 4.2(b).)
Southern Power
	(e)	1	—	Senior Note Indenture dated as of June 1, 2002, between Southern Power Company and Computershare Trust Company, N.A., as Successor Trustee, and certain indentures supplemental thereto through January 8, 2021. (Designated in Registration No. 333-98553 as Exhibit 4.1, in Form 8-K dated September 14, 2011, File No. 333-98553, as Exhibit 4.4, in Form 8-K dated July 10, 2013, File No. 333-98553, as Exhibit 4.4, in Form 8-K dated November 12, 2015, File No. 333-98553, as Exhibit 4.4(a), in Form 8-K dated June 13, 2016, File No. 001-37803, as Exhibit 4.4(a), in Form 10-Q for the quarter ended September 30, 2016, File No. 001-37803, as Exhibit 4(f)1, in Form 10-Q for the quarter ended September 30, 2016, File No. 001-37803, as Exhibit 4(f)2, in Form 8-K dated November 10, 2016, File No. 001-37803, as Exhibit 4.4(b), in Form 8-K dated November 10, 2016, File No. 001-37803, as Exhibit 4.4(c), in Form 10-K for the year ended December 31, 2017, File No 001-37803, as Exhibit 4(f)2, and in Form 8-K dated January 5, 2021, File No. 001-37803, as Exhibit 4.4.)
	(e)	2	—	Description of securities registered pursuant to Section 12 of the Securities Exchange Act of 1934, as amended. (Designated in Form 10-K for the year ended December 31, 2019, File No. 001-37803, as Exhibit 4(e)2.)


Southern Company Gas
	(f)	1	—	Indenture dated February 20, 2001 between AGL Capital Corporation, AGL Resources Inc., and Computershare Trust Company, N.A., as Successor Trustee and First Supplemental Indenture thereto dated as of September 9, 2021. (Designated in Form S-3, File No. 333-69500, as Exhibit 4.2, and in Form 8-K dated September 7, 2021, File No. 1-14174 , as Exhi bit 4.2.)
	(f)	2	—	Southern Company Gas Capital Corporation's 6.00% Senior Notes due 2034, 5.875% Senior Notes due 2041, Form of Series B Senior Notes due 2018, 4.40% Senior Notes due 2043, 3.875% Senior Notes due 2025, 3.250% Senior Notes due 2026, Form of 2.450% Senior Note due October 1, 2023, Form of 3.950% Senior Note due October 1, 2046, Form of Series 2017A 4.400% Senior Note due May 30, 2047, Form of 2020A 1.750% Senior Note due January 15, 2031, and Form of Series 2021A 3.15% Senior Note due September 30, 2051. (Designated in Form 8-K dated September 22, 2004, File No. 1-14174, as Exhibit 4.1, in Form 8-K dated March 16, 2011, File No. 1-14174, as Exhibit 4.1, in Form 8-K dated August 31, 2011, File No. 1-14174, as Exhibit 4.2, in Form 8-K dated May 13, 2013, File No. 1-14174, as Exhibit 4.2, in Form 8-K dated November 13, 2015, File No. 1-14174, as Exhibit 4.2, in Form 8-K dated May 13, 2016, File No. 1-14174, as Exhibit 4.2, in Form 8-K dated September 8, 2016, File No. 1-14174, as Exhibit 4.1(a), in Form 8-K dated September 8, 2016, File No. 1-14174, as Exhibit 4.1(b), in Form 8-K dated May 5, 2017, File No. 1-14174, as Exhibit 4.1, in Form 8-K dated August 17, 2020, File No. 1-14174, as Exhibit 4.1, and in Form 8-K dated September 9, 2021, File No. 1-14174, as Exhibit 4.1, respectively.)
	(f)	3	—	Southern Company Gas' Guarantee related to the 6.00% Senior Notes due 2034, Guarantee related to the 5.875% Senior Notes due 2041, Guarantee related to the 4.40% Senior Notes due 2043, Guarantee related to the 3.875% Senior Notes due 2025, Guarantee related to the 3.250% Senior Notes due 2026, Form of Guarantee related to the 2.450% Senior Notes due October 1, 2023, Form of Guarantee related to the 3.950% Senior Notes due October 1, 2046, Form of Guarantee related to the Series 2017A 4.400% Senior Notes due May 30, 2047, Form of Guarantee related to the Series 2020A 1.750% Senior Notes due January 15, 2031, and Form of Guarantee related to the Series 2021A 3.15% Senior Note due September 30, 2051. (Designated in Form 8-K dated September 22, 2004, File No. 1-14174, as Exhibit 4.3, in Form 8-K dated September 15, 2011, File No. 1-14174, as Exhibit 4.2, in Form 8-K dated May 13, 2013, File No. 1-14174, as Exhibit 4.3, in Form 8-K dated November 13, 2015, File No. 1-14174, as Exhibit 4.3, in Form 8-K dated May 13, 2016, File No. 1-14174, as Exhibit 4.3, in Form 8-K dated September 8, 2016, File No. 1-14174, as Exhibit 4.3(a), in Form 8-K dated September 8, 2016, File No. 1-14174, as Exhibit 4.3(b), in Form 8-K dated May 5, 2017, File No. 1-14174, as Exhibit 4.3, in Form 8-K dated August 17, 2020, File No. 1-14174, as Exhibit 4.3, and in Form 8-K dated September 9, 2021, File No. 1-14174, as Exhibit 4.3, respectively.)
	(f)	4	—	Indenture dated December 1, 1989 of Atlanta Gas Light Company and First Supplemental Indenture thereto dated March 16, 1992. (Designated in Form S-3, File No. 33-32274, as Exhibit 4(a) and in Form S-3, File No. 33-46419, as Exhibit 4(a).)
	(f)	5	—	Indenture of Commonwealth Edison Company to Continental Illinois National Bank and Trust Company of Chicago, Trustee, dated as of January 1, 1954, Indenture of Adoption of Northern Illinois Gas Company to Continental Illinois National Bank and Trust Company of Chicago, Trustee, dated February 9, 1954, and certain indentures supplemental thereto. (Designated in Form 10-K for the year ended December 31, 1995, File No. 1-7296, as Exhibit 4.01, in Form 10-K for the year ended December 31, 1995, File No. 1-7296, as Exhibit 4.02, in Registration No. 2-56578 as Exhibits 2.21 and 2.25, in Form 10-Q for the quarter ended June 30, 1996, File No. 1-7296, as Exhibit 4.01, in Form 10-K for the year ended December 31, 1997, File No. 1-7296, as Exhibit 4.19, in Form 10-K for the year ended December 31, 2003, File No. 1-7296, as Exhibit 4.09, in Form 10-K for the year ended December 31, 2003, File No. 1-7296, as Exhibit 4.10, in Form 10-K for the year ended December 31, 2003, File No. 1-7296, as Exhibit 4.11, in Form 10-K for the year ended December 31, 2006, File No. 1-7296, as Exhibit 4.11, in Form 10-Q for the quarter ended September 30, 2008, File No. 1-7296, as Exhibit 4.01, in Form 10-Q for the quarter ended September 30, 2012, File No. 1-7296, as Exhibit 4, in Form 10-K for the year ended December 31, 2016, File No. 1-14174, as Exhibit 4(g)6, in Form 10-K for the year ended December 31, 2017, File No. 1-14174, as Exhibit 4(g)6, in Form 10-Q for the quarter ended September 30, 2018, File No. 1-14174, as Exhibit 4(g)1, in Form 10-K for the year ended December 31, 2019, File No. 1-14174, as Exhibit 4(f)6, in Form 10-K for the year e nded December 31, 2020, File No. 1 -14174, as Exhibit 4 (f)6, and in Form 10-Q for t he quarter ended September 30, 2021, File No. 1-4174, as Exhibit 4(f)4.)


	#	(a)	10	—	Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective December 16, 2020, by and between Southern Company and Wells Fargo Bank, National Association. (Designated in Form 10-K for the year ended December 31, 2020, File No. 1-3526, as Exhibit 10(a)10.)
	#	(a)	11	—	Southern Company Senior Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008, First Amendment thereto effective October 19, 2009, and Second Amendment thereto effective February 22, 2011. (Designated in Form 10-K for the year ended December 31, 2008, File No. 1-3526, as Exhibit 10(a)23, in Form 10-K for the year ended December 31, 2009, File No. 1-3526, as Exhibit 10(a)22, and in Form 10-K for the year ended December 31, 2010, File No. 1-3526, as Exhibit 10(a)16.)
	#	(a)	12	—	Southern Company Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008 and First Amendment thereto effective January 1, 2010. (Designated in Form 10-K for the year ended December 31, 2008, File No. 1-3526, as Exhibit 10(a)24 and in Form 10-K for the year ended December 31, 2009, File No. 1-3526, as Exhibit 10(a)24.)
	#	(a)	13	—	Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. (Designated in Form 10-Q for the quarter ended March 31, 2017, File No. 1-3526, as Exhibit 10(a)1).
	#	(a)	14	—	Deferred Compensation Agreement between Southern Company, SCS, Alabama Power, and Mark A. Crosswhite, effective July 30, 2008. (Designated in Form 10-K for the year ended December 31, 2016, File No. 1-3526, as Exhibit 10(a)17.)
		(a)	15	—	The Southern Company Employee Savings Plan, Amended and Restated effective January 1, 2018, First Amendment thereto effective January 1, 2018, Second Amendment thereto effective January 1, 2018, Third Amendment thereto effective January 1, 2018 and Fourth Amendment thereto effective as of January 1, 2018. (Designated in Post-Effective Amendment No. 1 to Form S-8, File No. 333-212783 as Exhibit 4.3, in Form 10-K for the year ended December 31, 2019, File No. 1-3526, as Exhibit 10(a)25, in Form 10-K for the year ended December 31, 2019, File No. 1-3526, as Exhibit 10(a)26, in Form 10-K for the year ended December 31, 2019, File No. 1-3526, as Exhibit 10(a)27 and in Form 10-K for the year ended December 31, 2020, File No . 1-3526, as Exhib it, 10(a)26.)
	#	(a)	16	—	Form of Terms for Restricted Stock Unit with Performance Measure Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. (Designated in Form 10-Q for the quarter ended March 31, 2017, File No. 1-3526, as Exhibit 10(a)2.)
	#	(a)	17	—	Letter Agreement among Southern Company Gas, Southern Company, and Andrew W. Evans and Performance Stock Unit Award Agreement, dated September 29, 2016. (Designated in Form 10-Q for the quarter ended March 31, 2017, File No. 1-3526, as Exhibit 10(a)3.)
	#	(a)	18	—	Form of Time-Vesting Restricted Stock Unit Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. (Designated in Form 10-Q for the quarter ended March 31, 2017, File No. 1-3526, as Exhibit 10(a)4.)
	#	(a)	19	—	Performance Stock Units Agreement, dated May 23, 2018, between Southern Company and Stephen E. Kuczynski. (Designated in Form 10-Q for the quarter ended March 31, 2019, File No. 1-3526, as Exhibit 10(a)1.)
	#	(a)	20	—	Retention and Restricted Stock Unit Agreement, dated May 23, 2018, between Southern Company and Stephen E. Kuczynski. (Designated in Form 10-Q for the quarter ended March 31, 2019, File No. 1-3526, as Exhibit 10(a)2.)
	#	(a)	21	—	Form of Terms for 2019 Equity Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. (Designated in Form 10-Q for the quarter ended March 31, 2019, File No. 1-3526, as Exhibit 10(a)3.)
	#	(a)	22	—	Form of Terms for 2020 Equity Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. (Designated in Form 10-Q for the quarter ended March 31, 2020, File No. 1-3526, as Exhibit 10(a).)
	#	(a)	23	—	The Southern Company Equity and Incentive Compensation Plan, effective May 26, 2021. (Designated in Form 8-K dated May 26, 2021, File No. 1-3526, as Exhibit 10.1.)
	#	(a)	24	—	Consulting Agreement between SCS and Andrew W. Evans dated August 23, 2021. (Designated in Form 10-Q for the quarter ended September 30, 2021, File No. 1-3526, as Exhibit 10(a).)
*	#	(a)	25	—	First Amendment to Amended and Restated Deferred Compensation Plan for Outside Directors of The Southern Company effective as of June 1, 2021.


Alabama Power
	(b)	1	—	Intercompany Interchange Contract as revised effective May 1, 2007, among Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and SCS and Appendix A thereto dated as of January 1, 2019. (Designated in Form 10-Q for the quarter ended March 31, 2007, File No. 1-3164, as Exhibit 10(b)5 and in Form 10-K for the year ended December 31, 2018, File No. 1-3164, as Exhibit 10(b)2.)
#	(b)	2	—	Southern Company 2011 Omnibus Incentive Compensation Plan effective May 25, 2011. See Exhibit 10(a)1 herein.
#	(b)	3	—	Form of Stock Option Award Agreement for Executive Officers of Southern Company under the Southern Company Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
#	(b)	4	—	Southern Company Deferred Compensation Plan, Amended and Restated as of January 1, 2018, First Amendment thereto dated as of December 7, 2018, and Second Amendment thereto dated as of January 29, 2019. See Exhibit 10(a)4 herein.
#	(b)	5	—	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective June 30, 2016, Amendment No. 1 thereto effective January 1, 2017, Amendment No. 2 thereto effective January 1, 2018, Amendment No. 3 thereto effective April 1, 2018, Amendment No. 4 thereto effective December 4, 2018, Amendment No. 5 thereto effective January 1, 2019 and Amendment No. 6 thereto effective January 1, 2019. See Exhibit 10(a)5 herein.
#	(b)	6	—	The Southern Company Supplemental Benefit Plan, Amended and Restated effective as of June 30, 2016, Amendment No. 1 thereto effective January 1, 2017, Amendment No. 2 thereto effective January 1, 2018, Amendment No. 3 thereto effective April 1, 2018, Amendment No. 4 thereto dated December 14, 2018, Amendment No. 5 thereto effective January 1, 2019 and Amendment No. 6 thereto effective January 1, 2019. See Exhibit 10(a)6 herein.
#	(b)	7	—	Southern Company Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008 and First Amendment thereto effective January 1, 2010. See Exhibit 10(a)12 herein.
#	(b)	8	—	Deferred Compensation Plan for Outside Directors of Alabama Power Company, Amended and Restated effective June 1, 2021. (Designated in Form 10-Q for the quarter ended June 30, 20 21 , File No. 1-3164, as Exhibit 10(b)2.)
#	(b)	9	—	The Southern Company Change in Control Benefits Protection Plan (an amendment and restatement of The Southern Company Change in Control Benefit Plan Determination Policy), effective December 31, 2008, Amendment No. 1 thereto effective March 1, 2018, and Amendment No. 2 thereto effective as of February 26, 2021. See Exhibit 10(a)7 herein.
#	(b)	10	—	Deferred Compensation Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective January 1, 2001, between Wells Fargo Bank, N.A., as successor to Wachovia Bank, N.A., Southern Company, SCS, Alabama Power, Georgia Power, Mississippi Power, Southern Linc, Southern Company Energy Solutions, LLC, and Southern Nuclear and First Amendment thereto effective January 1, 2009. See Exhibit 10(a)8 herein.
#	(b)	11	—	Amended and Restated Deferred Stock Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective December 16, 2020, by and between Southern Company and Computershare Trust Company, N.A.. See Exhibit 10(a)9 herein.
#	(b)	12	—	Amended and Restated Deferred Cash Compensation Trust Agreement for Directors of Southern Company and its Subsidiaries, Amended and Restated effective December 16, 2020, by and between Southern Company and Computershare Trust Company, N.A.. See Exhibit 10(a)10 herein.
#	(b)	13	—	Southern Company Senior Executive Change in Control Severance Plan, Amended and Restated effective December 31, 2008, First Amendment thereto effective October 19, 2009, and Second Amendment thereto effective February 22, 2011. See Exhibit 10(a)11 herein.
#	(b)	14	—	Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)13 herein.
#	(b)	15	—	Deferred Compensation Agreement between Southern Company, Alabama Power, Georgia Power, Mississippi Power, and SCS and Philip C. Raymond dated September 15, 2010. (Designated in Form 10-Q for the quarter ended September 30, 2010, File No. 1-3164, as Exhibit 10(b)2.)