The Southern Company (SO, NYSE)
Industry: Utilities - Regulated Electric
Annual report, fiscal year 2021


## 2021 Annual Report Vision in Motion




Contents

2 Chairman's Message

5 Financial Highlights

6 Cleaner energy from a transformed fleet

8 A reliable and resilient system

10 A more just and equitable society

12 Bigger than our bottom line

14 Leadership

16 Financial Contents











Every day at Southern Company, we put into motion our vision for the future of energy. It encompasses our century-long commitment to provide clean, safe, reliable and affordable energy to the customers we are privileged to serve, while making life in our communities better because we are there. Knowing that tomorrow’s needs are on today’s doorstep, we are aggressively working toward our net-zero emissions goal by transforming our generation fleet, researching next-generation energy technologies and constructing the first new nuclear units to be built in the U.S. in a generation. As we make smarter moves for our climate, we are delivering a more reliable and resilient system and advancing diversity, equity and inclusion in our workplace and in our communities. That’s our vision. Explore this report to learn more about how we put it in motion.



## Dear fellow shareholders,

At Southern Company, our vision is rooted in knowing energy provides an opportunity for people to live more comfortable and connected lives, fuels businesses that are shaping industries and creates possibilities for future generations. We put our vision in motion by placing our customers and communities at the center of everything we do. Understanding their needs and going out of our way to prepare them for what's ahead, our mission remains the same – provide clean, safe, reliable and affordable energy. Over 27,000 system employees work hard every day to deliver smart solutions anchored in remarkable service, resilience and safety.

In fact, here in the first few months of 2022, we were recognized by Fortune magazine as one of the World’s Most Admired Companies. This recognition is a testament to the thousands of people across our enterprise who are making thousands of good decisions every day in alignment with our core values of Safety First, Unquestionable Trust, Superior Performance and Total Commitment. You will find photographs of some of these employees displayed throughout this report. These individuals – and countless others – are the basis for our continued success, and I am proud to serve on their team.

This past year was an outstanding year for Southern Company, and we believe we are well-positioned to continue that momentum. We have a solid financial outlook, and our premier, state-regulated electric and gas utility franchises continue to be among our industry’s leaders for operational performance and customer satisfaction.

In 2021, Southern Company benefitted from strong customer growth, improving retail trends and continued investment in our state rate-regulated utilities. On an adjusted basis \( ^{*} \) , our company earned 3.62 billion, or 3.41 per share, compared with 3.44 billion, or 3.25 per share, for 2020. For nearly three quarters of a century, Southern Company has paid a dividend to its shareholders that is equal to or greater than the previous quarter. Notable highlights from 2021 are perhaps best appreciated through a brief review of the progress we achieved in each of our five strategic priorities:

## Excel at the Fundamentals

Southern Company’s keen focus on operational excellence and business fundamentals has resulted in a variety of industry awards and recognition. Nicror Gas was honored with the Midwest Energy Efficiency Alliance Award for outstanding service to customers in need. The Edison Electric Institute recognized Alabama Power with the Emergency Response Award. Virginia Natural Gas was recognized by the Virginia Oil and Gas Association as that state’s Local Distribution Company of the Year.

J.D. Power ranked Georgia Power among the very best in business customer satisfaction for large utilities in the South. Cogent Reports named both Georgia Power and Nicror Gas among their most trusted utility brands, and Chattanooga Gas among the most trusted business partners in the utility industry.

Achieve Success with Major Construction Projects
Despite the COVID-19 pandemic, we continued to make meaningful progress at Plant Vogtle units 3 and 4, and we are entering the final stages of testing for Unit 3. The project has continued to face challenges which have added to our project timelines and costs. The projected in-service range for Unit 3 is the fourth quarter of 2022 through the first quarter of 2023. We project that Unit 4 will be in service in the third or fourth quarter of 2023.

All 157 fuel assemblies at Unit 3 have been loaded into the spent fuel pool in preparation for fuel load. Direct construction of Unit 4 is approximately 92% complete. Our priority is bringing these units online safely, after which they are expected to serve as reliable carbon-free energy resources for customers for the next 60 to 80 years.

## Support the Building of a National Energy Policy

We maintained our ongoing commitment to advocate for a comprehensive national energy policy, actively engaging in



Thomas A. Fanning
Chairman, President & CEO,
Southern Company



public policy dialogue and working constructively with regulators and legislators to support policies that advance innovation and benefit our industry, our business and the customers we serve.

## Promote Energy Innovation

Southern Company and the United States Department of Energy have established a cooperative agreement to design, construct and operate the Molten Chloride Reactor Experiment – the world’s first critical fast-spectrum salt reactor and a technology considered important to a sustainable clean energy future. Southern Company’s research and development (R&D) organization will lead this effort in collaboration with Terra-Power, Idaho National Laboratory, CORE POWER, Orano Federal Services, the Electric Power Research Institute and 3M Company.

Southern Company has also joined the Hydrogen Council, a global, CEO-led coalition of companies with a united vision and long-term ambition for hydrogen to foster a clean energy transition. The Council believes hydrogen will play a key role in reaching global decarbonization goals by helping diversify energy sources and by fostering business and technological innovation. Southern Company is embracing the role of hydrogen as a potentially powerful solution to holistically serve the needs of customers while providing a resilient energy system in a decarbonized energy environment.

Southern Company’s R&D organization is actively engaged both domestically and internationally in a portfolio of projects focused on power generation delivery, transportation, infrastructure and energy storage, as well as low-carbon hydrogen production and developing a national road map for the deployment of hydrogen-based energy.

## Value and Develop Our People

Southern Company has been named the number two Best Large Employer in America by Forbes magazine. Of the 500 large employers included in the ranking, Southern Company was first among energy industry peers, first among Georgia-based companies and first in the entire Southeast. This recognition is especially gratifying because it was based directly on employee feedback.
For the sixth consecutive year, we were recognized as one of the Top 50 Companies for Diversity by DiversityInc. Southern Company earned a 100 percent rating from the Human Rights Campaign (HRC) on their 2022 Corporate Equality Index, also for the sixth consecutive year. Likewise, the HRC’s Disability Equality Index recognized Southern Company as one of the Best Places to Work for Disability Inclusion.

We also take great pride in our longstanding commitment to hiring military veterans. In 2021, we were named the number one Best for Vets Employer by Military Times magazine.

I believe all these accolades are a tangible result of our commitment to value and develop our people, and our efforts to create a workplace where all groups are well-represented, included and treated fairly and where everyone feels welcome, valued and respected.

In closing, the foundation of our business remains strong as we continue to execute on our vision. With performance characterized by outstanding fundamentals, high customer satisfaction, operational excellence and constructive regulatory relationships, our success is the direct result of an unwavering emphasis on the core values that have shaped our company’s identity since its inception.

Our customer-focused business model continues to be the cornerstone for delivering value to customers and shareholders alike, and our management team is experienced and motivated, with a long track record of successfully executing on this time-tested model. We believe our company is poised for continued success, both today and in the years ahead.

We are grateful for your continued confidence in Southern Company. It is a privilege to serve you.

Sincerely,



Thomas A. Fanning

March 29, 2022



## Financial Highlights



Basic Earnings Per Share
(in dollars)



Return On Average Common Equity (percent)



Basic Earnings Per Share – Excluding Items \( ^{*} \)  (in dollars)

* Not a financial measure under generally accepted accounting principles. See Reconciliation of Non-GAAP Financial Metrics on page 21 for additional information and specific adjustments made to this measure by year.



Dividends Per Share
(in dollars)

<table><tr><td></td><td>2021</td><td>2020</td><td>Change</td></tr><tr><td>Operating Revenues (in millions)</td><td>$23,113</td><td>$20,375</td><td>13.4 %</td></tr><tr><td>Earnings (in millions)</td><td>$2,393</td><td>$3,119</td><td>(23.3)%</td></tr><tr><td>Basic Earnings Per Share</td><td>$2.26</td><td>$2.95</td><td>(23.4)%</td></tr><tr><td>Diluted Earnings Per Share</td><td>$2.24</td><td>$2.93</td><td>(23.5)%</td></tr><tr><td>Dividends Per Share (amount paid)</td><td>$2.62</td><td>$2.54</td><td>3.1 %</td></tr><tr><td>Dividend Yield (year-end, percent)</td><td>3.8</td><td>4.1</td><td>(7.3)%</td></tr><tr><td>Average Shares Outstanding (in millions)</td><td>1,061</td><td>1,058</td><td>0.3 %</td></tr><tr><td>Return On Average Common Equity (percent)</td><td>8.57</td><td>11.24</td><td>(23.8)%</td></tr><tr><td>Book Value Per Share</td><td>$26.30</td><td>$26.48</td><td>(0.7)%</td></tr><tr><td>Market Price Per Share (year-end, closing)</td><td>$68.58</td><td>$61.43</td><td>11.6 %</td></tr><tr><td>Total Market Value Of Common Stock (year-end, in millions)</td><td>$72,693</td><td>$64,899</td><td>12.0 %</td></tr><tr><td>Total Assets (in millions)</td><td>$127,534</td><td>$122,935</td><td>3.7 %</td></tr><tr><td>Total Kilowatt-Hour Sales (in millions)</td><td>193,380</td><td>186,225</td><td>3.8 %</td></tr><tr><td>Retail</td><td>143,370</td><td>140,546</td><td>2.0 %</td></tr><tr><td>Wholesale</td><td>50,010</td><td>45,679</td><td>9.5 %</td></tr><tr><td>Total Utility Customers (year-end, in thousands)</td><td>8,722</td><td>8,630</td><td>1.1 %</td></tr></table>











2007
A. 16% Gas
B. 14% Nuclear
C. 69% Coal
D. 1% Renewables/Other



2021
A. 48% Gas
B. 16% Nuclear
C. 21% Coal
D. 15% Renewables/Other



* Represents the energy the Southern Company system uses to serve its retail and wholesale customers. Does not represent any particular customer or customer class. Includes non-affiliate PPAs. Renewables/Other includes wind, solar, hydro, biomass and landfill gas. For certain renewable generation and associated renewable energy credits (RECs), to the extent an affiliate of Southern Company has the right to the RECs associated with renewable energy it generates or purchases, it retains the right to sell the energy and RECs, either bundled or separately, to retail customers and third parties.



The vision:

# Cleaner energy from
a transformed fleet

We are aggressively transforming our energy generation fleet to lower carbon-emitting sources to better serve customers and communities with cleaner energy.

We like to say that innovation is in our DNA, and across the Southern Company system we work hard each day to deliver increasingly clean energy with the same safety, reliability and affordability that our customers have come to expect.

In 2021, nearly one third of our energy mix came from zero-carbon sources, including renewables like solar, wind and hydro, and carbon-free nuclear energy. Over the past 15 years, we have closed or repowered 46 coal-fired generating units, representing over 9,000 megawatts. We are working in lockstep with our state regulators through integrated resource planning processes to transform our energy generation fleet, adding more renewables and modernizing our hydroelectric generation.

Southern Company is targeting net zero greenhouse gas (GHG) emissions by 2050. Net zero is a scenario where any GHG emissions from operations are balanced by an equivalent amount of GHG removal. Southern Company Gas is continuing to modernize its infrastructure to help ensure that the natural gas we deliver to homes and businesses is clean, safe, reliable and affordable.

At the same time, our industry-leading R&D organization is on the front lines developing energy storage solutions and zero-carbon technologies. As we plan for this energy future, we are carefully coordinating the development of these new resources with the grid to help ensure continued reliability and resilience.

We are off to a great start on our goal, and expect to sustainably achieve an interim 50% reduction in GHG emissions by 2025, compared with 2007 baseline levels – five years in advance of our target of 2030.

(Left) Skookumchuck Wind Facility, located in Lewis and Thurston Counties, Washington. Skookumchuck is one of the newest renewable generating facilities of Southern Power, Southern Company’s wholesale energy subsidiary.







The vision:

# A reliable and resilient
system second to none

Delivering the future of energy requires that we protect that future. Southern Company employs multiple layers of security to help ensure the resilience of our system.

Since the inception of Southern Company more than 100 years ago, the delivery of energy to homes and businesses has changed significantly. No longer just a matter of power poles or pipelines, advanced technology is now an integral part of the process. Protecting those technological assets from cyber threats is just as important as protecting our physical assets.

“Cybersecurity has become paramount, day in and day out,” explains Martin Davis, chief information officer (CIO) for Southern Company. “As a critical part of the infrastructure of the United States, we’ve got to protect it at all costs.” Just as cyber threats are ever-changing, Southern Company is ever-diligent in its efforts to protect its technological assets.

“We employ a ‘defense in-depth’ approach to cybersecurity,” adds Davis. “This is very similar to the way in which you might seek to protect your home. For example, you might have a doorbell camera at your front door, an alarm system and perhaps other surveillance cameras inside your home. Our approach to cybersecurity is much the same, with layers of defense for our network, our telecommunications, our computers and our data.”

As CIO, Davis oversees more than 2,000 employees in the company’s Technology Organization, including a dedicated team who staff our Security Operations Center, where company operations are monitored around the clock.

(Right) Employees at Southern Company’s Security Operations Center are on the front lines of the company’s 24/7 cybersecurity efforts.












The vision:

# A more just and equitable society

Southern Company has long been a leader in the fight for social justice and equity, both in the workplace and in the communities we serve.

This commitment guides not only our business priorities and partnerships, it informs our approach to philanthropic giving as we endeavor to bolster equity for all groups, especially underserved or historically marginalized groups.

In 2021, we continued to assess how we conduct our business and what improvements might serve to advance these objectives. We implemented measures designed to eliminate unconscious bias from our hiring process. Underscoring our commitment to supplier diversity, Southern Company subsidiaries established a goal to increase their utilization of minority-owned businesses to 30% of total spend. We invested more than $66 million to advance racial equity and social justice in our communities as part of a larger commitment to invest $225 million through 2025. This social justice strategy targets giving of $25 million to advance energy justice, $50 million to promote criminal justice reform, $50 million for economic empowerment and $100 million to advance educational equity.

Among the highlights of our philanthropic giving in 2021 was a landmark $5 million donation by the Southern Company Foundation to establish the Center for Civil Rights and Social Justice at the Emory University School of Law. The Foundation has also announced $10 million in grants to fund a new and innovative collaboration between INROADS, one of the nation's largest nonprofit developers of underrepresented talent, the United Negro College Fund and the Thurgood Marshall College Fund, all global leaders in providing financial support to students at Historically Black Colleges and Universities.

Finally, we published our first-ever Southern Company Transformation Report to document our progress against these goals of increased cultural understanding and community involvement.

(Right) Employees representing a variety of Southern Company subsidiaries meeting at the Energy Center in Birmingham, Alabama.















Employees throughout the Southern Company system regularly volunteer for a myriad of conservation-minded projects such as tree plantings.






The vision:

# Bigger than our
bottom line

We are committed to being “A Citizen Wherever We Serve,” meaning our employees are inextricably woven into the communities we are privileged to serve.

At Southern Company, we have long believed corporate responsibility and corporate strategy should be closely linked. Employee volunteerism and support of community initiatives, both large and small, are hallmarks of Southern Company and our subsidiaries. Employees and retirees dedicate approximately 200,000 hours of volunteer service annually to support and improve our communities. In 2021, charitable giving across the Southern Company System totaled $110 million. We are committed to investing more than $225 million in community social justice efforts through 2025.

Similarly, our environmental goals and progress remain core to Southern Company’s overall strategy and corporate responsibility. The pillars of our environmental strategy are leading through innovation, promoting conservation and environmental stewardship, engaging in robust research and development and holding ourselves accountable with transparent reporting. These concepts guide how we conduct business.

That is why we were one of the first U.S. energy companies to establish a sustainable financing framework. As of the end of 2021, we were one of the top five corporate, non-financial green bond issuers in the nation.

We have a long history of partnering with communities, conservation organizations and natural resource agencies to help threatened and vulnerable species, restore forests, clean waterways and increase environmental awareness. Volunteers have removed millions of tons of debris from waterways through the Renew Our Rivers program, and we have funded the preservation of land for recreational use.

Through our partnership with the National Fish and Wildlife Foundation, we have supported hundreds of projects and invested more than $21 million in grants with a total on the ground conservation impact valued at over $180 million, restoring and enhancing over 1.9 million acres.







Thomas A. Fanning



Janaki Akella



Juanita Powell Baranco



Henry A. Clark III



Anthony F. Earley, Jr.



David J. Grain



Colette D. Honorable



Donald M. James



John D. Johns



Dale E. Klein



Ernest J. Moniz



William G. Smith, Jr.



Kristine L. Svinicki



E. Jenner Wood III

## Management Council



Thomas A. Fanning



Bryan D. Anderson



Stanley W. Connally, Jr.



Mark A. Crosswhite



Christopher Cummiskey



Martin B. Davis



Kimberly S. Greene



James Y. Kerr II



Stephen E. Kuczynski



Daniel S. Tucker



Anthony L. Wilson



Christopher C. Womack



## Board of Directors

Thomas A. Fanning
Chairman, President and CEO, Southern Company
Atlanta, GA | Age 65 | elected 2010

Janaki Akella
Digital Transformation Leader
Google LLC (technology)
Palo Alto, CA | Age 61 | elected 2019

Juanita Powell Baranco
Executive Vice President and Chief Operating Officer
Baranco Automotive Group (automobile sales)
Atlanta, GA | Age 73 | elected 2006

Henry A. Clark III
Retired Senior Advisor, Evercore Inc.
(global independent investment advisory firm)
Hobe Sound, FL | Age 72 | elected 2009

Anthony F. Earley, Jr.
Retired Chairman, President and CEO
PG&E Corporation (utility)
Bloomfield Hills, MI | Age 72 | elected 2019

David J. Grain
CEO and Managing Director
Grain Management, LLC (private equity firm)
Sarasota, FL | Age 59 | elected 2012

Colette D. Honorable
Partner, Reed Smith LLP (legal)
Washington, DC | Age 52 | elected 2020

Donald M. James
Retired Chairman and CEO, Vulcan Materials Company (construction materials)
Pensacola, FL | Age 73 | elected 1999

## Management Council

Thomas A. Fanning
Chairman, President and CEO
Fanning, 65, joined the company in 1980

Bryan D. Anderson
Executive Vice President and President, External Affairs
Anderson, 55, joined the company in 2010

Stanley W. Connally, Jr.
Executive Vice President, Operations, Southern Company
Chairman, President and Chief Executive Officer, Southern Company Services, Inc.
Connaly, 52, joined the company in 1989

Mark A. Crosswhite
Chairman, President and CEO, Alabama Power
Crosswhite, 59, joined the company in 2004

Christopher Cummiskey
Executive Vice President, Chief Commercial and Customer Solutions Officer
Cummiskey, 47, joined the company in 2013

Martin B. Davis
Executive Vice President and Chief Information Officer
Davis, 59, joined the company in 2015

John D. Johns
Retired Chairman of DLI North America Inc., the oversight company for Protective Life Insurance Corporation (insurance)
Birmingham, AL | Age 70 | elected 2015

Dale E. Klein
Associate Vice Chancellor of Research, University of Texas System
Retired Chairman, U.S. Nuclear Regulatory Commission (energy)
Austin, TX | Age 74 | elected 2010

Ernest J. Moniz
Cecil and Ida Green Professor of Physics and Engineering Systems emeritus,
Massachusetts Institute of Technology
CEO and Co-Chair, Nuclear Threat Initiative (energy)
Former U.S. Secretary of Energy
Brookline, MA | Age 77 | elected 2018

William G. Smith, Jr.
Chairman, President and CEO, Capital City Bank Group, Inc. (banking)
Tallahassee, FL | Age 68 | elected 2006

Kristine L. Svinicki
Managing Director, The Svinicki Group LLC
Former Chairman, Nuclear Regulatory Commission
Miami Beach, FL | Age 55 | elected 2021

E. Jenner Wood III
Retired Corporate Executive Vice President – Wholesale Banking,
SunTrust Banks, Inc. (banking)
Atlanta, GA | Age 70 | elected 2012

Kimberly S. Greene
Chairman, President and CEO, Southern Company Gas
Greene, 55, has held her current role since June 2018

James Y. Kerr II
Executive Vice President, Chief Legal Officer and Chief Compliance Officer
Kerr, 58, joined the company in March 2014

Stephen E. Kuczynski
Chairman, President and CEO, Southern Nuclear
Kuczynski, 59, joined the company in July 2011

Daniel S. Tucker
Executive Vice President and Chief Financial Officer
Tucker, 51, joined the company in 1998

Anthony L. Wilson
Chairman, President and CEO, Mississippi Power
Wilson, 58, joined the company in 1984

Christopher C. Womack
Chairman, President and CEO, Georgia Power
Womack, 64, joined the company in 1988



## Financial Contents

17 Definitions
21 Reconciliation of Non-GAAP Financial Metric
22 Cautionary Statement Regarding Forward-Looking Statements
23 Available Information
24 Southern Company Business
24 Five-Year Cumulative Performance Graph
25 Management's Report on Internal Control Over Financial Reporting
26 Report of Independent Registered Public Accounting Firm
30 Management's Discussion and Analysis of Financial Condition and Results of Operations
70 Consolidated Statements of Income
71 Consolidated Statements of Comprehensive Income
72 Consolidated Statements of Cash Flows
74 Consolidated Balance Sheets
76 Consolidated Statements of Stockholders' Equity
77 Index to the Notes to Financial Statements
78 Notes to Financial Statements



## Definitions

## 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

## 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

## 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

## 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



## Definitions

## 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

## IGCC

Integrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility

## 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

## 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

## Moody's

Moody's Investors Service, Inc.

## MPUS

Mississippi Public Utilities Staff

## MRA

Municipal and Rural Associations

## MW

Megawatt

## natural gas distribution utilities

Southern Company Gas' natural gas distribution utilities (Nico Gas, Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas)

## NCCR

Georgia Power's Nuclear Construction Cost Recovery tariff



## Definitions

## NDR

Alabama Power's Natural Disaster Reserve

## NextEra Energy

NextEra Energy, Inc.

## Nior 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

## Sequent

Sequent Energy Management, L.P. and Sequent Energy Canada Corp., wholly-owned subsidiaries of Southern Company Gas through June 30, 2021

## SNG

Southern Natural Gas Company, L.L.C., a pipeline system in which Southern Company Gas has a 50% ownership interest

## SO₂

Sulfur dioxide

## 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



## Definitions

## 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



<table><tr><td rowspan="2">(In millions, except earnings per share)</td><td colspan="5">Year Ended December 31,</td></tr><tr><td>2021</td><td>2020</td><td>2019</td><td>2018</td><td>2017</td></tr><tr><td>Net Income - GAAP</td><td>$ 2,393</td><td>$3,119</td><td>$ 4,739</td><td>$ 2,226</td><td>$ 842</td></tr><tr><td>Average Shares Outstanding</td><td>1,061</td><td>1,058</td><td>1,046</td><td>1,020</td><td>1,000</td></tr><tr><td>Basic Earnings Per Share</td><td>$ 2.26</td><td>$ 2.95</td><td>$ 4.53</td><td>$ 2.18</td><td>$ 0.84</td></tr><tr><td>Net Income - GAAP</td><td>$ 2,393</td><td>$3,119</td><td>$ 4,739</td><td>$ 2,226</td><td>$ 842</td></tr><tr><td>Less Non-GAAP Excluding Items:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Acquisition, Disposition, and Integration Impacts(1)</td><td>209</td><td>60</td><td>2,516</td><td>35</td><td>(35)</td></tr><tr><td>Tax Impact</td><td>(90)</td><td>(22)</td><td>(1,081)</td><td>(294)</td><td>(12)</td></tr><tr><td>Estimated Loss on Plants Under Construction(2)</td><td>(1,703)</td><td>(328)</td><td>(27)</td><td>(1,102)</td><td>(3,366)</td></tr><tr><td>Tax Impact</td><td>433</td><td>84</td><td>—</td><td>376</td><td>975</td></tr><tr><td>Loss on Plant Scherer Unit 3(3)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(33)</td></tr><tr><td>Tax Impact</td><td>—</td><td>—</td><td>—</td><td>—</td><td>13</td></tr><tr><td>Wholesale Gas Services(4)</td><td>18</td><td>17</td><td>215</td><td>42</td><td>(57)</td></tr><tr><td>Tax Impact</td><td>(3)</td><td>(3)</td><td>(52)</td><td>(4)</td><td>—</td></tr><tr><td>Asset Impairments(5)</td><td>(91)</td><td>(206)</td><td>(108)</td><td>—</td><td>—</td></tr><tr><td>Tax Impact</td><td>19</td><td>101</td><td>26</td><td>—</td><td>—</td></tr><tr><td>Litigation Settlement Proceeds(6)</td><td>—</td><td>—</td><td>—</td><td>24</td><td>—</td></tr><tr><td>Tax Impact</td><td>—</td><td>—</td><td>—</td><td>(6)</td><td>—</td></tr><tr><td>Loss on Extinguishment of Debt(7)</td><td>(23)</td><td>(29)</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Tax Impact</td><td>6</td><td>7</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Earnings Guidance Comparability Items(8):</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity Return Related to Kemper IGCC Schedule Extension</td><td>—</td><td>—</td><td>—</td><td>—</td><td>47</td></tr><tr><td>Tax Impact</td><td>—</td><td>—</td><td>—</td><td>—</td><td>9</td></tr><tr><td>Adoption of Tax Reform</td><td>—</td><td>—</td><td>—</td><td>27</td><td>284</td></tr><tr><td>Net Income - Excluding Items</td><td>$ 3,618</td><td>$3,438</td><td>$ 3,250</td><td>$ 3,128</td><td>$ 3,017</td></tr><tr><td>Basic Earnings Per Share - Excluding Items</td><td>$ 3.41</td><td>$ 3.25</td><td>$ 3.11</td><td>$ 3.07</td><td>$ 3.02</td></tr></table>

(1) Net income for the year ended December 31, 2021 includes: (i) a $93 million pre-tax ($99 million after-tax) gain associated with the termination of a leasehold interest in assets associated with two leveraged lease projects; (ii) $16 million of income tax benefits recognized as the result of another leveraged lease investment disposition; and (iii) a $121 million pre-tax ($92 million after-tax) gain on the sale of Sequent, as well as $85 million of additional tax expense due to the resulting changes in state apportionment rates. Net income for the year ended December 31, 2020 includes: (i) a $39 million pre-tax ($23 million after-tax) gain on the sale of Plant Mankato and (ii) a $22 million pre-tax ($16 million after-tax) gain on the sale of a natural gas storage facility. Net income for the year ended December 31, 2019 includes: (i) a $2.6 billion pre-tax ($1.4 billion after-tax) gain on the sale of Gulf Power; (ii) a $23 million pre-tax ($88 million after-tax) gain on the sale of Plant Nacagdoches; and (iii) $18 million pre-tax ($11 million after-tax) of other acquisition, disposition, and integration impacts, partially offset by: (i) a $58 million pre-tax ($52 million after-tax) net loss, including impairment charges, associated with the sales of PowerSecure's utility infrastructure services and lighting businesses and (ii) a $24 million pre-tax ($17 million after-tax) impairment charge in contemplation of the sale of Pivotal LNG and Atlantic Coast Pipeline. Net income for the year ended December 31, 2018 includes: (i) a net combined $249 million pre-tax gain ($93 million after-tax loss) on the sales of Elizabethtown Gas, Elkton Gas, Florida City Gas, and Pivotal Home Solutions, including a related impairment charge; (ii) a $119 million pre-tax ($89 million after-tax) impairment charge associated with the sales of Plants Stanton and Oleander; and (iii) $95 million pre-tax ($77 million after-tax) of other acquisition, disposition, and integration costs. Net income for the year ended December 31, 2017 includes costs related to the acquisition and integration of Southern Company Gas and costs related to the dispositions of Elizabethtown Gas and Elkton Gas.

(2) Net income for the years ended December 31, 2021, 2020, and 2018 includes aggregate charges of $1.7 billion pre tax ($1.3 billion after tax), $325 million pre tax ($242 million after tax), and $1.1 billion pre tax ($0.8 billion after tax), respectively, for estimated probable losses associated with Georgia Power's construction of Plant Vogtle Units 3 and 4. Net income for all periods presented includes charges (net of salvage proceeds), associated legal expenses (net of insurance recoveries), and tax impacts related to Mississippi Power's construction and abandonment of the Kemper IGCC. Mississippi Power expects to incur additional pre-tax period costs to complete dismantlement of the abandoned gasifier-related assets and site restoration activities, including related costs for compliance and safety, asset retirement obligation accretion, and property taxes, net of salvage, totaling $10 million to $20 million annually through 2025. Further charges related to Plant Vogtle Units 3 and 4 may occur; however, the amount and timing of any such charges are uncertain.

(3) Net income for the year ended December 31, 2017 includes a $32.5 million write-down ($20 million after tax) of Gulf Power's ownership of Plant Scherer Unit 3 as the result of a retail rate case settlement.

(4) Net income for all periods presented includes the Wholesale Gas Services business, which was sold on July 1, 2021. Presenting net income and earnings per share excluding Wholesale Gas Services provides an additional measure of operating performance that excludes the volatility resulting from mark-to-market and lower of weighted average cost or current market price accounting adjustments.

(5) Net income for the years ended December 31, 2021, 2020, and 2019 includes impairment charges associated with two leveraged leases. Net income for the year ended December 31, 2021 also includes pre-tax impairment charges totaling $84 million ($67 million after tax) related to Southern Company Gas' investment in the PennEast Pipeline project. Net income for the year ended December 31, 2019 also includes impairment charges associated with a natural gas storage facility. Further impairment charges associated with these assets are not expected.

(6) Net income for the year ended December 31, 2018 includes the settlement proceeds of Mississippi Power's claim for lost revenue resulting from the 2010 Deepwater Horizon oil spill. No further proceeds are expected.

(7) Net income for the years ended December 31, 2021 and 2020 includes costs associated with the extinguishment of debt at Southern Company. Further debt extinguishment charges may occur at Southern Company or its non-regulated subsidiaries; however, the amount and timing of any such costs are uncertain.

(8) Net income for the year ended December 31, 2017 includes AFUDC equity as a result of extending the schedule for the Kemper IGCC construction project beyond the dates assumed when Southern Company's 2017 earnings guidance was initially presented. AFUDC equity ceased in connection with the project's suspension in June 2017. Net income for the years ended December 31, 2018 and 2017 includes net tax benefits as a result of implementing the Tax Reform Legislation. During 2018, Southern Company obtained and analyzed additional information that was not initially available or reported as provisional amounts at December 31, 2017. Southern Company believes presentation of earnings per share excluding these adjustments provided investors with information comparable to guidance and used such measures to evaluate performance.



Southern Company’s Annual Report 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;

• 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,” 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;

• 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;



## Cautionary Statement Regarding Forward-Looking Statements (continued)

• 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.

Southern Company expressly disclaims any obligation to update any forward-looking statements.

## Available Information

Southern Company’s Annual Report on Form 10-K for the year ended December 31, 2021 (Form 10-K), as well as other documents filed by Southern Company pursuant to the Securities Exchange Act of 1934, as amended, are available electronically at http://www.sec.gov.

A copy of the Form 10-K as filed with the Securities and Exchange Commission will be provided without charge upon written request to the office of the Corporate Secretary. Requests for copies should be directed to the Corporate Secretary, 30 Ivan Allen Jr. Blvd., N.W., Atlanta, GA 30308.

The “Management’s Discussion and Analysis of Financial Condition and Results of Operations” herein 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 can be found in Item 7 of Southern Company’s Annual Report on Form 10-K for the year ended December 31, 2020, which was filed with the SEC on February 17, 2021.



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. 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.

## Five-Year Cumulative Performance Graph

This performance graph compares the cumulative total shareholder return on Southern Company’s common stock with the Standard & Poor’s 500 index and the Philadelphia Utility Index for the past five years. The graph assumes that $100 was invested on December 30, 2016 in Southern Company’s common stock and each of the indices and that all dividends were reinvested. The stockholder return shown for the five-year historical period may not be indicative of future performance.






## Management’s Report on Internal Control Over Financial Reporting

The management of Southern Company is responsible for establishing and maintaining an adequate system of internal control over financial reporting as required by the Sarbanes-Oxley Act of 2002 and as defined in Exchange Act Rule 13a-15(f). A control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Under management’s supervision, an evaluation of the design and effectiveness of Southern Company’s internal control over financial reporting was conducted based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Southern Company’s internal control over financial reporting was effective as of December 31, 2021.

Deloitte & Touche LLP, as auditors of Southern Company’s financial statements, has issued an attestation report on the effectiveness of Southern Company’s internal control over financial reporting as of December 31, 2021, which is included herein.



Thomas A. Fanning

Chairman, President, and Chief Executive Officer



Daniel S. Tucker

Executive Vice President and Chief Financial Officer

February 16, 2022



## 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.



## 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.

• 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.

• 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.



## Report of Independent Registered Public Accounting Firm

• 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.

## Deloitte & Touche LLP

Atlanta, Georgia

February 16, 2022

We have served as Southern Company’s auditor since 2002.



## 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.

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.

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



## Management’s Discussion and Analysis of Financial Condition and Results of Operations

$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.

## 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.



## Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 Tranquility battery energy storage facility. Southern Power continues construction of the remainder of the Garland and Tranquility 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 Invergency Renewables LLC.

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.

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.

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 Nicro 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.

## 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.

<table><tr><td></td><td>2021</td><td>2020</td></tr><tr><td></td><td colspan="2">(in millions)</td></tr><tr><td>Electricity business</td><td>$2,247</td><td>$3,115</td></tr><tr><td>Gas business</td><td>539</td><td>590</td></tr><tr><td>Other business activities</td><td>(393)</td><td>(586)</td></tr><tr><td>Net Income</td><td>$2,393</td><td>$3,119</td></tr></table>



## 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:

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

## 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:

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

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.



## Management’s Discussion and Analysis of Financial Condition and Results of Operations

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:

<table><tr><td></td><td>2021</td><td>2020</td></tr><tr><td></td><td colspan="2">(in millions)</td></tr><tr><td>Capacity and other</td><td>$ 550</td><td>$ 476</td></tr><tr><td>Energy</td><td>1,905</td><td>1,469</td></tr><tr><td>Total</td><td>$2,455</td><td>$1,945</td></tr></table>

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.



## Management’s Discussion and Analysis of Financial Condition and Results of Operations

## 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:

<table><tr><td rowspan="2"></td><td colspan="3">2021</td></tr><tr><td>Total KWHs</td><td>Total KWH Percent Change</td><td>Weather-Adjusted Percent Change \( ^{(1)} \)</td></tr><tr><td></td><td>(in billions)</td><td></td><td></td></tr><tr><td>Residential</td><td>47.4</td><td>(0.2)%</td><td>0.5%</td></tr><tr><td>Commercial</td><td>46.7</td><td>2.7</td><td>3.2</td></tr><tr><td>Industrial</td><td>48.7</td><td>3.7</td><td>3.7</td></tr><tr><td>Other</td><td>0.6</td><td>(5.1)</td><td>(5.1)</td></tr><tr><td>Total retail</td><td>143.4</td><td>2.0</td><td>2.4%</td></tr><tr><td>Wholesale</td><td>50.0</td><td>9.5</td><td></td></tr><tr><td>Total energy sales</td><td>193.4</td><td>3.8%</td><td></td></tr></table>

(*) 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.

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

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

(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



## Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 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 Tranquility 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 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:

<table><tr><td></td><td>2021</td><td>Increase (Decrease) from 2020 (in millions)</td></tr><tr><td>Operating revenues</td><td>$4,380</td><td>$ 946</td></tr><tr><td>Cost of natural gas</td><td>1,619</td><td>647</td></tr><tr><td>Other operations and maintenance</td><td>1,072</td><td>106</td></tr><tr><td>Depreciation and amortization</td><td>536</td><td>36</td></tr><tr><td>Taxes other than income taxes</td><td>225</td><td>19</td></tr><tr><td>Gain on dispositions, net</td><td>(127)</td><td>(105)</td></tr><tr><td>Total operating expenses</td><td>3,325</td><td>703</td></tr><tr><td>Operating income</td><td>1,055</td><td>243</td></tr><tr><td>Earnings from equity method investments</td><td>50</td><td>(91)</td></tr><tr><td>Interest expense, net of amounts capitalized</td><td>238</td><td>7</td></tr><tr><td>Other income (expense), net</td><td>(53)</td><td>(94)</td></tr><tr><td>Income taxes</td><td>275</td><td>102</td></tr><tr><td>Net income</td><td>$ 539</td><td>$ (51)</td></tr></table>

## 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.

## 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:

<table><tr><td></td><td>2021</td></tr><tr><td>Operating revenues - prior year</td><td>$3,434</td></tr><tr><td>Estimated change resulting from -</td><td></td></tr><tr><td>Infrastructure replacement programs and base rate changes</td><td>146</td></tr><tr><td>Gas costs and other cost recovery</td><td>675</td></tr><tr><td>Wholesale gas services</td><td>114</td></tr><tr><td>Other</td><td>11</td></tr><tr><td>Operating revenues - current year</td><td>$4,380</td></tr></table>



## Management’s Discussion and Analysis of Financial Condition and Results of Operations

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.

## 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 Nicro 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.

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

<table><tr><td></td><td>2021</td><td>Increase (Decrease) from 2020</td></tr><tr><td></td><td colspan="2">(in millions)</td></tr><tr><td>Operating revenues</td><td>$ 433</td><td>$ (11)</td></tr><tr><td>Cost of other sales</td><td>249</td><td>15</td></tr><tr><td>Other operations and maintenance</td><td>207</td><td>11</td></tr><tr><td>Depreciation and amortization</td><td>75</td><td>(2)</td></tr><tr><td>Taxes other than income taxes</td><td>4</td><td>—</td></tr><tr><td>Gain on dispositions, net</td><td>—</td><td>1</td></tr><tr><td>Total operating expenses</td><td>535</td><td>25</td></tr><tr><td>Operating income (loss)</td><td>(102)</td><td>(36)</td></tr><tr><td>Earnings from equity method investments</td><td>26</td><td>14</td></tr><tr><td>Interest expense</td><td>631</td><td>17</td></tr><tr><td>Impairment of leveraged leases</td><td>7</td><td>(199)</td></tr><tr><td>Other income (expense), net</td><td>94</td><td>103</td></tr><tr><td>Income taxes (benefit)</td><td>(227)</td><td>70</td></tr><tr><td>Net loss</td><td>(393)</td><td>$ 193</td></tr></table>

## 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.

## 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.

## 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.

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.

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.

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:

<table><tr><td></td><td>2022</td><td>2023</td><td>2024</td><td>2025</td><td>2026</td><td>Total</td></tr><tr><td></td><td colspan="6">(in millions)</td></tr><tr><td>Southern Company</td><td>$98</td><td>$111</td><td>$146</td><td>$72</td><td>$58</td><td>$485</td></tr><tr><td>Alabama Power</td><td>49</td><td>35</td><td>50</td><td>33</td><td>28</td><td>195</td></tr><tr><td>Georgia Power</td><td>37</td><td>75</td><td>91</td><td>34</td><td>25</td><td>262</td></tr><tr><td>Mississippi Power</td><td>12</td><td>1</td><td>5</td><td>5</td><td>5</td><td>28</td></tr></table>

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 SO \( _{2} \)  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, SO \( _{2} \) , 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 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



## Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 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  \( CO_{2} \)  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  \( CO_{2} \)  equivalents from its natural gas distribution system since 1998.

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

<table><tr><td></td><td>2020</td><td>Preliminary 2021</td></tr><tr><td></td><td colspan="2">(in million metric tons of  \( CO_{2} \)  equivalent)</td></tr><tr><td>Southern Company \( ^{(r)} \)</td><td>75</td><td>82</td></tr><tr><td>Alabama Power \( ^{(r)} \)</td><td>28</td><td>34</td></tr><tr><td>Georgia Power</td><td>21</td><td>23</td></tr><tr><td>Mississippi Power</td><td>8</td><td>8</td></tr><tr><td>Southern Power</td><td>12</td><td>11</td></tr><tr><td>Southern Company Gas \( ^{(r)} \)</td><td>1</td><td>1</td></tr></table>

(*) 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.

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

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.

## 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.

## 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:

<table><tr><td>ITC Percentage</td><td>Date Project Commenced Construction</td></tr><tr><td>30%</td><td>Prior to December 31, 2019</td></tr><tr><td>26%</td><td>From 2020 through 2022</td></tr><tr><td>22%</td><td>During 2023</td></tr></table>

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:

<table><tr><td>PTC Percentage</td><td>Year Project Commenced Construction</td></tr><tr><td>100%</td><td>2016</td></tr><tr><td>80%</td><td>2017</td></tr><tr><td>60%</td><td>2018</td></tr><tr><td>40%</td><td>2019</td></tr><tr><td>60%</td><td>2020 or 2021</td></tr><tr><td>0%</td><td>2022 and after</td></tr></table>

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 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. The following critical accounting policies and estimates include only those that are applicable to Southern Company.

## 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 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.

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 in Note 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)

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.



## Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 as bonds. 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.

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.

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.



## Management’s Discussion and Analysis of Financial Condition and Results of Operations

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:

<table><tr><td rowspan="2">25 Basis Point Change in:</td><td colspan="3">Increase/(Decrease) in</td></tr><tr><td>Total Benefit Expense for 2022</td><td>Projected Obligation for Pension Plan at December 31, 2021</td><td>Projected Obligation for Other Postretirement Benefit Plans at December 31, 2021</td></tr><tr><td>Discount rate:</td><td></td><td></td><td></td></tr><tr><td>Southern Company</td><td>$44/$(43)</td><td>$610/$(575)</td><td>$53/$(51)</td></tr><tr><td>Alabama Power</td><td>$12/$(12)</td><td>$149/$(140)</td><td>$14/$(13)</td></tr><tr><td>Georgia Power</td><td>$12/$(12)</td><td>$180/$(170)</td><td>$18/$(17)</td></tr><tr><td>Mississippi Power</td><td>$2/$(2)</td><td>$27/$(26)</td><td>$2/$(2)</td></tr><tr><td>Southern Company Gas</td><td>$-\)/\(-</td><td>$40/$38)</td><td>$6/$6)</td></tr><tr><td>Salaries:</td><td></td><td></td><td></td></tr><tr><td>Southern Company</td><td>$26/$(24)</td><td>$131/$(127)</td><td>$-\)/\(-</td></tr><tr><td>Alabama Power</td><td>$8/$7)</td><td>$37/$(36)</td><td>$-\)/\(-</td></tr><tr><td>Georgia Power</td><td>$7/$7)</td><td>$37/$(36)</td><td>$-\)/\(-\)</td></tr><tr><td>Mississippi Power</td><td>$1/$(1)</td><td>$6/$(6)</td><td>$-\)/\(-\)</td></tr><tr><td>Southern Company Gas</td><td>$-\)/\(-</td><td>$2/$2)</td><td>$-\)/\(-</td></tr><tr><td>Long-term return on plan assets:</td><td></td><td></td><td></td></tr><tr><td>Southern Company</td><td>$41/$(41)</td><td>N/A</td><td>N/A</td></tr><tr><td>Alabama Power</td><td>$10/$(10)</td><td>N/A</td><td>N/A</td></tr><tr><td>Georgia Power</td><td>$13/$(13)</td><td>N/A</td><td>N/A</td></tr><tr><td>Mississippi Power</td><td>$2/$(2)</td><td>N/A</td><td>N/A</td></tr><tr><td>Southern Company Gas</td><td>$3/$(3)</td><td>N/A</td><td>N/A</td></tr></table>

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 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



## Management’s Discussion and Analysis of Financial Condition and Results of Operations

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.

## 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 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:

<table><tr><td></td><td>2022</td><td>2023</td><td>2024</td><td>2025</td><td>2026</td></tr><tr><td></td><td colspan="5">(in billions)</td></tr><tr><td>Southern Company \( ^{(a)(b)(c)} \)</td><td>8.7</td><td>8.6</td><td>7.5</td><td>7.2</td><td>7.1</td></tr><tr><td>Alabama Power \( ^{(a)} \)</td><td>1.9</td><td>1.8</td><td>1.7</td><td>1.7</td><td>1.7</td></tr><tr><td>Georgia Power \( ^{(b)} \)</td><td>4.4</td><td>4.5</td><td>3.5</td><td>3.5</td><td>3.4</td></tr><tr><td>Mississippi Power</td><td>0.3</td><td>0.3</td><td>0.2</td><td>0.2</td><td>0.2</td></tr><tr><td>Southern Power \( ^{(c)} \)</td><td>0.1</td><td>0.2</td><td>0.1</td><td>0.1</td><td>0.1</td></tr><tr><td>Southern Company Gas</td><td>1.7</td><td>1.7</td><td>1.8</td><td>1.7</td><td>1.7</td></tr></table>

(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  \( CO_{2} \)  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.

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.

<table><tr><td></td><td>2022</td><td>2023</td><td>2024</td><td>2025</td><td>2026</td></tr><tr><td></td><td colspan="5">(in millions)</td></tr><tr><td>Southern Company</td><td>$687</td><td>$688</td><td>$767</td><td>$907</td><td>$888</td></tr><tr><td>Alabama Power</td><td>320</td><td>330</td><td>346</td><td>364</td><td>299</td></tr><tr><td>Georgia Power</td><td>317</td><td>307</td><td>368</td><td>489</td><td>555</td></tr><tr><td>Mississippi Power</td><td>16</td><td>20</td><td>23</td><td>30</td><td>16</td></tr></table>

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. 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.

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.

<table><tr><td></td><td>2022</td><td>2023</td><td>2024</td><td>2025</td><td>2026</td><td>Thereafter</td></tr><tr><td></td><td colspan="6">(in millions)</td></tr><tr><td>Southern Company \( ^{*} \)</td><td>3,740</td><td>1,983</td><td>1,302</td><td>969</td><td>753</td><td>5,803</td></tr><tr><td>Alabama Power</td><td>1,170</td><td>581</td><td>446</td><td>358</td><td>203</td><td>1,182</td></tr><tr><td>Georgia Power \( ^{*} \)</td><td>1,405</td><td>795</td><td>440</td><td>348</td><td>329</td><td>4,118</td></tr><tr><td>Mississippi Power</td><td>539</td><td>235</td><td>168</td><td>109</td><td>98</td><td>491</td></tr><tr><td>Southern Power</td><td>626</td><td>372</td><td>248</td><td>154</td><td>123</td><td>12</td></tr></table>

(*) 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:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td></tr><tr><td></td><td colspan="5">(in millions)</td></tr><tr><td>LTSA commitments (after 2026)</td><td>1,918</td><td>203</td><td>347</td><td>137</td><td>1,231</td></tr></table>

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.

<table><tr><td></td><td>2022</td><td>2023</td><td>2024</td><td>2025</td><td>2026</td><td>Thereafter</td></tr><tr><td></td><td colspan="6">(in millions)</td></tr><tr><td>Southern Power’s operations and maintenance agreements</td><td>$77</td><td>$65</td><td>$62</td><td>$47</td><td>$36</td><td>$303</td></tr></table>

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.



## 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.



## Management’s Discussion and Analysis of Financial Condition and Results of Operations

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:

<table><tr><td>At December 31, 2021</td><td>Southern Company</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Current liabilities in excess of current assets</td><td>$1,956</td><td>$1,544</td><td>$57</td><td>$748</td><td>$471</td></tr></table>

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:

<table><tr><td>At December 31, 2021</td><td>Southern Company parent</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power \( ^{(a)} \)</td><td>Southern Company Gas \( ^{(b)} \)</td><td>SEGCO</td><td>Southern Company</td></tr><tr><td></td><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>Unused committed credit</td><td>1,998</td><td>1,250</td><td>1,726</td><td>275</td><td>568</td><td>1,747</td><td>30</td><td>7,594</td></tr></table>

(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.



## 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:

<table><tr><td rowspan="4"></td><td colspan="6">Short-term Debt at the End of the Period</td></tr><tr><td colspan="3">Amount Outstanding</td><td colspan="3">Weighted Average Interest Rate</td></tr><tr><td colspan="3">December 31,</td><td colspan="3">December 31,</td></tr><tr><td>2021</td><td>2020</td><td>2019</td><td>2021</td><td>2020</td><td>2019</td></tr><tr><td></td><td colspan="6">(in millions)</td></tr><tr><td>Southern Company</td><td>$1,440</td><td>$609</td><td>$2,055</td><td>0.4%</td><td>0.3%</td><td>2.1%</td></tr><tr><td>Georgia Power</td><td>—</td><td>60</td><td>365</td><td>—</td><td>0.3</td><td>2.2</td></tr><tr><td>Mississippi Power</td><td>—</td><td>25</td><td>—</td><td>—</td><td>0.4</td><td>—</td></tr><tr><td>Southern Power</td><td>211</td><td>175</td><td>549</td><td>0.3</td><td>0.3</td><td>2.2</td></tr><tr><td>Southern Company Gas:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Southern Company Gas Capital</td><td>$ 379</td><td>$220</td><td>$ 372</td><td>0.3%</td><td>0.3%</td><td>2.1%</td></tr><tr><td>Nicor Gas</td><td>830</td><td>104</td><td>278</td><td>0.4%</td><td>0.2</td><td>1.8</td></tr><tr><td>Southern Company Gas Total</td><td>$1,209</td><td>$324</td><td>$ 650</td><td>0.4%</td><td>0.2%</td><td>2.0%</td></tr></table>

Short-term Debt During the Period \( ^{*} \) 

<table><tr><td rowspan="3"></td><td colspan="3">Average Amount Outstanding</td><td colspan="3">Weighted Average Interest Rate</td><td colspan="3">Maximum Amount Outstanding</td></tr><tr><td>2021</td><td>2020</td><td>2019</td><td>2021</td><td>2020</td><td>2019</td><td>2021</td><td>2020</td><td></td></tr><tr><td colspan="3">(in millions)</td><td colspan="3">(in millions)</td><td></td><td></td><td></td></tr><tr><td>Southern Company</td><td>$1,141</td><td>$1,017</td><td>$1,240</td><td>0.3%</td><td>1.6%</td><td>2.6%</td><td>$1,809</td><td>$2,113</td><td>$2,914</td></tr><tr><td>Alabama Power</td><td>27</td><td>20</td><td>17</td><td>0.1</td><td>1.1</td><td>2.6</td><td>200</td><td>155</td><td>190</td></tr><tr><td>Georgia Power</td><td>95</td><td>264</td><td>371</td><td>0.2</td><td>1.7</td><td>2.7</td><td>407</td><td>478</td><td>935</td></tr><tr><td>Mississippi Power</td><td>15</td><td>9</td><td>—</td><td>0.2</td><td>1.6</td><td>—</td><td>81</td><td>40</td><td>—</td></tr><tr><td>Southern Power</td><td>133</td><td>64</td><td>76</td><td>0.2</td><td>1.5</td><td>2.7</td><td>520</td><td>550</td><td>578</td></tr><tr><td>Southern Company Gas:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Southern Company Gas Capital</td><td>$ 206</td><td>$ 316</td><td>$ 302</td><td>0.2%</td><td>1.4%</td><td>2.6%</td><td>$ 485</td><td>$ 641</td><td>$ 490</td></tr><tr><td>Nicor Gas</td><td>420</td><td>49</td><td>91</td><td>0.4</td><td>1.4</td><td>2.3</td><td>897</td><td>278</td><td>278</td></tr><tr><td>Southern Company Gas Total</td><td>$ 626</td><td>$ 365</td><td>$ 393</td><td>0.4%</td><td>1.4%</td><td>2.5%</td><td></td><td></td><td></td></tr></table>

(*) Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2021, 2020, and 2019.



## 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:

<table><tr><td>Net cash provided from (used for):</td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>2021</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating activities</td><td>$ 6,169</td><td>$ 2,053</td><td>$ 2,747</td><td>$ 246</td><td>$ 951</td><td>$ 663</td></tr><tr><td>Investing activities</td><td>(7,353)</td><td>(1,961)</td><td>(3,590)</td><td>(257)</td><td>(803)</td><td>(1,379)</td></tr><tr><td>Financing activities</td><td>1,945</td><td>438</td><td>867</td><td>33</td><td>(195)</td><td>745</td></tr><tr><td>2020</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating activities</td><td>$ 6,696</td><td>$ 1,742</td><td>$ 2,784</td><td>$ 298</td><td>$ 901</td><td>$ 1,207</td></tr><tr><td>Investing activities</td><td>(7,030)</td><td>(2,122)</td><td>(3,503)</td><td>(323)</td><td>374</td><td>(1,417)</td></tr><tr><td>Financing activities</td><td>(576)</td><td>16</td><td>676</td><td>(222)</td><td>(1,372)</td><td>180</td></tr></table>

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.

## 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;

• 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.



## Financing Activities

The following table outlines the Registrants' long-term debt financing activities for the year ended December 31, 2021:

<table><tr><td rowspan="2">Company</td><td colspan="3">Issuances/Reofferings</td><td colspan="3">Maturities, Redemptions, and Repurchases</td></tr><tr><td>Senior Notes</td><td>Revenue Bonds</td><td>Other Long-Term Debt</td><td>Senior Notes</td><td>Revenue Bonds</td><td>Other Long-Term Debt \( ^{(a)} \)</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Southern Company parent</td><td>1,600</td><td>$ —</td><td>$2,476</td><td>1,500</td><td>$ —</td><td>$ 800</td></tr><tr><td>Alabama Power</td><td>1,300</td><td>—</td><td>—</td><td>200</td><td>65</td><td>207</td></tr><tr><td>Georgia Power</td><td>750</td><td>122</td><td>440</td><td>325</td><td>69</td><td>105</td></tr><tr><td>Mississippi Power</td><td>525</td><td>—</td><td>—</td><td>—</td><td>320</td><td>100</td></tr><tr><td>Southern Power</td><td>400</td><td>—</td><td>—</td><td>300</td><td>—</td><td>—</td></tr><tr><td>Southern Company Gas</td><td>450</td><td>—</td><td>200</td><td>300</td><td>—</td><td>30</td></tr><tr><td>Other</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>14</td></tr><tr><td>Elimination \( ^{(b)} \)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(7)</td></tr><tr><td>Southern Company</td><td>5,025</td><td>1,122</td><td>3,116</td><td>2,625</td><td>4,454</td><td>1,249</td></tr></table>

(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.



## 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.

## 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.



## Management’s Discussion and Analysis of Financial Condition and Results of Operations

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, Nicro 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, Nicro 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, Nicro Gas issued in a private placement $100 million aggregate principal amount of 1.77% Series First Mortgage Bonds due October 28, 2028. Nicro 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.

The maximum potential collateral requirements under these contracts at December 31, 2021 were as follows:

<table><tr><td>Credit Ratings</td><td>Southern Company \( ^{(1)} \)</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power \( ^{(1)} \)</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td colspan="5">(in millions)</td></tr><tr><td>At BBB and/or Baa2</td><td>$ 41</td><td>$ 1</td><td>$ —</td><td>$ —</td><td>$ 40</td><td>$ —</td></tr><tr><td>At BBB- and/or Baa3</td><td>419</td><td>2</td><td>61</td><td>1</td><td>357</td><td>—</td></tr><tr><td>At BB+ and/or Ba1 or below</td><td>1,934</td><td>407</td><td>939</td><td>307</td><td>1,186</td><td>9</td></tr></table>

(*) 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.



## Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 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.



## Management’s Discussion and Analysis of Financial Condition and Results of Operations

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:

<table><tr><td>At December 31, 2021</td><td>Southern Company \( ^{(a)} \)</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Company Gas</td></tr><tr><td></td><td colspan="5">(in millions, except percentages)</td></tr><tr><td>Long-term variable interest rate exposure</td><td>4,464</td><td>8 834</td><td>7 797</td><td>2 234</td><td>5 500</td></tr><tr><td>Weighted average interest rate on long-term variable interest rate exposure</td><td>0.84%</td><td>0.21%</td><td>0.21%</td><td>0.32%</td><td>0.49%</td></tr><tr><td>Impact on annualized interest expense of 100 basis point change in interest rates</td><td>5</td><td>8</td><td>8</td><td>2</td><td>5</td></tr></table>

(*) 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.

<table><tr><td></td><td>Southern Company \( ^{(a)} \)</td><td>Southern Company Gas \( ^{(a)} \)</td></tr><tr><td></td><td colspan="2">(in millions)</td></tr><tr><td>Contracts outstanding at December 31, 2019, assets (liabilities), net</td><td>$ (21)</td><td>$ 72</td></tr><tr><td>Contracts realized or settled</td><td>(14)</td><td>(98)</td></tr><tr><td>Current period changes \( ^{(b)} \)</td><td>142</td><td>127</td></tr><tr><td>Contracts outstanding at December 31, 2020, assets (liabilities), net</td><td>$ 107</td><td>$101</td></tr><tr><td>Contracts realized or settled</td><td>(252)</td><td>(85)</td></tr><tr><td>Current period changes \( ^{(b)} \)</td><td>243</td><td>(84)</td></tr><tr><td>Sale of Sequent</td><td>76</td><td>76</td></tr><tr><td>Contracts outstanding at December 31, 2021, assets (liabilities), net</td><td>$ 174</td><td>$ 8</td></tr></table>

(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.

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:

<table><tr><td></td><td>Southern Company</td><td>Southern Company Gas</td></tr><tr><td></td><td colspan="2">mmBtu Volume (in millions)</td></tr><tr><td>At December 31, 2021:</td><td></td><td></td></tr><tr><td>Commodity - Natural gas swaps</td><td>57</td><td>—</td></tr><tr><td>Commodity - Natural gas options</td><td>253</td><td>68</td></tr><tr><td>Total hedge volume</td><td>310</td><td>68</td></tr><tr><td>At December 31, 2020:</td><td></td><td></td></tr><tr><td>Commodity - Natural gas swaps</td><td>262</td><td>—</td></tr><tr><td>Commodity - Natural gas options</td><td>574</td><td>523</td></tr><tr><td>Total hedge volume</td><td>836</td><td>523</td></tr></table>



## Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

<table><tr><td rowspan="2"></td><td rowspan="2">Total Fair Value</td><td colspan="4">Maturity</td></tr><tr><td>2022</td><td>2023 - 2024</td><td>2025 - 2026</td><td></td></tr><tr><td>Southern Company</td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Level 1 \( ^{(a)} \)</td><td></td><td>$ 15</td><td>$ 14</td><td>$ 1</td><td>$ —</td></tr><tr><td>Level 2 \( ^{(b)} \)</td><td></td><td>159</td><td>93</td><td>65</td><td>1</td></tr><tr><td>Southern Company total \( ^{(c)} \)</td><td></td><td>$ 174</td><td>$ 107</td><td>$ 66</td><td>$ 1</td></tr><tr><td>Southern Company Gas</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Level 1 \( ^{(a)} \)</td><td></td><td>$ 15</td><td>$ 14</td><td>$ 1</td><td>$ —</td></tr><tr><td>Level 2 \( ^{(b)} \)</td><td></td><td>(7)</td><td>(7)</td><td>—</td><td>—</td></tr><tr><td>Southern Company Gas total \( ^{(c)} \)</td><td></td><td>$ 8</td><td>$ 7</td><td>$ 1</td><td>$ —</td></tr></table>

(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.

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

Except as discussed herein, the Southern Company system is not exposed to any concentrations 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 the 16 Marketers in Georgia. For 2021, the four largest Marketers based on customer count, which includes SouthStar, accounted for 15% of Southern Company Gas' operating revenues.



<table><tr><td></td><td>2021</td><td>2020</td><td>2019</td></tr><tr><td></td><td colspan="3">(in millions)</td></tr><tr><td>Operating Revenues:</td><td></td><td></td><td></td></tr><tr><td>Retail electric revenues</td><td>$14,852</td><td>$13,643</td><td>$14,084</td></tr><tr><td>Wholesale electric revenues</td><td>2,455</td><td>1,945</td><td>2,152</td></tr><tr><td>Other electric revenues</td><td>718</td><td>672</td><td>636</td></tr><tr><td>Natural gas revenues</td><td>4,380</td><td>3,434</td><td>3,792</td></tr><tr><td>Other revenues</td><td>708</td><td>681</td><td>755</td></tr><tr><td>Total operating revenues</td><td>23,113</td><td>20,375</td><td>21,419</td></tr><tr><td>Operating Expenses:</td><td></td><td></td><td></td></tr><tr><td>Fuel</td><td>4,010</td><td>2,967</td><td>3,622</td></tr><tr><td>Purchased power</td><td>978</td><td>799</td><td>816</td></tr><tr><td>Cost of natural gas</td><td>1,619</td><td>972</td><td>1,319</td></tr><tr><td>Cost of other sales</td><td>357</td><td>327</td><td>435</td></tr><tr><td>Other operations and maintenance</td><td>6,088</td><td>5,413</td><td>5,624</td></tr><tr><td>Depreciation and amortization</td><td>3,565</td><td>3,518</td><td>3,038</td></tr><tr><td>Taxes other than income taxes</td><td>1,290</td><td>1,234</td><td>1,230</td></tr><tr><td>Estimated loss on Plant Vogtle Units 3 and 4</td><td>1,692</td><td>325</td><td>—</td></tr><tr><td>Impairment charges</td><td>2</td><td>—</td><td>168</td></tr><tr><td>Gain on dispositions, net</td><td>(186)</td><td>(65)</td><td>(2,569)</td></tr><tr><td>Total operating expenses</td><td>19,415</td><td>15,490</td><td>13,683</td></tr><tr><td>Operating Income</td><td>3,698</td><td>4,885</td><td>7,736</td></tr><tr><td>Other Income and (Expense):</td><td></td><td></td><td></td></tr><tr><td>Allowance for equity funds used during construction</td><td>190</td><td>149</td><td>128</td></tr><tr><td>Earnings from equity method investments</td><td>76</td><td>153</td><td>162</td></tr><tr><td>Interest expense, net of amounts capitalized</td><td>(1,837)</td><td>(1,821)</td><td>(1,736)</td></tr><tr><td>Impairment of leveraged leases</td><td>(7)</td><td>(206)</td><td>—</td></tr><tr><td>Other income (expense), net</td><td>456</td><td>336</td><td>252</td></tr><tr><td>Total other income and (expense)</td><td>(1,122)</td><td>(1,389)</td><td>(1,194)</td></tr><tr><td>Earnings Before Income Taxes</td><td>2,576</td><td>3,496</td><td>6,542</td></tr><tr><td>Income taxes</td><td>267</td><td>393</td><td>1,798</td></tr><tr><td>Consolidated Net Income</td><td>2,309</td><td>3,103</td><td>4,744</td></tr><tr><td>Dividends on preferred stock of subsidiaries</td><td>15</td><td>15</td><td>15</td></tr><tr><td>Net loss attributable to noncontrolling interests</td><td>(99)</td><td>(31)</td><td>(10)</td></tr><tr><td>Consolidated Net Income Attributable to Southern Company</td><td>$ 2,393</td><td>$ 3,119</td><td>$ 4,739</td></tr><tr><td>Common Stock Data:</td><td></td><td></td><td></td></tr><tr><td>Earnings per share —</td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>$ 2.26</td><td>$ 2.95</td><td>$ 4.53</td></tr><tr><td>Diluted</td><td>2.24</td><td>2.93</td><td>4.50</td></tr><tr><td>Average number of shares of common stock outstanding — (in millions)</td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>1,061</td><td>1,058</td><td>1,046</td></tr><tr><td>Diluted</td><td>1,068</td><td>1,065</td><td>1,054</td></tr></table>

The accompanying notes are an integral part of these consolidated financial statements.



## Consolidated Statements of Comprehensive Income
For the Years Ended December 31, 2021, 2020, and 2019

<table><tr><td></td><td>2021</td><td>2020</td><td>2019</td></tr><tr><td></td><td colspan="3">(in millions)</td></tr><tr><td>Consolidated Net Income</td><td>$2,309</td><td>$3,103</td><td>$4,744</td></tr><tr><td>Other comprehensive income (loss):</td><td></td><td></td><td></td></tr><tr><td>Qualifying hedges:</td><td></td><td></td><td></td></tr><tr><td>Changes in fair value, net of tax of (16), 3, and (39), respectively</td><td>(49)</td><td>10</td><td>(115)</td></tr><tr><td>Reclassification adjustment for amounts included in net income, net of tax of 31, (13), and 19, respectively</td><td>96</td><td>(40)</td><td>57</td></tr><tr><td>Pension and other postretirement benefit plans:</td><td></td><td></td><td></td></tr><tr><td>Benefit plan net gain (loss), net of tax of 37, (17), and (31), respectively</td><td>98</td><td>(55)</td><td>(64)</td></tr><tr><td>Reclassification adjustment for amounts included in net income, net of tax of 5, 3, and 1, respectively</td><td>13</td><td>10</td><td>4</td></tr><tr><td>Total other comprehensive income (loss)</td><td>158</td><td>(75)</td><td>(118)</td></tr><tr><td>Dividends on preferred stock of subsidiaries</td><td>15</td><td>15</td><td>15</td></tr><tr><td>Comprehensive loss attributable to noncontrolling interests</td><td>(99)</td><td>(31)</td><td>(10)</td></tr><tr><td>Consolidated Comprehensive Income Attributable to Southern Company</td><td>$2,551</td><td>$3,044</td><td>$4,621</td></tr></table>

The accompanying notes are an integral part of these consolidated financial statements.



<table><tr><td></td><td>2021</td><td>2020</td><td>2019</td></tr><tr><td></td><td colspan="3">(in millions)</td></tr><tr><td>Operating Activities:</td><td></td><td></td><td></td></tr><tr><td>Consolidated net income</td><td>$ 2,309</td><td>$ 3,103</td><td>$ 4,744</td></tr><tr><td>Adjustments to reconcile consolidated net income to net cash provided from operating activities — Depreciation and amortization, total</td><td>3,973</td><td>3,905</td><td>3,331</td></tr><tr><td>Deferred income taxes</td><td>(49)</td><td>(241)</td><td>611</td></tr><tr><td>Utilization of federal investment tax credits</td><td>288</td><td>341</td><td>757</td></tr><tr><td>Allowance for equity funds used during construction</td><td>(190)</td><td>(149)</td><td>(128)</td></tr><tr><td>Pension, postretirement, and other employee benefits</td><td>(305)</td><td>(259)</td><td>(204)</td></tr><tr><td>Pension and postretirement funding</td><td>—</td><td>(2)</td><td>(1,136)</td></tr><tr><td>Settlement of asset retirement obligations</td><td>(456)</td><td>(442)</td><td>(328)</td></tr><tr><td>Storm damage accruals</td><td>288</td><td>325</td><td>168</td></tr><tr><td>Stock based compensation expense</td><td>144</td><td>113</td><td>107</td></tr><tr><td>Estimated loss on Plant Vogtle Units 3 and 4</td><td>1,692</td><td>325</td><td>—</td></tr><tr><td>Impairment charges</td><td>91</td><td>206</td><td>168</td></tr><tr><td>Gain on dispositions, net</td><td>(176)</td><td>(66)</td><td>(2,588)</td></tr><tr><td>Retail fuel cost under recovery - long-term</td><td>(536)</td><td>—</td><td>—</td></tr><tr><td>Natural gas cost under recovery - long-term</td><td>(207)</td><td>—</td><td>—</td></tr><tr><td>Other, net</td><td>86</td><td>(74)</td><td>115</td></tr><tr><td>Changes in certain current assets and liabilities —</td><td></td><td></td><td></td></tr><tr><td>—Receivables</td><td>(81)</td><td>(222)</td><td>630</td></tr><tr><td>—Materials and supplies</td><td>(130)</td><td>(157)</td><td>(17)</td></tr><tr><td>—Natural gas cost under recovery</td><td>(266)</td><td>—</td><td>—</td></tr><tr><td>—Other current assets</td><td>(170)</td><td>(161)</td><td>12</td></tr><tr><td>—Accounts payable</td><td>(8)</td><td>(27)</td><td>(693)</td></tr><tr><td>—Accrued taxes</td><td>(54)</td><td>242</td><td>117</td></tr><tr><td>—Retail fuel cost over recovery</td><td>(155)</td><td>96</td><td>62</td></tr><tr><td>—Customer refunds</td><td>130</td><td>(236)</td><td>126</td></tr><tr><td>—Other current liabilities</td><td>(49)</td><td>76</td><td>(73)</td></tr><tr><td>Net cash provided from operating activities</td><td>6,169</td><td>6,696</td><td>5,781</td></tr><tr><td>Investing Activities:</td><td></td><td></td><td></td></tr><tr><td>Business acquisitions, net of cash acquired</td><td>(345)</td><td>(81)</td><td>(50)</td></tr><tr><td>Property additions</td><td>(7,240)</td><td>(7,441)</td><td>(7,555)</td></tr><tr><td>Nuclear decommissioning trust fund purchases</td><td>(1,598)</td><td>(877)</td><td>(888)</td></tr><tr><td>Nuclear decommissioning trust fund sales</td><td>1,593</td><td>871</td><td>882</td></tr><tr><td>Proceeds from dispositions</td><td>917</td><td>1,049</td><td>5,122</td></tr><tr><td>Cost of removal, net of salvage</td><td>(442)</td><td>(361)</td><td>(393)</td></tr><tr><td>Change in construction payables, net</td><td>(124)</td><td>37</td><td>(169)</td></tr><tr><td>Payments pursuant to LTSAs</td><td>(188)</td><td>(211)</td><td>(234)</td></tr><tr><td>Other investing activities</td><td>74</td><td>(16)</td><td>(107)</td></tr><tr><td>Net cash used for investing activities</td><td>(7,353)</td><td>(7,030)</td><td>(3,392)</td></tr></table>



## Consolidated Statements of Cash Flows (continued)
For the Years Ended December 31, 2021, 2020, and 2019

<table><tr><td></td><td>2021</td><td>2020</td><td>2019</td></tr><tr><td></td><td colspan="3">(in millions)</td></tr><tr><td>Financing Activities:</td><td></td><td></td><td></td></tr><tr><td>Increase (decrease) in notes payable, net</td><td>530</td><td>(1,096)</td><td>640</td></tr><tr><td>Proceeds —</td><td></td><td></td><td></td></tr><tr><td>Long-term debt</td><td>8,262</td><td>8,047</td><td>5,220</td></tr><tr><td>Short-term borrowings</td><td>325</td><td>615</td><td>350</td></tr><tr><td>Common stock</td><td>73</td><td>74</td><td>844</td></tr><tr><td>Redemptions and repurchases —</td><td></td><td></td><td></td></tr><tr><td>Long-term debt</td><td>(4,327)</td><td>(4,458)</td><td>(4,347)</td></tr><tr><td>Short-term borrowings</td><td>(25)</td><td>(840)</td><td>(1,850)</td></tr><tr><td>Capital contributions from noncontrolling interests</td><td>501</td><td>363</td><td>196</td></tr><tr><td>Distributions to noncontrolling interests</td><td>(351)</td><td>(271)</td><td>(256)</td></tr><tr><td>Payment of common stock dividends</td><td>(2,777)</td><td>(2,685)</td><td>(2,570)</td></tr><tr><td>Other financing activities</td><td>(266)</td><td>(325)</td><td>(157)</td></tr><tr><td>Net cash provided from (used for) financing activities</td><td>1,945</td><td>(576)</td><td>(1,930)</td></tr><tr><td>Net Change in Cash, Cash Equivalents, and Restricted Cash</td><td>761</td><td>(910)</td><td>459</td></tr><tr><td>Cash, Cash Equivalents, and Restricted Cash at Beginning of Year</td><td>1,068</td><td>1,978</td><td>1,519</td></tr><tr><td>Cash, Cash Equivalents, and Restricted Cash at End of Year</td><td>$ 1,829</td><td>$ 1,068</td><td>$ 1,978</td></tr><tr><td>Supplemental Cash Flow Information:</td><td></td><td></td><td></td></tr><tr><td>Cash paid during the period for —</td><td></td><td></td><td></td></tr><tr><td>Interest (net of $92, $81, and $74 capitalized, respectively)</td><td>$ 1,718</td><td>$ 1,683</td><td>$ 1,651</td></tr><tr><td>Income taxes, net</td><td>93</td><td>64</td><td>276</td></tr><tr><td>Noncash transactions —</td><td></td><td></td><td></td></tr><tr><td>Accrued property additions at year-end</td><td>866</td><td>989</td><td>932</td></tr><tr><td>Contributions from noncontrolling interests</td><td>89</td><td>12</td><td>80</td></tr><tr><td>Contributions of wind turbine equipment</td><td>82</td><td>17</td><td>26</td></tr></table>

The accompanying notes are an integral part of these consolidated financial statements.



<table><tr><td>Assets</td><td>2021</td><td>2020</td></tr><tr><td></td><td>(in millions)</td><td></td></tr><tr><td>Current Assets:</td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$ 1,798</td><td>$ 1,065</td></tr><tr><td>Receivables —</td><td></td><td></td></tr><tr><td>Customer accounts</td><td>1,806</td><td>1,753</td></tr><tr><td>Energy marketing</td><td>—</td><td>516</td></tr><tr><td>Unbilled revenues</td><td>711</td><td>672</td></tr><tr><td>Other accounts and notes</td><td>523</td><td>512</td></tr><tr><td>Accumulated provision for uncollectible accounts</td><td>(78)</td><td>(118)</td></tr><tr><td>Materials and supplies</td><td>1,543</td><td>1,478</td></tr><tr><td>Fossil fuel for generation</td><td>450</td><td>550</td></tr><tr><td>Natural gas for sale</td><td>362</td><td>460</td></tr><tr><td>Prepaid expenses</td><td>330</td><td>276</td></tr><tr><td>Assets from risk management activities, net of collateral</td><td>151</td><td>147</td></tr><tr><td>Regulatory assets - asset retirement obligations</td><td>219</td><td>214</td></tr><tr><td>Natural gas cost under recovery</td><td>266</td><td>—</td></tr><tr><td>Other regulatory assets</td><td>653</td><td>810</td></tr><tr><td>Other current assets</td><td>231</td><td>282</td></tr><tr><td>Total current assets</td><td>8,965</td><td>8,617</td></tr><tr><td>Property, Plant, and Equipment:</td><td></td><td></td></tr><tr><td>In service</td><td>115,592</td><td>110,516</td></tr><tr><td>Less: Accumulated depreciation</td><td>34,079</td><td>32,397</td></tr><tr><td>Plant in service, net of depreciation</td><td>81,513</td><td>78,119</td></tr><tr><td>Nuclear fuel, at amortized cost</td><td>824</td><td>818</td></tr><tr><td>Construction work in progress</td><td>8,771</td><td>8,697</td></tr><tr><td>Total property, plant, and equipment</td><td>91,108</td><td>87,634</td></tr><tr><td>Other Property and Investments:</td><td></td><td></td></tr><tr><td>Goodwill</td><td>5,280</td><td>5,280</td></tr><tr><td>Nuclear decommissioning trusts, at fair value</td><td>2,542</td><td>2,303</td></tr><tr><td>Equity investments in unconsolidated subsidiaries</td><td>1,282</td><td>1,362</td></tr><tr><td>Other intangible assets, net of amortization of $307 and $328, respectively</td><td>445</td><td>487</td></tr><tr><td>Leveraged leases</td><td>—</td><td>556</td></tr><tr><td>Miscellaneous property and investments</td><td>653</td><td>398</td></tr><tr><td>Total other property and investments</td><td>10,202</td><td>10,386</td></tr><tr><td>Deferred Charges and Other Assets:</td><td></td><td></td></tr><tr><td>Operating lease right-of-use assets, net of amortization</td><td>1,701</td><td>1,802</td></tr><tr><td>Deferred charges related to income taxes</td><td>824</td><td>796</td></tr><tr><td>Prepaid pension costs</td><td>1,657</td><td>—</td></tr><tr><td>Unamortized loss on reacquired debt</td><td>258</td><td>280</td></tr><tr><td>Regulatory assets - asset retirement obligations, deferred</td><td>5,466</td><td>4,934</td></tr><tr><td>Other regulatory assets, deferred</td><td>5,577</td><td>7,198</td></tr><tr><td>Other deferred charges and assets</td><td>1,776</td><td>1,288</td></tr><tr><td>Total deferred charges and other assets</td><td>17,259</td><td>16,298</td></tr><tr><td>Total Assets</td><td>$127,534</td><td>$122,935</td></tr></table>

The accompanying notes are an integral part of these consolidated financial statements.



<table><tr><td>Liabilities and Stockholders&#x27; Equity</td><td>2021</td><td>2020</td></tr><tr><td></td><td colspan="2">(in millions)</td></tr><tr><td>Current Liabilities:</td><td></td><td></td></tr><tr><td>Securities due within one year</td><td>$ 2,157</td><td>$ 3,507</td></tr><tr><td>Notes payable</td><td>1,440</td><td>609</td></tr><tr><td>Energy marketing trade payables</td><td>—</td><td>494</td></tr><tr><td>Accounts payable</td><td>2,169</td><td>2,312</td></tr><tr><td>Customer deposits</td><td>479</td><td>487</td></tr><tr><td>Accrued taxes —</td><td></td><td></td></tr><tr><td>Accrued income taxes</td><td>50</td><td>130</td></tr><tr><td>Other accrued taxes</td><td>641</td><td>699</td></tr><tr><td>Accrued interest</td><td>533</td><td>513</td></tr><tr><td>Accrued compensation</td><td>1,070</td><td>1,025</td></tr><tr><td>Asset retirement obligations</td><td>697</td><td>585</td></tr><tr><td>Operating lease obligations</td><td>250</td><td>241</td></tr><tr><td>Other regulatory liabilities</td><td>563</td><td>509</td></tr><tr><td>Other current liabilities</td><td>872</td><td>968</td></tr><tr><td>Total current liabilities</td><td>10,921</td><td>12,079</td></tr><tr><td>Long-Term Debt</td><td>50,120</td><td>45,073</td></tr><tr><td>Deferred Credits and Other Liabilities:</td><td></td><td></td></tr><tr><td>Accumulated deferred income taxes</td><td>8,862</td><td>8,175</td></tr><tr><td>Deferred credits related to income taxes</td><td>5,401</td><td>5,767</td></tr><tr><td>Accumulated deferred ITCs</td><td>2,216</td><td>2,235</td></tr><tr><td>Employee benefit obligations</td><td>1,550</td><td>2,213</td></tr><tr><td>Operating lease obligations, deferred</td><td>1,503</td><td>1,611</td></tr><tr><td>Asset retirement obligations, deferred</td><td>10,990</td><td>10,099</td></tr><tr><td>Other cost of removal obligations</td><td>2,103</td><td>2,211</td></tr><tr><td>Other regulatory liabilities, deferred</td><td>485</td><td>251</td></tr><tr><td>Other deferred credits and liabilities</td><td>816</td><td>696</td></tr><tr><td>Total deferred credits and other liabilities</td><td>33,926</td><td>33,258</td></tr><tr><td>Total Liabilities</td><td>94,967</td><td>90,410</td></tr><tr><td>Redeemable Preferred Stock of Subsidiaries:</td><td></td><td></td></tr><tr><td>Cumulative preferred stock</td><td></td><td></td></tr><tr><td>$100 par or stated value - 4.20% to 4.92%</td><td></td><td></td></tr><tr><td>(Authorized - 10 million shares; Outstanding - 0.5 million shares)</td><td>48</td><td>48</td></tr><tr><td>$1 par value - 5.00% (Authorized - 28 million shares; Outstanding - 10 million shares)</td><td>243</td><td>243</td></tr><tr><td>Total redeemable preferred stock of subsidiaries (annual dividend requirement - $15 million)</td><td>291</td><td>291</td></tr><tr><td>Common Stockholders&#x27; Equity:</td><td></td><td></td></tr><tr><td>Common stock, par value $5 per share (Authorized - 1.5 billion shares)</td><td>5,279</td><td>5,268</td></tr><tr><td>(Issued - 1.1 billion shares; Treasury - 1.0 million shares)</td><td></td><td></td></tr><tr><td>Paid-in capital</td><td>11,950</td><td>11,834</td></tr><tr><td>Treasury, at cost</td><td>(47)</td><td>(46)</td></tr><tr><td>Retained earnings</td><td>10,929</td><td>11,311</td></tr><tr><td>Accumulated other comprehensive loss</td><td>(237)</td><td>(395)</td></tr><tr><td>Total common stockholders&#x27; equity</td><td>27,874</td><td>27,972</td></tr><tr><td>Noncontrolling interests</td><td>4,402</td><td>4,262</td></tr><tr><td>Total Stockholders&#x27; Equity (See accompanying statements)</td><td>32,276</td><td>32,234</td></tr><tr><td>Total Liabilities and Stockholders&#x27; Equity</td><td>$127,534</td><td>$122,935</td></tr><tr><td>Commitments and Contingent Matters (See notes)</td><td></td><td></td></tr></table>

The accompanying notes are an integral part of these consolidated financial statements.



Southern Company Common Stockholders' Equity

<table><tr><td rowspan="2"></td><td colspan="2">Number of Common Shares</td><td colspan="3">Common Stock</td><td rowspan="2">Retained Earnings</td><td rowspan="2">Accumulated Other Comprehensive Income (Loss)</td><td rowspan="2">Noncontrolling Interests</td><td rowspan="2">Total</td></tr><tr><td>Issued</td><td>Treasury</td><td>Par Value</td><td>Paid-in Capital</td><td>Treasury</td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>Balance at December 31, 2018</td><td>1,035</td><td>(1)</td><td>$5,164</td><td>$11,094</td><td>$ (38)</td><td>$ 8,706</td><td>$ (203)</td><td>$4,316</td><td>$29,039</td></tr><tr><td>Consolidated net income (loss)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>4,739</td><td>—</td><td>(10)</td><td>4,729</td></tr><tr><td>Other comprehensive income (loss)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(118)</td><td>—</td><td>(118)</td></tr><tr><td>Issuance of equity units \( ^{(r)} \)</td><td>—</td><td>—</td><td>—</td><td>(198)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(198)</td></tr><tr><td>Stock issued</td><td>19</td><td>—</td><td>93</td><td>751</td><td>—</td><td>—</td><td>—</td><td>—</td><td>844</td></tr><tr><td>Stock-based compensation</td><td>—</td><td>—</td><td>—</td><td>66</td><td>—</td><td>—</td><td>—</td><td>—</td><td>66</td></tr><tr><td>Cash dividends of $2.4600 per share</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(2,570)</td><td>—</td><td>—</td><td>(2,570)</td></tr><tr><td>Contributions from noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>276</td><td>276</td></tr><tr><td>Distributions to noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(327)</td><td>(327)</td></tr><tr><td>Other</td><td>—</td><td>—</td><td>—</td><td>21</td><td>(4)</td><td>2</td><td>—</td><td>(1)</td><td>18</td></tr><tr><td>Balance at December 31, 2019</td><td>1,054</td><td>(1)</td><td>5,257</td><td>11,734</td><td>(42)</td><td>10,877</td><td>(321)</td><td>4,254</td><td>31,759</td></tr><tr><td>Consolidated net income (loss)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>3,119</td><td>—</td><td>(31)</td><td>3,088</td></tr><tr><td>Other comprehensive income (loss)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(75)</td><td>—</td><td>(75)</td></tr><tr><td>Stock issued</td><td>4</td><td>—</td><td>11</td><td>63</td><td>—</td><td>—</td><td>—</td><td>—</td><td>74</td></tr><tr><td>Stock-based compensation</td><td>—</td><td>—</td><td>—</td><td>44</td><td>—</td><td>—</td><td>—</td><td>—</td><td>44</td></tr><tr><td>Cash dividends of $2.5400 per share</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(2,685)</td><td>—</td><td>—</td><td>(2,685)</td></tr><tr><td>Contributions from noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>307</td><td>307</td></tr><tr><td>Distributions to noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(271)</td><td>(271)</td></tr><tr><td>Purchase of membership interests from noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>5</td><td>—</td><td>—</td><td>—</td><td>(65)</td><td>(60)</td></tr><tr><td>Sale of noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>(2)</td><td>—</td><td>—</td><td>—</td><td>67</td><td>65</td></tr><tr><td>Other</td><td>—</td><td>—</td><td>—</td><td>(10)</td><td>(4)</td><td>—</td><td>1</td><td>1</td><td>(12)</td></tr><tr><td>Balance at December 31, 2020</td><td>1,058</td><td>(1)</td><td>5,268</td><td>11,834</td><td>(46)</td><td>11,311</td><td>(395)</td><td>4,262</td><td>32,234</td></tr><tr><td>Consolidated net income (loss)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>2,393</td><td>—</td><td>(99)</td><td>2,294</td></tr><tr><td>Other comprehensive income</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>158</td><td>—</td><td>158</td></tr><tr><td>Stock issued</td><td>3</td><td>—</td><td>11</td><td>62</td><td>—</td><td>—</td><td>—</td><td>—</td><td>73</td></tr><tr><td>Stock-based compensation</td><td>—</td><td>—</td><td>—</td><td>62</td><td>—</td><td>—</td><td>—</td><td>—</td><td>62</td></tr><tr><td>Cash dividends of $2.6200 per share</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(2,777)</td><td>—</td><td>—</td><td>(2,777)</td></tr><tr><td>Contributions from noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>590</td><td>590</td></tr><tr><td>Distributions to noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(351)</td><td>(351)</td></tr><tr><td>Other</td><td>—</td><td>—</td><td>—</td><td>(8)</td><td>(1)</td><td>2</td><td>—</td><td>—</td><td>(7)</td></tr><tr><td>Balance at December 31, 2021</td><td>1,061</td><td>(1)</td><td>$5,279</td><td>$11,950</td><td>$ (47)</td><td>$10,929</td><td>$ (237)</td><td>$4,402</td><td>$32,276</td></tr></table>

(*) See Note 8 under "Equity Units" for additional information.

The accompanying notes are an integral part of these consolidated financial statements.



## Index to the Notes to Financial Statements

78 Note 1 Summary of Significant Accounting Policies
91 Note 2 Regulatory Matters
112 Note 3 Contingencies, Commitments, and Guarantees
118 Note 4 Revenue from Contracts with Customers
122 Note 5 Property, Plant, and Equipment
125 Note 6 Asset Retirement Obligations
129 Note 7 Consolidated Entities and Equity Method Investments
132 Note 8 Financing
139 Note 9 Leases
148 Note 10 Income Taxes
154 Note 11 Retirement Benefits
175 Note 12 Stock Compensation
177 Note 13 Fair Value Measurements
184 Note 14 Derivatives
192 Note 15 Acquisitions and Dispositions
195 Note 16 Segment and Related Information



## 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

## General

Southern Company is the parent company of three traditional electric operating companies, as well as Southern Power, Southern Company Gas, SCS, Southern Linc, Southern Holdings, Southern Nuclear, PowerSecure, and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in three Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through natural gas distribution utilities, including Nicor Gas (Illinois), Atlanta Gas Light (Georgia), Virginia Natural Gas, and Chattanooga Gas (Tennessee). Southern Company Gas is also involved in several other complementary businesses including gas pipeline investments and gas marketing services. Prior to the sale of Sequent on July 1, 2021, these businesses also included wholesale gas services. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including Alabama Power's Plant Farley and Georgia Power's Plant Hatch and Plant Vogtle Units 1 and 2, and is currently managing construction and start-up of Plant Vogtle Units 3 and 4, which are co-owned by Georgia Power. PowerSecure develops distributed energy and resilience solutions and deploys microgrids for commercial, industrial, governmental, and utility customers. See Note 15 for information regarding the sale of Sequent.

The Registrants’ financial statements reflect investments in subsidiaries on a consolidated basis. Intercompany transactions have been eliminated in consolidation. The equity method is used for investments in entities in which a Registrant has significant influence but does not have control and for VIEs where a Registrant has an equity investment but is not the primary beneficiary. Southern Power has controlling ownership in certain legal entities for which the contractual provisions represent profit-sharing arrangements because the allocations of cash distributions and tax benefits are not based on fixed ownership percentages. For these arrangements, the noncontrolling interest is accounted for under a balance sheet approach utilizing the HLBV method. The HLBV method calculates each partner’s share of income based on the change in net equity the partner can legally claim in a HLBV at the end of the period compared to the beginning of the period. See “Variable Interest Entities” herein and Note 7 for additional information.

The traditional electric operating companies, Southern Power, certain subsidiaries of Southern Company Gas, and certain other subsidiaries are subject to regulation by the FERC, and the traditional electric operating companies and the natural gas distribution utilities are also subject to regulation by their respective state PSCs or other applicable state regulatory agencies. As such, the respective financial statements of the applicable Registrants reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by relevant state PSCs or other applicable state regulatory agencies.

The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the Registrants' results of operations, financial position, or cash flows.



## Recently Adopted Accounting Standards

In March 2020, the FASB issued ASU 2020–04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (ASU 2020–04) providing temporary guidance to ease the potential burden in accounting for reference rate reform primarily resulting from the discontinuation of LIBOR, which began phasing out on December 31, 2021. The amendments in ASU 2020–04 are elective and apply to all entities that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued. The new guidance (i) simplifies accounting analyses under current GAAP for contract modifications; (ii) simplifies the assessment of hedge effectiveness and allows hedging relationships affected by reference rate reform to continue; and (iii) allows a one-time election to sell or transfer debt securities classified as held to maturity that reference a rate affected by reference rate reform. An entity may elect to apply the amendments prospectively from March 12, 2020 through December 31, 2022 by accounting topic. The Registrants have elected to apply the amendments to modifications of debt arrangements that meet the scope of ASU 2020–04.

The Registrants currently reference LIBOR for certain debt and hedging arrangements. In addition, certain provisions in PPAs at Southern Power include references to LIBOR. Contract language has been, or is expected to be, incorporated into each of these agreements to address the transition to an alternative rate for agreements that will be in place at the transition date. While no material impacts are expected from modifications to the arrangements and effective hedging relationships are expected to 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:

<table><tr><td></td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>2021</td><td>$504</td><td>$663</td><td>$120</td><td>$89</td><td>$239</td></tr><tr><td>2020</td><td>478</td><td>639</td><td>149</td><td>87</td><td>237</td></tr><tr><td>2019</td><td>527</td><td>704</td><td>118</td><td>90</td><td>183</td></tr></table>

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:

<table><tr><td></td><td>Mississippi Power</td><td>Southern Power</td></tr><tr><td></td><td>(in millions)</td><td></td></tr><tr><td>2021</td><td>$9</td><td>$15</td></tr><tr><td>2020</td><td>4</td><td>8</td></tr><tr><td>2019</td><td>3</td><td>14</td></tr></table>



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.

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:

<table><tr><td></td><td>Alabama Power</td><td>Georgia Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td colspan="4">(in millions)</td></tr><tr><td>2021</td><td>$14</td><td>$108</td><td>$31</td><td>$29</td></tr><tr><td>2020</td><td>15</td><td>108</td><td>29</td><td>29</td></tr><tr><td>2019</td><td>17</td><td>99</td><td>28</td><td>31</td></tr></table>

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 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.

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 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 Nicro 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 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:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power \( ^{*)} \)</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>2021</td><td>$ 282</td><td>$ 68</td><td>$ 190</td><td>$ —</td><td>$ 6</td><td>$ 18</td></tr><tr><td>2020</td><td>230</td><td>61</td><td>138</td><td>1</td><td>11</td><td>18</td></tr><tr><td>2019</td><td>202</td><td>71</td><td>103</td><td>—</td><td>15</td><td>13</td></tr></table>

(*) 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.

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:

<table><tr><td></td><td>2021</td><td>2020</td><td>2019</td></tr><tr><td>Alabama Power</td><td>7.9%</td><td>8.1%</td><td>8.4%</td></tr><tr><td>Georgia Power \( ^{*)} \)</td><td>7.2%</td><td>6.9%</td><td>6.9%</td></tr><tr><td>Mississippi Power</td><td>2.5%</td><td>5.4%</td><td>7.3%</td></tr><tr><td>Southern Company Gas:</td><td></td><td></td><td></td></tr><tr><td>Atlanta Gas Light</td><td>7.7%</td><td>7.7%</td><td>7.8%</td></tr><tr><td>Chattanooga Gas</td><td>7.1%</td><td>7.1%</td><td>7.1%</td></tr><tr><td>Nicor Gas</td><td>0.1%</td><td>0.7%</td><td>2.3%</td></tr></table>

(*) 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:

<table><tr><td></td><td>Goodwill (in millions)</td></tr><tr><td>Southern Company</td><td>$5,280</td></tr><tr><td>Southern Company Gas:</td><td></td></tr><tr><td>Gas distribution operations</td><td>$4,034</td></tr><tr><td>Gas marketing services</td><td>981</td></tr><tr><td>Southern Company Gas total</td><td>$5,015</td></tr></table>

At December 31, 2021 and 2020, other intangible assets were as follows:

<table><tr><td rowspan="2"></td><td colspan="3">At December 31, 2021</td><td colspan="3">At December 31, 2020</td></tr><tr><td>Gross Carrying Amount</td><td>Accumulated Amortization</td><td>Other Intangible Assets, Net</td><td>Gross Carrying Amount</td><td>Accumulated Amortization</td><td>Other Intangible Assets Net</td></tr><tr><td>Southern Company</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other intangible assets subject to amortization:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Customer relationships</td><td>$212</td><td>$(150)</td><td>$62</td><td>$212</td><td>$135)</td><td>$77</td></tr><tr><td>Trade names</td><td>64</td><td>(38)</td><td>26</td><td>64</td><td>(31)</td><td>33</td></tr><tr><td>Storage and transportation contracts(1)</td><td>—</td><td>—</td><td>—</td><td>64</td><td>(64)</td><td>—</td></tr><tr><td>PPA fair value adjustments</td><td>390</td><td>(109)</td><td>281</td><td>390</td><td>(89)</td><td>301</td></tr><tr><td>Other</td><td>11</td><td>(10)</td><td>1</td><td>10</td><td>(9)</td><td>1</td></tr><tr><td>Total other intangible assets subject to amortization</td><td>$677</td><td>$(307)</td><td>$370</td><td>$740</td><td>$(328)</td><td>$412</td></tr><tr><td>Other intangible assets not subject to amortization:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Federal Communications Commission licenses</td><td>75</td><td>—</td><td>75</td><td>75</td><td>—</td><td>75</td></tr><tr><td>Total other intangible assets</td><td>$752</td><td>$(307)</td><td>$445</td><td>$815</td><td>$(328)</td><td>$487</td></tr><tr><td>Southern Power</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other intangible assets subject to amortization:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>PPA fair value adjustments</td><td>$390</td><td>$(109)</td><td>$281</td><td>$390</td><td>$(89)</td><td>$301</td></tr><tr><td>Southern Company Gas</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other intangible assets subject to amortization:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Gas marketing services</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Customer relationships</td><td>$156</td><td>$(130)</td><td>$26</td><td>$156</td><td>$(119)</td><td>$37</td></tr><tr><td>Trade names</td><td>26</td><td>(15)</td><td>11</td><td>26</td><td>(12)</td><td>14</td></tr><tr><td>Wholesale gas services</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Storage and transportation contracts(1)</td><td>—</td><td>—</td><td>—</td><td>64</td><td>(64)</td><td>—</td></tr><tr><td>Total other intangible assets subject to amortization</td><td>$182</td><td>$(145)</td><td>$37</td><td>$246</td><td>$(195)</td><td>$51</td></tr></table>

(*) See Note 15 under “Southern Company Gas” for information regarding the sale of Sequent.



Amortization associated with other intangible assets in 2021, 2020, and 2019 was as follows:

<table><tr><td></td><td>2021</td><td>2020</td><td>2019</td></tr><tr><td></td><td colspan="3">(in millions)</td></tr><tr><td>Southern Company \( ^{(a)} \)</td><td>44</td><td>49</td><td>61</td></tr><tr><td>Southern Power \( ^{(b)} \)</td><td>20</td><td>20</td><td>19</td></tr><tr><td>Southern Company Gas:</td><td></td><td></td><td></td></tr><tr><td>Gas marketing services</td><td>15</td><td>17</td><td>23</td></tr><tr><td>Wholesale gas services \( ^{(b)} \)</td><td>—</td><td>2</td><td>8</td></tr><tr><td>Southern Company Gas total</td><td>15</td><td>19</td><td>31</td></tr></table>

(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:

<table><tr><td></td><td>2022</td><td>2023</td><td>2024</td><td>2025</td><td>2026</td></tr><tr><td></td><td colspan="5">(in millions)</td></tr><tr><td>Southern Company</td><td>39</td><td>37</td><td>35</td><td>32</td><td>27</td></tr><tr><td>Southern Power</td><td>20</td><td>20</td><td>20</td><td>20</td><td>20</td></tr><tr><td>Southern Company Gas</td><td>11</td><td>9</td><td>7</td><td>6</td><td>3</td></tr></table>

Intangible liabilities of $91 million recorded under acquisition accounting for transportation contracts at Southern Company Gas were fully amortized at December 31, 2019.

## Acquisition Accounting

At the time of an acquisition, management will assess whether acquired assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, operating results from the date of acquisition are included in the acquiring entity's financial statements. The purchase price, including any contingent consideration, is allocated based on the fair value of the identifiable assets acquired and liabilities assumed (including any intangible assets). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition. The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired.

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

Historically, contingent consideration primarily relates to fixed amounts due to the seller once an acquired construction project is placed in service. For contingent consideration with variable payments, management fair values the arrangement with any changes recorded in the statements of income. See Note 13 for additional fair value information.

## Development Costs

For Southern Power, development costs are capitalized once a project is probable of completion, primarily based on a review of its economics and operational feasibility, as well as the status of power off-take agreements and regulatory approvals, if applicable. Southern Power's capitalized development costs are included in CWIP on the balance sheets. All of Southern Power's development costs incurred prior to the determination that a project is probable of completion are expensed as incurred and included in other operations and maintenance expense in the statements of income. If it is determined that a project is no longer probable of completion, any of Southern Power's capitalized development costs are expensed and included in other operations and maintenance expense in the statements of income.

## Long-Term Service Agreements

The traditional electric operating companies and Southern Power have entered into LTSAs for the purpose of securing maintenance support for certain of their generating facilities. The LTSAs cover all planned inspections on the covered equipment, 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:

<table><tr><td rowspan="2"></td><td colspan="2">Southern Company</td><td colspan="2">Southern Power</td><td colspan="2">Southern Company Gas</td></tr><tr><td>December 31, 2021</td><td>December 31, 2020</td><td>December 31, 2021</td><td>December 31, 2021</td><td>December 31, 2020</td><td></td></tr><tr><td></td><td colspan="2">(in millions)</td><td colspan="2">(in millions)</td><td colspan="2">(in millions</td></tr><tr><td>Cash and cash equivalents</td><td>$1,798</td><td>$1,065</td><td>$107</td><td>$45</td><td>$17</td><td></td></tr><tr><td>Restricted cash(a):</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other current assets</td><td>2</td><td>2</td><td>—</td><td>2</td><td>2</td><td></td></tr><tr><td>Other deferred charges and assets</td><td>29</td><td>—</td><td>29</td><td>—</td><td>—</td><td></td></tr><tr><td>Total cash, cash equivalents, and restricted cash(b)</td><td>$1,829</td><td>$1,068</td><td>$135</td><td>$48</td><td>$19</td><td></td></tr></table>

(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.

## 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:

<table><tr><td></td><td>Southern Company(a)(b)</td><td>Alabama Power(a)</td><td>Georgia Power</td><td>Mississippi Power(b)</td></tr><tr><td></td><td colspan="4">(in millions)</td></tr><tr><td>2021</td><td>$286</td><td>$ 75</td><td>$213</td><td>$(2)</td></tr><tr><td>2020</td><td>326</td><td>112</td><td>213</td><td>1</td></tr><tr><td>2019</td><td>170</td><td>139</td><td>30</td><td>1</td></tr></table>

(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.

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 Nicro 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 Nicro 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 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.

AOCI (loss) balances, net of tax effects, for Southern Company, Southern Power, and Southern Company Gas were as follows:

<table><tr><td></td><td>Qualifying Hedges</td><td>Pension and Other Postretirement Benefit Plans</td><td>Accumulated Other Comprehensive Income (Loss) \( ^{(1)} \)</td></tr><tr><td>Southern Company</td><td></td><td></td><td></td></tr><tr><td>Balance at December 31, 2020</td><td>$ (209)</td><td>$ (187)</td><td>$ (395)</td></tr><tr><td>Current period change</td><td>47</td><td>111</td><td>158</td></tr><tr><td>Balance at December 31, 2021</td><td>$ (162)</td><td>$ (76)</td><td>$ (237)</td></tr><tr><td>Southern Power</td><td></td><td></td><td></td></tr><tr><td>Balance at December 31, 2020</td><td>$ (21)</td><td>$ (47)</td><td>$ (67)</td></tr><tr><td>Current period change</td><td>22</td><td>18</td><td>40</td></tr><tr><td>Balance at December 31, 2021</td><td>$ 1</td><td>$ (29)</td><td>$ (27)</td></tr><tr><td>Southern Company Gas</td><td></td><td></td><td></td></tr><tr><td>Balance at December 31, 2020</td><td>$ (20)</td><td>$ (2)</td><td>$ (22)</td></tr><tr><td>Current period change</td><td>6</td><td>40</td><td>46</td></tr><tr><td>Balance at December 31, 2021</td><td>$ (14)</td><td>$ 38</td><td>$ 24</td></tr></table>

(*) 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.



## 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:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Company Gas</td></tr><tr><td></td><td colspan="5">(in millions)</td></tr><tr><td>At December 31, 2021</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>AROs(a)(u)</td><td>$ 5,685</td><td>$ 1,576</td><td>$ 3,866</td><td>$ 236</td><td>$ —</td></tr><tr><td>Retiree benefit plans(b)(u)</td><td>2,998</td><td>747</td><td>962</td><td>145</td><td>95</td></tr><tr><td>Remaining net book value of retired assets(c)</td><td>1,050</td><td>574</td><td>455</td><td>21</td><td>—</td></tr><tr><td>Deferred income tax charges(d)</td><td>829</td><td>240</td><td>555</td><td>31</td><td>—</td></tr><tr><td>Under recovered regulatory clause revenues(e)</td><td>806</td><td>225</td><td>—</td><td>49</td><td>532</td></tr><tr><td>Environmental remediation(f)(u)</td><td>302</td><td>—</td><td>35</td><td>—</td><td>267</td></tr><tr><td>Loss on reacquired debt(g)</td><td>281</td><td>42</td><td>231</td><td>6</td><td>2</td></tr><tr><td>Vacation pay(h)(u)</td><td>207</td><td>81</td><td>102</td><td>10</td><td>14</td></tr><tr><td>Regulatory clauses(i)</td><td>142</td><td>142</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Storm damage(j)</td><td>97</td><td>—</td><td>48</td><td>49</td><td>—</td></tr><tr><td>Long-term debt fair value adjustment(k)</td><td>79</td><td>—</td><td>—</td><td>—</td><td>79</td></tr><tr><td>Nuclear outage(l)</td><td>75</td><td>41</td><td>34</td><td>—</td><td>—</td></tr><tr><td>Software and cloud computing costs(m)</td><td>73</td><td>35</td><td>33</td><td>—</td><td>5</td></tr><tr><td>Kemper County energy facility assets, net(n)</td><td>35</td><td>—</td><td>—</td><td>35</td><td>—</td></tr><tr><td>Plant Daniel Units 3 and 4(o)</td><td>28</td><td>—</td><td>—</td><td>28</td><td>—</td></tr><tr><td>Other regulatory assets(p)</td><td>168</td><td>38</td><td>29</td><td>7</td><td>94</td></tr><tr><td>Deferred income tax credits(q)</td><td>(5,636)</td><td>(1,968)</td><td>(2,537)</td><td>(288)</td><td>(816)</td></tr><tr><td>Other cost of removal obligations(a)</td><td>(1,826)</td><td>(192)</td><td>278</td><td>(195)</td><td>(1,683)</td></tr><tr><td>Customer refunds(o)</td><td>(189)</td><td>(181)</td><td>(8)</td><td>—</td><td>—</td></tr><tr><td>Fuel-hedging (realized and unrealized) gains(r)</td><td>(176)</td><td>(50)</td><td>(72)</td><td>(54)</td><td>—</td></tr><tr><td>Storm/property damage reserves(s)</td><td>(133)</td><td>(103)</td><td>—</td><td>(30)</td><td>—</td></tr><tr><td>Over recovered regulatory clause revenues(e)</td><td>(63)</td><td>(1)</td><td>(59)</td><td>—</td><td>(3)</td></tr><tr><td>Other regulatory liabilities(t)</td><td>(121)</td><td>(29)</td><td>(24)</td><td>(4)</td><td>(57)</td></tr><tr><td>Total regulatory assets (liabilities), net</td><td>$ 4,711</td><td>$ 1,217</td><td>$ 3,928</td><td>$ 46</td><td>$ (1,471)</td></tr><tr><td>At December 31, 2020</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>AROs(a)(u)</td><td>$ 5,147</td><td>$ 1,470</td><td>$ 3,457</td><td>$ 212</td><td>$ —</td></tr><tr><td>Retiree benefit plans(b)(u)</td><td>4,958</td><td>1,265</td><td>1,647</td><td>238</td><td>187</td></tr><tr><td>Remaining net book value of retired assets(c)</td><td>1,183</td><td>632</td><td>527</td><td>24</td><td>—</td></tr><tr><td>Deferred income tax charges(d)</td><td>801</td><td>235</td><td>531</td><td>32</td><td>—</td></tr><tr><td>Environmental remediation(f)(u)</td><td>310</td><td>—</td><td>41</td><td>—</td><td>269</td></tr><tr><td>Loss on reacquired debt(g)</td><td>304</td><td>47</td><td>248</td><td>6</td><td>3</td></tr><tr><td>Storm damage(j)</td><td>262</td><td>—</td><td>262</td><td>—</td><td>—</td></tr><tr><td>Vacation pay(h)(u)</td><td>207</td><td>80</td><td>104</td><td>10</td><td>13</td></tr><tr><td>Under recovered regulatory clause revenues(e)</td><td>185</td><td>58</td><td>—</td><td>52</td><td>75</td></tr><tr><td>Regulatory clauses(i)</td><td>142</td><td>142</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Nuclear outage(l)</td><td>101</td><td>61</td><td>40</td><td>—</td><td>—</td></tr><tr><td>Long-term debt fair value adjustment(k)</td><td>92</td><td>—</td><td>—</td><td>—</td><td>92</td></tr><tr><td>Kemper County energy facility assets, net(n)</td><td>50</td><td>—</td><td>—</td><td>50</td><td>—</td></tr><tr><td>Plant Daniel Units 3 and 4(o)</td><td>32</td><td>—</td><td>—</td><td>32</td><td>—</td></tr><tr><td>Software and cloud computing costs(m)</td><td>31</td><td>17</td><td>12</td><td>—</td><td>2</td></tr><tr><td>Other regulatory assets(p)</td><td>174</td><td>35</td><td>56</td><td>4</td><td>79</td></tr><tr><td>Deferred income tax credits(q)</td><td>(6,016)</td><td>(2,016)</td><td>(2,805)</td><td>(320)</td><td>(847)</td></tr><tr><td>Other cost of removal obligations(a)</td><td>(1,999)</td><td>(335)</td><td>212</td><td>(194)</td><td>(1,649)</td></tr><tr><td>Over recovered regulatory clause revenues(e)</td><td>(185)</td><td>(46)</td><td>(44)</td><td>—</td><td>(95)</td></tr><tr><td>Storm/property damage reserves(s)</td><td>(81)</td><td>(77)</td><td>—</td><td>(4)</td><td>—</td></tr><tr><td>Customer refunds(o)</td><td>(56)</td><td>(50)</td><td>(6)</td><td>—</td><td>—</td></tr><tr><td>Other regulatory liabilities(t)</td><td>(149)</td><td>(37)</td><td>(30)</td><td>(6)</td><td>(54)</td></tr><tr><td>Total regulatory assets (liabilities), net</td><td>$ 5,493</td><td>$ 1,481</td><td>$ 4,252</td><td>$ 136</td><td>$ (1,925)</td></tr></table>



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.

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.

## 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 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.

## 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.



## 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 billing, 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.

## 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:

<table><tr><td>Tariff</td><td>2020</td><td>2021</td><td>2022</td></tr><tr><td></td><td colspan="3">(in millions)</td></tr><tr><td>Traditional base</td><td>$ —</td><td>$ 120</td><td>$ 192</td></tr><tr><td>ECCR \( ^{*} \)</td><td>318</td><td>2</td><td>(12)</td></tr><tr><td>DSM</td><td>12</td><td>(15)</td><td>(25)</td></tr><tr><td>MFF</td><td>12</td><td>4</td><td>2</td></tr><tr><td>Total</td><td>$ 342</td><td>$ 111</td><td>$ 157</td></tr></table>

(*) 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 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 prudence 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.

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.

## 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:

<table><tr><td></td><td>(in millions)</td></tr><tr><td>Base project capital cost forecast \( ^{(a)(b)} \)</td><td>10,251</td></tr><tr><td>Construction contingency estimate</td><td>150</td></tr><tr><td>Total project capital cost forecast \( ^{(a)(b)} \)</td><td>10,401</td></tr><tr><td>Net investment at December 31, 2021 \( ^{(b)} \)</td><td>(8,442)</td></tr><tr><td>Remaining estimate to complete</td><td>$ 1,959</td></tr></table>

(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.

As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and related test results, and workforce statistics. Southern Nuclear establishes aggressive target values for monthly construction production and system turnover activities, which are reflected in the site work plans.

In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures; isolating individuals who tested positive for COVID-19, showed symptoms consistent with COVID-19, were being tested for COVID-19, or were in close contact with such persons; requiring self-quarantine; and adopting additional precautionary measures. Since March 2020, the number of active cases at the site has fluctuated consistent with the surrounding area and impacted productivity levels and pace of activity completion, with the site experiencing peaks in the number of active cases in January 2021, August 2021, and January 2022. Georgia Power estimates the productivity impacts of the COVID-19 pandemic have consumed approximately three to four months of schedule margin previously embedded in the site work plan for Unit 3 and Unit 4. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $160 million and $200 million and is included in the total project capital cost forecast. The continuing effects of the COVID-19 pandemic could further disrupt or delay construction and testing activities at Plant Vogtle Units 3 and 4.



During 2021, Southern Nuclear performed additional construction remediation work necessary to ensure quality and design standards are met and support system turnovers necessary for Unit 3 hot functional testing, which was completed in July 2021, and fuel load. As a result of Unit 3 challenges including, but not limited to, construction productivity, construction remediation work, the pace of system turnovers, spent fuel pool repairs, and the timeframe and duration for hot functional and other testing, at the end of each of the second and third quarters 2021, Southern Nuclear further extended certain milestone dates, including fuel load for Unit 3, from those established in January 2021. Through the fourth quarter 2021, the project continued to face these and other challenges related to the completion of documentation, including inspection records, necessary to submit the remaining ITAACs and begin fuel load. As a result, at the end of the fourth quarter 2021, Southern Nuclear further extended certain milestone dates, including fuel load for Unit 3, from those established at the end of the third quarter 2021. The site work plan currently targets fuel load for Unit 3 in the second quarter 2022 and an in-service date during the third quarter 2022 and primarily depends on significant improvements in overall construction productivity and production levels, the volume of construction remediation work, the pace of system and area turnovers, and the progression of startup and other testing. As the site work plan includes minimal margin to these milestone dates, an in-service date during the fourth quarter 2022 or the first quarter 2023 for Unit 3 is projected, although any further delays could result in a later in-service date.

As the result of productivity challenges and temporarily diverting some Unit 4 craft and support resources to Unit 3 construction efforts, at the end of each of the second and third quarters 2021, Southern Nuclear also further extended milestone dates for Unit 4 from those established in January 2021. The temporary diversion of Unit 4 resources to support Unit 3 has continued into the first quarter 2022; therefore, at the end of the fourth quarter 2021, Southern Nuclear further extended milestone dates for Unit 4 from those established at the end of the third quarter 2021. The site work plan targets an in-service date during the first quarter 2023 for Unit 4 and primarily depends on overall construction productivity and production levels significantly improving as well as appropriate levels of craft laborers, particularly electricians and pipefitters, being added and maintained. As the site work plan includes minimal margin to the milestone dates, an in-service date during the third or fourth quarter 2023 for Unit 4 is projected, although any further delays could result in a later in-service date.

During 2021, established construction contingency and additional costs totaling $1.3 billion were assigned to the base capital cost forecast for costs primarily associated with schedule extensions, construction productivity, the pace of system turnovers, and support resources for Units 3 and 4. Georgia Power also increased its total capital cost forecast as of December 31, 2021 by $99 million to replenish construction contingency.

After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded pre-tax charges to income in the first quarter 2021, the second quarter 2021, the third quarter 2021, and the fourth quarter 2021 of $48 million ($36 million after tax), $460 million ($343 million after tax), $264 million ($197 million after tax), and $480 million ($358 million after tax), respectively, for the increases in the total project capital cost forecast. Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery during the prudence review following the Unit 4 fuel load pursuant to the twenty-fourth VCM stipulation described below. In addition, Georgia Power recorded a pre-tax charge to income in the fourth quarter 2021 of approximately $440 million ($328 million after tax) for incremental costs, which will not be recovered from retail customers, associated with the cost-sharing and tender provisions of the joint ownership agreements described below.

As Unit 3 completes system turnover from construction and moves to testing and transition to operations, ongoing and potential future challenges include completion of construction remediation work, completion of work packages, including inspection records, and other documentation necessary to submit the remaining ITAACs and begin fuel load, and final component and pre-operational tests. As Unit 4 progresses through construction and continues to transition into testing, ongoing and potential future challenges include the pace and quality of electrical installation, availability of craft and supervisory resources, including the temporary diversion of such resources to support Unit 3 construction efforts, and the pace of work package closures and system turnovers. As construction, including subcontract work, continues on both Units 3 and 4, ongoing or future challenges include management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; and procurement and related installation. New challenges may arise, particularly as Units 3 and 4 move into initial testing and start-up, which may result in required engineering changes or remediation related to plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale). The ongoing and potential future challenges described above may change the projected schedule and estimated cost.



There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to ensure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. In connection with the additional construction remediation work described above, Southern Nuclear reviewed the project's construction quality programs and, where needed, is implementing improvement plans consistent with these processes. On November 17, 2021, the NRC issued the final significance report on its special inspection to review the root cause of this additional construction remediation work and the corresponding corrective action plans with two findings of low to moderate safety significance. Southern Nuclear had already identified and self-reported many of the issues in this report to the NRC and implemented corrective-action plans to resolve these issues. The NRC will conduct a follow-up inspection on these findings at a future date. Findings resulting from this or other inspections could require additional remediation and/or further NRC oversight. In addition, certain license amendment requests have been filed and approved or are pending before the NRC.

The site work plan currently targets fuel load for Units 3 and 4 in the second quarter 2022 and the fourth quarter 2022, respectively. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, have arisen or may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues, including inspections and ITAACs, are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the in-service date beyond the first quarter 2023 for Unit 3 or the fourth quarter 2023 for Unit 4, including the current level of cost sharing described below, is estimated to result in additional base capital costs for Georgia Power of up to $60 million per month for Unit 3 and $40 million per month for Unit 4, as well as the related AFUDC and any additional related construction, support resources, or testing costs. While Georgia Power is not precluded from seeking retail recovery of any future capital cost forecast increase other than the amounts related to the cost-sharing and tender provisions of the joint ownership agreements described below, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

## Joint Owner Contracts

In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.

## 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.

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.

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.

## Integrated Resource Plan

In 2019, Mississippi Power updated its proposed Reserve Margin Plan (RMP), originally filed in 2018, as required by the Mississippi PSC. In 2018, Mississippi Power had proposed alternatives to reduce its reserve margin and lower or avoid operating costs. In December 2020, the Mississippi PSC issued an order concluding the RMP docket and requiring Mississippi Power to incorporate into its 2021 IRP a schedule of early or anticipated retirement of 950 MWs of fossil-steam generation by year-end 2027 to reduce Mississippi Power’s excess reserve margin. The order stated that Mississippi Power will be allowed to defer any retirement-related costs as regulatory assets for future recovery.

On September 9, 2021, the Mississippi PSC issued an order confirming the conclusion of its review of Mississippi Power’s 2021 IRP with no deficiencies identified. The 2021 IRP included a schedule to retire Plant Watson Unit 4 (268 MWs) and Mississippi Power’s 40% ownership interest in Plant Greene County Units 1 and 2 (103 MWs each) in December 2023, 2025, and 2026, respectively, consistent with each unit’s remaining useful life in the most recent approved depreciation studies. In addition, the schedule reflects the early retirement of Mississippi Power’s 50% undivided ownership interest in Plant Daniel Units 1 and 2 (502 MWs) by the end of 2027. The Plant Greene County unit retirements require the completion by Alabama Power of transmission and system reliability improvements, as well as agreement by Alabama Power.

The remaining net book value of Plant Daniel Units 1 and 2 was approximately $515 million at December 31, 2021 and Mississippi Power is continuing to depreciate these units using the current approved rates through the end of 2027. Mississippi Power expects to reclassify the net book value remaining at retirement, which is expected to total approximately $386 million, to a regulatory asset to be amortized over a period to be determined by the Mississippi PSC in future proceedings, consistent with the December 2020 order. The Plant Watson and Greene County units are expected to be fully depreciated upon retirement. The ultimate outcome of these matters cannot be determined at this time. See Note 3 under “Other Matters – Mississippi Power” for additional information on Plant Daniel Units 1 and 2.



## Environmental Compliance Overview Plan

In accordance with a 2011 accounting order from the Mississippi PSC, Mississippi Power has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations.

In accordance with a Mississippi PSC-approved settlement agreement between Mississippi Power and the MPUS, Mississippi Power was not required to make any ECO Plan filings for 2019 and 2020, and any necessary adjustments were reflected in Mississippi Power's 2019 base rate case.

In 2019, the Mississippi PSC approved Mississippi Power’s request for a CPCN to complete certain environmental compliance projects, primarily associated with the Plant Daniel coal units co-owned 50% with Gulf Power. The total estimated cost is approximately $125 million, with Mississippi Power’s share of approximately $67 million being proposed for recovery through its ECO Plan. As of December 31, 2021, approximately $20 million of Mississippi Power’s share is included in plant in service, approximately $14 million is included in CWIP, and approximately $13 million associated with ash pond closure is reflected in Mississippi Power’s ARO liabilities. See Note 6 for additional information on AROs and Note 3 under “Other Matters – Mississippi Power” for additional information on Gulf Power’s ownership in Plant Daniel.

On June 8, 2021, the Mississippi PSC approved Mississippi Power’s ECO Plan filing for 2021, resulting in a decrease in revenues of approximately $9 million annually, primarily due to a change in the amortization periods of certain regulatory assets and liabilities. The rate decrease became effective with the first billing cycle of July 2021.

## Fuel Cost Recovery

Mississippi Power annually establishes and is required to file for an adjustment to the retail fuel cost recovery factor that is approved by the Mississippi PSC. The Mississippi PSC approved decreases of $35 million and $24 million effective in February 2019 and 2020, respectively, and increases of $2 million and $43 million effective in February 2021 and 2022, respectively. At December 31, 2021, under recovered retail fuel costs totaled approximately $4 million and were included in other customer accounts receivable on Southern Company's and Mississippi Power's balance sheets. At December 31, 2020, over recovered retail fuel costs totaled $24 million and were included in other current liabilities on Southern Company's balance sheet and over recovered regulatory clause liabilities on Mississippi Power's balance sheet.

Mississippi Power has wholesale MRA and Market Based (MB) fuel cost recovery factors. Effective with the first billing cycles for January 2020, 2021, and 2022, annual revenues under the wholesale MRA fuel rate increased $1 million, decreased $5 million, and increased $11 million, respectively. The wholesale MB fuel rate did not change materially in any period presented. At December 31, 2021, under recovered wholesale fuel costs were immaterial. At December 31, 2020, over recovered 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 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.



## Notes to Financial Statements

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

<table><tr><td></td><td>Nico Gas</td><td>Atlanta Gas Light</td><td>Virginia Natural Gas</td><td>Chattanooga Gas</td></tr><tr><td>Authorized ROE \( ^{(a)} \)</td><td>9.75%</td><td>10.25%</td><td>9.50%</td><td>9.80%</td></tr><tr><td>Weather normalization mechanisms \( ^{(b)} \)</td><td></td><td></td><td>✓</td><td>✓</td></tr><tr><td>Decoupled, including straight-fixed-variable rates \( ^{(c)} \)</td><td>✓</td><td>✓</td><td>✓</td><td></td></tr><tr><td>Regulatory infrastructure program rates \( ^{(d)} \)</td><td>✓</td><td>✓</td><td>✓</td><td>✓</td></tr><tr><td>Bad debt rider \( ^{(e)} \)</td><td>✓</td><td></td><td>✓</td><td>✓</td></tr><tr><td>Energy efficiency plan \( ^{(f)} \)</td><td>✓</td><td></td><td>✓</td><td></td></tr><tr><td>Annual base rate adjustment mechanism \( ^{(g)} \)</td><td></td><td>✓</td><td></td><td>✓</td></tr><tr><td>Year of last base rate case decision \( ^{(h)} \)</td><td>2021</td><td>2019</td><td>2021</td><td>2018</td></tr></table>

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

<table><tr><td>Utility</td><td>Program</td><td>Recovery</td><td>Expenditures in 2021</td><td>Expenditures Since Project Inception</td><td>Expenditures Since Project Inception</td><td>Pipe Installed Since Project Inception</td><td>Scope of Program</td><td>Program Duration</td><td>Last Year of Program</td></tr><tr><td>Nicro Gas</td><td>Investing in Illinois \( ^{(r)} \)</td><td>Rider</td><td></td><td>($ 40 $ 8</td><td>$ 2,508</td><td>1,153</td><td>1,394</td><td>9</td><td>2023</td></tr><tr><td>Virginia Natural Gas</td><td>Steps to Advance Virginia&#x27;s Energy (SAVE)</td><td>Rider</td><td>51</td><td>342</td><td>470</td><td>640</td><td>13</td><td>2024</td><td></td></tr><tr><td>Atlanta Gas Light</td><td>System Reinforcement Rider</td><td>Rider</td><td>—</td><td>—</td><td>N/A</td><td>N/A</td><td>3</td><td>2024</td><td></td></tr><tr><td>Chattanooga Gas</td><td>Pipeline Replacement Program</td><td>Rate Base</td><td>2</td><td>2</td><td>5</td><td>73</td><td>7</td><td>2027</td><td></td></tr><tr><td>Total</td><td></td><td></td><td>$461</td><td>$2,852</td><td>1,628</td><td>2,107</td><td></td><td></td><td></td></tr></table>

(*) 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 “Nicro Gas” herein.



## Nior Gas

Illinois legislation allows Nior 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, Nior Gas recovers program costs incurred through a separate rider and base rates. The Illinois Commission's approval of Nior Gas' rate case on November 18, 2021 included recovery of program costs through December 31, 2021. See "Rate Proceedings – Nior Gas" herein for additional information. Nior 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.

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

## Nior 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.

On February 16, 2021, the Georgia PSC approved a stipulation between Atlanta Gas Light and the Georgia PSC staff establishing a long-range comprehensive planning process. Under the terms of the stipulation, Atlanta Gas Light was required to develop and file at least triennially an Integrated Capacity and Delivery Plan (i-CDP). Each i-CDP will include a 10-year forecast of interstate and intrastate capacity asset requirements, including a detailed plan for the first three years consistent with Atlanta Gas Light's current capacity supply plan, and a 10-year projection of capital budgets and related operations and maintenance spending. Recovery of the related revenue requirements will be included in either subsequent annual GRAM filings or a new System Reinforcement Rider for authorized large pressure improvement and system reliability projects.

On April 28, 2021, Atlanta Gas Light filed its first i-CDP with the Georgia PSC, which includes a series of ongoing and proposed pipeline safety, reliability, and growth programs for the next 10 years (2022 through 2031), as well as the required capital investments and related costs to implement the programs. The i-CDP reflected capital investments totaling approximately $0.5 billion to $0.6 billion annually.

On November 18, 2021, the Georgia PSC approved an October 14, 2021 joint stipulation agreement between Atlanta Gas Light and the staff of the Georgia PSC, under which, for the years 2022 through 2024, Atlanta Gas Light will incrementally reduce its combined GRAM and System Reinforcement Rider request by 10% through Atlanta Gas Light's GRAM mechanism, or $5 million for 2022. The stipulation agreement also provides for $1.7 billion of total capital investment for the years 2022 through 2024.



Also on November 18, 2021, the Georgia PSC approved Atlanta Gas Light's amended annual GRAM filing, which resulted in an annual rate increase of $43 million effective January 1, 2022.

## Virginia Natural Gas

On September 14, 2021, the Virginia Commission approved a stipulation agreement related to Virginia Natural Gas' June 2020 general rate case filing, which allows for a $43 million increase in annual base rate revenues, including $14 million related to the recovery of investments under the SAVE program, based on a ROE of 9.5% and an equity ratio of 51.9%. Interim rate adjustments became effective as of November 1, 2020, subject to refund, based on Virginia Natural Gas' original request for an increase of approximately $50 million. Refunds to customers related to the difference between the approved rates and the interim rates were completed during the fourth quarter 2021.

## Deferral of Incremental COVID-19 Costs

As discussed under “Utility Regulation and Rate Design,” the natural gas distribution utilities have various regulatory mechanisms to recover bad debt expense, which helped mitigate potential increases in bad debt expense as a result of the COVID-19 pandemic. Deferred incremental costs related to the COVID-19 pandemic were immaterial for Virginia Natural Gas.

## Atlanta Gas Light

In April 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Atlanta Gas Light to continue its previous, voluntary suspension of customer disconnections. In June 2020, the Georgia PSC ordered Atlanta Gas Light to resume customer disconnections beginning July 2020, with exceptions for customers still covered by a shelter-in-place order. All suspensions for customer disconnections were lifted in October 2020. The orders provide the Marketers, including SouthStar, with a mechanism to receive credits from Atlanta Gas Light for the base rates it charged to the Marketers of non-paying customers during the suspension. Atlanta Gas Light will begin recovering these credits through GRAM rates effective January 1, 2023.

## Nior 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 Nior 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. Nior 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. Nior Gas began certain disconnections in late April 2021 and resumed normal disconnections in June 2021. At December 31, 2021 and 2020, Nior Gas' related regulatory asset was $5 million and $9 million, respectively.

## 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.

<table><tr><td></td><td>December 31, 2021</td><td>December 31, 2020</td></tr><tr><td></td><td>(in millions)</td><td></td></tr><tr><td>Atlanta Gas Light</td><td>$47</td><td>$59</td></tr><tr><td>Virginia Natural Gas</td><td>10</td><td>10</td></tr><tr><td>Chattanooga Gas</td><td>4</td><td>2</td></tr><tr><td>Nior Gas</td><td>—</td><td>3</td></tr><tr><td>Total</td><td>$61</td><td>$74</td></tr></table>



## 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 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.

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.

<table><tr><td></td><td>Southern Company</td><td>Georgia Power</td><td>Southern Company Gas</td></tr><tr><td></td><td colspan="3">(in millions)</td></tr><tr><td>December 31, 2021:</td><td></td><td></td><td></td></tr><tr><td>Environmental remediation liability:</td><td></td><td></td><td></td></tr><tr><td>Other current liabilities</td><td>$ 69</td><td>$17</td><td>$ 52</td></tr><tr><td>Accrued environmental remediation</td><td>197</td><td>—</td><td>197</td></tr><tr><td>Under recovered environmental remediation costs:</td><td></td><td></td><td></td></tr><tr><td>Other regulatory assets, current</td><td>$ 71</td><td>$12</td><td>$ 59</td></tr><tr><td>Other regulatory assets, deferred</td><td>231</td><td>23</td><td>208</td></tr><tr><td>December 31, 2020:</td><td></td><td></td><td></td></tr><tr><td>Environmental remediation liability:</td><td></td><td></td><td></td></tr><tr><td>Other current liabilities</td><td>$ 44</td><td>$15</td><td>$ 29</td></tr><tr><td>Accrued environmental remediation</td><td>216</td><td>—</td><td>216</td></tr><tr><td>Under recovered environmental remediation costs:</td><td></td><td></td><td></td></tr><tr><td>Other regulatory assets, current</td><td>$ 46</td><td>$12</td><td>$ 34</td></tr><tr><td>Other regulatory assets, deferred</td><td>265</td><td>29</td><td>236</td></tr></table>

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 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 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 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:

<table><tr><td></td><td>Pipeline Charges, Storage Capacity, and Gas Supply</td></tr><tr><td></td><td>(in millions)</td></tr><tr><td>2022</td><td>$ 634</td></tr><tr><td>2023</td><td>455</td></tr><tr><td>2024</td><td>376</td></tr><tr><td>2025</td><td>275</td></tr><tr><td>2026</td><td>164</td></tr><tr><td>Thereafter</td><td>910</td></tr><tr><td>Total</td><td>$2,814</td></tr></table>

## 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.



## 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:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td>2021</td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Retail electric revenues</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>$ 6,207</td><td>$2,467</td><td>$3,471</td><td>$ 269</td><td>$ —</td><td>$ —</td></tr><tr><td>Commercial</td><td>4,877</td><td>1,600</td><td>3,010</td><td>267</td><td>—</td><td>—</td></tr><tr><td>Industrial</td><td>3,067</td><td>1,386</td><td>1,391</td><td>290</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>93</td><td>17</td><td>68</td><td>8</td><td>—</td><td>—</td></tr><tr><td>Total retail electric revenues</td><td>14,244</td><td>5,470</td><td>7,940</td><td>834</td><td>—</td><td>—</td></tr><tr><td>Natural gas distribution revenues</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>1,799</td><td>—</td><td>—</td><td>—</td><td>—</td><td>1,799</td></tr><tr><td>Commercial</td><td>470</td><td>—</td><td>—</td><td>—</td><td>—</td><td>470</td></tr><tr><td>Transportation</td><td>1,038</td><td>—</td><td>—</td><td>—</td><td>—</td><td>1,038</td></tr><tr><td>Industrial</td><td>49</td><td>—</td><td>—</td><td>—</td><td>—</td><td>49</td></tr><tr><td>Other</td><td>269</td><td>—</td><td>—</td><td>—</td><td>—</td><td>269</td></tr><tr><td>Total natural gas distribution revenues</td><td>3,625</td><td>—</td><td>—</td><td>—</td><td>—</td><td>3,625</td></tr><tr><td>Wholesale electric revenues</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>PPA energy revenues</td><td>1,122</td><td>184</td><td>95</td><td>11</td><td>854</td><td>—</td></tr><tr><td>PPA capacity revenues</td><td>493</td><td>115</td><td>55</td><td>5</td><td>323</td><td>—</td></tr><tr><td>Non-PPA revenues</td><td>236</td><td>170</td><td>21</td><td>401</td><td>398</td><td>—</td></tr><tr><td>Total wholesale electric revenues</td><td>1,851</td><td>469</td><td>171</td><td>417</td><td>1,575</td><td>—</td></tr><tr><td>Other natural gas revenues</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Wholesale gas services</td><td>2,168</td><td>—</td><td>—</td><td>—</td><td>—</td><td>2,168</td></tr><tr><td>Gas marketing services</td><td>464</td><td>—</td><td>—</td><td>—</td><td>—</td><td>464</td></tr><tr><td>Other natural gas revenues</td><td>36</td><td>—</td><td>—</td><td>—</td><td>—</td><td>36</td></tr><tr><td>Total natural gas revenues</td><td>2,668</td><td>—</td><td>—</td><td>—</td><td>—</td><td>2,668</td></tr><tr><td>Other revenues</td><td>1,075</td><td>202</td><td>452</td><td>31</td><td>30</td><td>—</td></tr><tr><td>Total revenue from contracts with customers</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other revenue sources(a)</td><td>23,463</td><td>6,141</td><td>8,563</td><td>1,282</td><td>1,605</td><td>6,293</td></tr><tr><td>Other adjustments(b)</td><td>3,349</td><td>272</td><td>697</td><td>40</td><td>611</td><td>1,786</td></tr><tr><td>Total operating revenues</td><td>(3,699)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(3,699)</td></tr></table>



## Notes to Financial Statements

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td>2020</td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Retail electric revenues</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>$ 6,113</td><td>$2,377</td><td>$3,476</td><td>$ 260</td><td>$ —</td><td>$ —</td></tr><tr><td>Commercial</td><td>4,699</td><td>1,512</td><td>2,933</td><td>254</td><td>—</td><td>—</td></tr><tr><td>Industrial</td><td>2,775</td><td>1,293</td><td>1,197</td><td>285</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>90</td><td>21</td><td>60</td><td>9</td><td>—</td><td>—</td></tr><tr><td>Total retail electric revenues</td><td>13,677</td><td>5,203</td><td>7,666</td><td>808</td><td>—</td><td>—</td></tr><tr><td>Natural gas distribution revenues</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>1,338</td><td>—</td><td>—</td><td>—</td><td>—</td><td>1,338</td></tr><tr><td>Commercial</td><td>340</td><td>—</td><td>—</td><td>—</td><td>—</td><td>340</td></tr><tr><td>Transportation</td><td>971</td><td>—</td><td>—</td><td>—</td><td>—</td><td>971</td></tr><tr><td>Industrial</td><td>30</td><td>—</td><td>—</td><td>—</td><td>—</td><td>30</td></tr><tr><td>Other</td><td>209</td><td>—</td><td>—</td><td>—</td><td>—</td><td>209</td></tr><tr><td>Total natural gas distribution revenues</td><td>2,888</td><td>—</td><td>—</td><td>—</td><td>—</td><td>2,888</td></tr><tr><td>Wholesale electric revenues</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>PPA energy revenues</td><td>735</td><td>133</td><td>42</td><td>9</td><td>570</td><td>—</td></tr><tr><td>PPA capacity revenues</td><td>454</td><td>108</td><td>50</td><td>3</td><td>296</td><td>—</td></tr><tr><td>Non-PPA revenues</td><td>210</td><td>43</td><td>10</td><td>311</td><td>239</td><td>—</td></tr><tr><td>Total wholesale electric revenues</td><td>1,399</td><td>284</td><td>102</td><td>323</td><td>1,105</td><td>—</td></tr><tr><td>Other natural gas revenues</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Wholesale gas services</td><td>1,727</td><td>—</td><td>—</td><td>—</td><td>—</td><td>1,727</td></tr><tr><td>Gas marketing services</td><td>391</td><td>—</td><td>—</td><td>—</td><td>—</td><td>391</td></tr><tr><td>Other natural gas revenues</td><td>33</td><td>—</td><td>—</td><td>—</td><td>—</td><td>33</td></tr><tr><td>Total other natural gas revenues</td><td>2,151</td><td>—</td><td>—</td><td>—</td><td>—</td><td>2,151</td></tr><tr><td>Other revenues</td><td>982</td><td>159</td><td>447</td><td>26</td><td>14</td><td>—</td></tr><tr><td>Total revenue from contracts with customers</td><td>21,097</td><td>5,646</td><td>8,215</td><td>1,157</td><td>1,119</td><td>5,039</td></tr><tr><td>Other revenue sources(a)</td><td>3,764</td><td>184</td><td>94</td><td>15</td><td>614</td><td>2,881</td></tr><tr><td>Other adjustments(b)</td><td>(4,486)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(4,486)</td></tr><tr><td>Total operating revenues</td><td>$20,375</td><td>$5,830</td><td>$8,309</td><td>$1,172</td><td>$1,733</td><td>$ 3,434</td></tr></table>



<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td>2019</td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Retail electric revenues</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>$ 6,164</td><td>$2,509</td><td>$3,377</td><td>$ 278</td><td>$ —</td><td>$ —</td></tr><tr><td>Commercial</td><td>5,065</td><td>1,677</td><td>3,097</td><td>291</td><td>—</td><td>—</td></tr><tr><td>Industrial</td><td>3,126</td><td>1,460</td><td>1,360</td><td>306</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>90</td><td>25</td><td>54</td><td>11</td><td>—</td><td>—</td></tr><tr><td>Total retail electric revenues</td><td>14,445</td><td>5,671</td><td>7,888</td><td>886</td><td>—</td><td>—</td></tr><tr><td>Natural gas distribution revenues</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>1,413</td><td>—</td><td>—</td><td>—</td><td>—</td><td>1,413</td></tr><tr><td>Commercial</td><td>389</td><td>—</td><td>—</td><td>—</td><td>—</td><td>389</td></tr><tr><td>Transportation</td><td>907</td><td>—</td><td>—</td><td>—</td><td>—</td><td>907</td></tr><tr><td>Industrial</td><td>35</td><td>—</td><td>—</td><td>—</td><td>—</td><td>35</td></tr><tr><td>Other</td><td>245</td><td>—</td><td>—</td><td>—</td><td>—</td><td>245</td></tr><tr><td>Total natural gas distribution revenues</td><td>2,989</td><td>—</td><td>—</td><td>—</td><td>—</td><td>2,989</td></tr><tr><td>Wholesale electric revenues</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>PPA energy revenues</td><td>833</td><td>145</td><td>60</td><td>11</td><td>648</td><td>—</td></tr><tr><td>PPA capacity revenues</td><td>453</td><td>102</td><td>54</td><td>3</td><td>322</td><td>—</td></tr><tr><td>Non-PPA revenues</td><td>232</td><td>81</td><td>9</td><td>352</td><td>238</td><td>—</td></tr><tr><td>Total wholesale electric revenues</td><td>1,518</td><td>328</td><td>123</td><td>366</td><td>1,208</td><td>—</td></tr><tr><td>Other natural gas revenues</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Gas pipeline investments</td><td>32</td><td>—</td><td>—</td><td>—</td><td>—</td><td>32</td></tr><tr><td>Wholesale gas services</td><td>2,095</td><td>—</td><td>—</td><td>—</td><td>—</td><td>2,095</td></tr><tr><td>Gas marketing services</td><td>440</td><td>—</td><td>—</td><td>—</td><td>—</td><td>440</td></tr><tr><td>Other natural gas revenues</td><td>42</td><td>—</td><td>—</td><td>—</td><td>—</td><td>42</td></tr><tr><td>Total other natural gas revenues</td><td>2,609</td><td>—</td><td>—</td><td>—</td><td>—</td><td>2,609</td></tr><tr><td>Other revenues</td><td>1,035</td><td>153</td><td>407</td><td>19</td><td>12</td><td>—</td></tr><tr><td>Total revenue from contracts with customers</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other revenue sources(a)</td><td>22,596</td><td>6,152</td><td>8,418</td><td>1,271</td><td>1,220</td><td>5,598</td></tr><tr><td>Other adjustments(b)</td><td>4,266</td><td>(27)</td><td>(10)</td><td>(7)</td><td>718</td><td>3,637</td></tr><tr><td>Total operating revenues</td><td>(5,443)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(5,443)</td></tr></table>

(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.



## 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:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>Accounts Receivable</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>At December 31, 2021</td><td>$2,504</td><td>$589</td><td>$736</td><td>$73</td><td>$149</td><td>$753</td></tr><tr><td>At December 31, 2020</td><td>2,614</td><td>632</td><td>806</td><td>77</td><td>112</td><td>788</td></tr><tr><td>Contract Assets</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>At December 31, 2021</td><td>$ 117</td><td>$ 2</td><td>$ 63</td><td>$ —</td><td>$ 1</td><td>$ —</td></tr><tr><td>At December 31, 2020</td><td>158</td><td>2</td><td>71</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Contract Liabilities</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>At December 31, 2021</td><td>$ 57</td><td>$ 4</td><td>$ 14</td><td>$ —</td><td>$ 1</td><td>$ —</td></tr><tr><td>At December 31, 2020</td><td>61</td><td>6</td><td>27</td><td>1</td><td>1</td><td>1</td></tr></table>

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:

<table><tr><td></td><td>2022</td><td>2023</td><td>2024</td><td>2025</td><td>2026</td><td>Thereafter</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>Southern Company</td><td>$577</td><td>$462</td><td>$341</td><td>$319</td><td>$295</td><td>$2,309</td></tr><tr><td>Alabama Power</td><td>33</td><td>24</td><td>7</td><td>5</td><td>—</td><td>—</td></tr><tr><td>Georgia Power</td><td>68</td><td>48</td><td>25</td><td>22</td><td>11</td><td>31</td></tr><tr><td>Southern Power</td><td>331</td><td>293</td><td>309</td><td>292</td><td>287</td><td>2,294</td></tr></table>

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.

The Registrants' property, plant, and equipment in service consisted of the following at December 31, 2021 and 2020:

<table><tr><td>At December 31, 2021:</td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>Electric utilities:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Generation</td><td>$ 53,803</td><td>$16,631</td><td>$19,184</td><td>$2,791</td><td>$14,551</td><td>$ —</td></tr><tr><td>Transmission</td><td>13,406</td><td>5,334</td><td>7,132</td><td>900</td><td>—</td><td>—</td></tr><tr><td>Distribution</td><td>22,236</td><td>8,643</td><td>12,437</td><td>1,156</td><td>—</td><td>—</td></tr><tr><td>General/other</td><td>5,423</td><td>2,527</td><td>2,579</td><td>259</td><td>34</td><td>—</td></tr><tr><td>Electric utilities&#x27; plant in service</td><td>94,868</td><td>33,135</td><td>41,332</td><td>5,106</td><td>14,585</td><td>—</td></tr><tr><td>Southern Company Gas:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Natural gas distribution utilities transportation and distribution</td><td>15,714</td><td>—</td><td>—</td><td>—</td><td>—</td><td>15,714</td></tr><tr><td>Storage facilities</td><td>1,315</td><td>—</td><td>—</td><td>—</td><td>—</td><td>1,315</td></tr><tr><td>Other</td><td>1,851</td><td>—</td><td>—</td><td>—</td><td>—</td><td>1,851</td></tr><tr><td>Southern Company Gas plant in service</td><td>18,880</td><td>—</td><td>—</td><td>—</td><td>—</td><td>18,880</td></tr><tr><td>Other plant in service</td><td>1,844</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total plant in service</td><td>$115,592</td><td>$33,135</td><td>$41,332</td><td>$5,106</td><td>$14,585</td><td>$18,880</td></tr></table>

<table><tr><td>At December 31, 2020:</td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>Electric utilities:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Generation</td><td>$ 52,179</td><td>$16,201</td><td>$18,675</td><td>$2,819</td><td>$13,872</td><td>$ —</td></tr><tr><td>Transmission</td><td>12,879</td><td>5,033</td><td>6,951</td><td>856</td><td>—</td><td>—</td></tr><tr><td>Distribution</td><td>20,958</td><td>8,248</td><td>11,622</td><td>1,088</td><td>—</td><td>—</td></tr><tr><td>General/other</td><td>5,072</td><td>2,334</td><td>2,434</td><td>248</td><td>32</td><td>—</td></tr><tr><td>Electric utilities&#x27; plant in service</td><td>91,088</td><td>31,816</td><td>39,682</td><td>5,011</td><td>13,904</td><td>—</td></tr><tr><td>Southern Company Gas:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Natural gas distribution utilities transportation and distribution</td><td>14,610</td><td>—</td><td>—</td><td>—</td><td>—</td><td>14,610</td></tr><tr><td>Storage facilities</td><td>1,752</td><td>—</td><td>—</td><td>—</td><td>—</td><td>1,752</td></tr><tr><td>Other</td><td>1,249</td><td>—</td><td>—</td><td>—</td><td>—</td><td>1,249</td></tr><tr><td>Southern Company Gas plant in service</td><td>17,611</td><td>—</td><td>—</td><td>—</td><td>—</td><td>17,611</td></tr><tr><td>Other plant in service</td><td>1,817</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total plant in service</td><td>$110,516</td><td>$31,816</td><td>$39,682</td><td>$5,011</td><td>$13,904</td><td>$17,611</td></tr></table>

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.



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:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>Deferred cloud implementation costs:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>At December 31, 2021</td><td>$240</td><td>$54</td><td>$81</td><td>$11</td><td>$14</td><td>$35</td></tr><tr><td>At December 31, 2020</td><td>162</td><td>38</td><td>58</td><td>7</td><td>9</td><td>17</td></tr></table>

## 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:

<table><tr><td></td><td>2021</td><td>2020</td><td>2019</td></tr><tr><td>Alabama Power</td><td>2.7%</td><td>2.6%</td><td>3.1%</td></tr><tr><td>Georgia Power</td><td>3.3%</td><td>3.0%</td><td>2.6%</td></tr><tr><td>Mississippi Power</td><td>3.6%</td><td>3.7%</td><td>3.7%</td></tr><tr><td>Southern Company Gas</td><td>2.8%</td><td>2.8%</td><td>2.9%</td></tr></table>

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.



## 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:

<table><tr><td>Southern Power Generating Facility</td><td>Useful life</td></tr><tr><td>Natural gas</td><td>Up to 50 years</td></tr><tr><td>Solar</td><td>Up to 35 years</td></tr><tr><td>Wind</td><td>Up to 30 years</td></tr></table>

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.

## 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:

<table><tr><td>Facility (Type)</td><td>Percent Ownership</td><td>Plant in Service</td><td>Accumulated Depreciation</td><td>CWIP</td></tr><tr><td>Alabama Power</td><td></td><td></td><td>(in millions)</td><td></td></tr><tr><td>Greene County (natural gas) Units 1 and 2</td><td>60.0% (a)</td><td>$ 191</td><td>$ 79</td><td>$ 1</td></tr><tr><td>Plant Miller (coal) Units 1 and 2</td><td>91.8 (b)</td><td>2,133</td><td>665</td><td>15</td></tr><tr><td>Georgia Power</td><td></td><td></td><td></td><td></td></tr><tr><td>Plant Hatch (nuclear)</td><td>50.1% (c)</td><td>$1,382</td><td>$ 647</td><td>$42</td></tr><tr><td>Plant Vogtle (nuclear) Units 1 and 2</td><td>45.7 (c)</td><td>3,611</td><td>2,265</td><td>86</td></tr><tr><td>Plant Scherer (coal) Units 1 and 2</td><td>8.4 (c)</td><td>276</td><td>100</td><td>1</td></tr><tr><td>Plant Scherer (coal) Unit 3</td><td>75.0 (c)</td><td>1,314</td><td>539</td><td>8</td></tr><tr><td>Plant Wansley (coal)</td><td>53.5 (c)</td><td>1,070</td><td>472</td><td>7</td></tr><tr><td>Rocky Mountain (pumped storage)</td><td>25.4 (d)</td><td>184</td><td>148</td><td>1</td></tr><tr><td>Mississippi Power</td><td></td><td></td><td></td><td></td></tr><tr><td>Greene County (natural gas) Units 1 and 2</td><td>40.0% (a)</td><td>$ 124</td><td>$ 61</td><td>$ —</td></tr><tr><td>Plant Daniel (coal) Units 1 and 2</td><td>50.0 (e)</td><td>762</td><td>237</td><td>19</td></tr><tr><td>Southern Company Gas</td><td></td><td></td><td></td><td></td></tr><tr><td>Dalton Pipeline (natural gas pipeline)</td><td>50.0% (f)</td><td>$ 271</td><td>$ 19</td><td>$ —</td></tr></table>

(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.

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:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power \( ^{(1)} \)</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Balance at December 31, 2019</td><td>$ 9,786</td><td>$3,540</td><td>$5,784</td><td>$190</td><td>$ 89</td></tr><tr><td>Liabilities incurred</td><td>19</td><td>—</td><td>10</td><td>—</td><td>9</td></tr><tr><td>Liabilities settled</td><td>(442)</td><td>(219)</td><td>(185)</td><td>(22)</td><td>—</td></tr><tr><td>Accretion</td><td>409</td><td>152</td><td>238</td><td>8</td><td>4</td></tr><tr><td>Cash flow revisions</td><td>912</td><td>501</td><td>418</td><td>—</td><td>(7)</td></tr><tr><td>Balance at December 31, 2020</td><td>$10,684</td><td>$3,974</td><td>$6,265</td><td>$176</td><td>$ 95</td></tr><tr><td>Liabilities incurred</td><td>26</td><td>—</td><td>3</td><td>—</td><td>23</td></tr><tr><td>Liabilities settled</td><td>(456)</td><td>(202)</td><td>(210)</td><td>(24)</td><td>—</td></tr><tr><td>Accretion</td><td>407</td><td>156</td><td>236</td><td>7</td><td>5</td></tr><tr><td>Cash flow revisions</td><td>1,026</td><td>406</td><td>530</td><td>31</td><td>8</td></tr><tr><td>Balance at December 31, 2021</td><td>$11,687</td><td>$4,334</td><td>$6,824</td><td>$190</td><td>$131</td></tr></table>

(*) Included in other deferred credits and liabilities on Southern Power's consolidated balance sheets.

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.

Investment securities in the Funds for December 31, 2021 and 2020 were as follows:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td></tr><tr><td></td><td colspan="3">(in millions)</td></tr><tr><td>At December 31, 2021:</td><td></td><td></td><td></td></tr><tr><td>Equity securities</td><td>$1,358</td><td>$ 849</td><td>$ 509</td></tr><tr><td>Debt securities</td><td>986</td><td>316</td><td>670</td></tr><tr><td>Other securities</td><td>197</td><td>159</td><td>38</td></tr><tr><td>Total investment securities in the Funds</td><td>$2,541</td><td>$1,324</td><td>$1,217</td></tr><tr><td>At December 31, 2020:</td><td></td><td></td><td></td></tr><tr><td>Equity securities</td><td>$1,339</td><td>$ 842</td><td>$ 497</td></tr><tr><td>Debt securities</td><td>851</td><td>231</td><td>620</td></tr><tr><td>Other securities</td><td>111</td><td>83</td><td>28</td></tr><tr><td>Total investment securities in the Funds</td><td>$2,301</td><td>$1,156</td><td>$1,145</td></tr></table>

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.

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td></tr><tr><td></td><td colspan="3">(in millions)</td></tr><tr><td>Fair value increases</td><td></td><td></td><td></td></tr><tr><td>2021</td><td>$ 274</td><td>$ 200</td><td>$ 74</td></tr><tr><td>2020</td><td>280</td><td>142</td><td>138</td></tr><tr><td>2019</td><td>344</td><td>194</td><td>150</td></tr><tr><td>Unrealized gains (losses)</td><td></td><td></td><td></td></tr><tr><td>At December 31, 2021</td><td>$ (27)</td><td>$ (30)</td><td>$ 3</td></tr><tr><td>At December 31, 2020</td><td>220</td><td>121</td><td>99</td></tr><tr><td>At December 31, 2019</td><td>259</td><td>149</td><td>110</td></tr></table>

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.

At December 31, 2021 and 2020, the accumulated provisions for the external decommissioning trust funds were as follows:

<table><tr><td></td><td>2021</td><td>2020</td></tr><tr><td></td><td colspan="2">(in millions)</td></tr><tr><td>Alabama Power</td><td></td><td></td></tr><tr><td>Plant Farley</td><td>$1,324</td><td>$1,156</td></tr><tr><td>Georgia Power</td><td></td><td></td></tr><tr><td>Plant Hatch</td><td>$ 757</td><td>$ 716</td></tr><tr><td>Plant Vogtle Units 1 and 2</td><td>460</td><td>429</td></tr><tr><td>Total</td><td>$1,217</td><td>$1,145</td></tr></table>

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:

<table><tr><td></td><td>Plant Farley</td><td>Plant Hatch \( ^{(1)} \)</td><td>Plant Vogtle Units 1 and 2 \( ^{(1)} \)</td></tr><tr><td>Decommissioning periods:</td><td></td><td></td><td></td></tr><tr><td>Beginning year</td><td>2037</td><td>2034</td><td>2047</td></tr><tr><td>Completion year</td><td>2076</td><td>2075</td><td>2079</td></tr><tr><td></td><td colspan="3">(in millions)</td></tr><tr><td>Site study costs:</td><td></td><td></td><td></td></tr><tr><td>Radiated structures</td><td>$1,234</td><td>$ 771</td><td>$628</td></tr><tr><td>Spent fuel management</td><td>387</td><td>186</td><td>170</td></tr><tr><td>Non-radiated structures</td><td>99</td><td>61</td><td>85</td></tr><tr><td>Total site study costs</td><td>$1,720</td><td>$1,018</td><td>$883</td></tr></table>

(*) 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.

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.

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:

<table><tr><td>Investment Balance</td><td>December 31, 2021</td><td>December 31, 2020</td></tr><tr><td></td><td>(in millions)</td><td></td></tr><tr><td>SNG \( ^{(a)} \)</td><td>1,129</td><td>1,167</td></tr><tr><td>PennEast Pipeline \( ^{(b)} \)</td><td>11</td><td>91</td></tr><tr><td>Other</td><td>33</td><td>32</td></tr><tr><td>Total</td><td>1,173</td><td>1,290</td></tr></table>

(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.



## Notes to Financial Statements

<table><tr><td>Earnings (Loss) from Equity Method Investments</td><td>2021</td><td>2020</td><td>2019</td></tr><tr><td></td><td></td><td>(in millions)</td><td></td></tr><tr><td>SNG</td><td>$127</td><td>$129</td><td>$141</td></tr><tr><td>Atlantic Coast Pipeline \( ^{(a)(b)} \)</td><td>—</td><td>3</td><td>13</td></tr><tr><td>PennEast Pipeline \( ^{(a)(c)} \)</td><td>(81)</td><td>7</td><td>6</td></tr><tr><td>Other \( ^{(d)} \)</td><td>4</td><td>2</td><td>(3)</td></tr><tr><td>Total</td><td>$ 50</td><td>$141</td><td>$157</td></tr></table>

(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.



## 8. FINANCING

## Long-term Debt

Details of long-term debt at December 31, 2021 and 2020 are provided in the following table:

<table><tr><td rowspan="2"></td><td colspan="2">At December 31, 2021</td><td colspan="2">Balance Outstanding at December 31,</td></tr><tr><td>Maturity</td><td>Weighted Average Interest Rate</td><td>2021</td><td>2020</td></tr><tr><td>Southern Company</td><td></td><td></td><td></td><td>(in millions)</td></tr><tr><td>Senior notes(a)</td><td>2022-2052</td><td>3.62%</td><td>$33,120</td><td>$30,850</td></tr><tr><td>Junior subordinated notes</td><td>2024-2081</td><td>4.00%</td><td>8,918</td><td>7,295</td></tr><tr><td>FFB loans(b)</td><td>2022-2044</td><td>2.88%</td><td>4,962</td><td>4,618</td></tr><tr><td>Pollution control revenue bonds(c)</td><td>2022-2053</td><td>1.05%</td><td>2,662</td><td>2,675</td></tr><tr><td>First mortgage bonds(d)</td><td>2023-2060</td><td>3.53%</td><td>2,100</td><td>1,900</td></tr><tr><td>Medium-term notes</td><td>2022-2027</td><td>7.60%</td><td>130</td><td>160</td></tr><tr><td>Other long-term debt</td><td>2022-2026</td><td>0.79%</td><td>270</td><td>370</td></tr><tr><td>Other revenue bonds</td><td></td><td></td><td>—</td><td>320</td></tr><tr><td>Debt payable to affiliated trusts(e)</td><td></td><td></td><td>—</td><td>206</td></tr><tr><td>Finance lease obligations(f)</td><td></td><td></td><td>215</td><td>231</td></tr><tr><td>Unamortized fair value adjustment</td><td></td><td></td><td>359</td><td>393</td></tr><tr><td>Unamortized debt premium (discount), net</td><td></td><td></td><td>(216)</td><td>(201)</td></tr><tr><td>Unamortized debt issuance expenses</td><td></td><td></td><td>(243)</td><td>(237)</td></tr><tr><td>Total long-term debt</td><td></td><td></td><td>52,277</td><td>48,580</td></tr><tr><td>Less: Amount due within one year</td><td></td><td></td><td>2,157</td><td>3,507</td></tr><tr><td>Total long-term debt excluding amount due within one year</td><td></td><td></td><td>50,120</td><td>45,073</td></tr><tr><td>Alabama Power</td><td></td><td></td><td></td><td></td></tr><tr><td>Senior notes</td><td>2022-2052</td><td>3.89%</td><td>$ 8,725</td><td>$ 7,625</td></tr><tr><td>Pollution control revenue bonds(c)</td><td>2024-2038</td><td>0.55%</td><td>995</td><td>1,060</td></tr><tr><td>Other long-term debt</td><td>2026</td><td>1.24%</td><td>45</td><td>45</td></tr><tr><td>Debt payable to affiliated trusts(e)</td><td></td><td></td><td>—</td><td>206</td></tr><tr><td>Finance lease obligations(f)</td><td></td><td></td><td>4</td><td>5</td></tr><tr><td>Unamortized debt premium (discount), net</td><td></td><td></td><td>(18)</td><td>(16)</td></tr><tr><td>Unamortized debt issuance expenses</td><td></td><td></td><td>(64)</td><td>(56)</td></tr><tr><td>Total long-term debt</td><td></td><td></td><td>9,687</td><td>8,869</td></tr><tr><td>Less: Amount due within one year</td><td></td><td></td><td>751</td><td>311</td></tr><tr><td>Total long-term debt excluding amount due within one year</td><td></td><td></td><td>$ 8,936</td><td>$ 8,558</td></tr><tr><td>Georgia Power</td><td></td><td></td><td></td><td></td></tr><tr><td>Senior notes</td><td>2022-2051</td><td>3.61%</td><td>$ 6,825</td><td>$ 6,400</td></tr><tr><td>Junior subordinated notes</td><td>2077</td><td>5.00%</td><td>270</td><td>270</td></tr><tr><td>FFB loans(b)</td><td>2022-2044</td><td>2.88%</td><td>4,962</td><td>4,618</td></tr><tr><td>Pollution control revenue bonds(c)</td><td>2022-2053</td><td>1.33%</td><td>1,591</td><td>1,538</td></tr><tr><td>Other long-term debt</td><td>2022</td><td>0.70%</td><td>125</td><td>125</td></tr><tr><td>Finance lease obligations(f)</td><td></td><td></td><td>136</td><td>145</td></tr><tr><td>Unamortized debt premium (discount), net</td><td></td><td></td><td>(11)</td><td>(12)</td></tr><tr><td>Unamortized debt issuance expenses</td><td></td><td></td><td>(114)</td><td>(114)</td></tr><tr><td>Total long-term debt</td><td></td><td></td><td>13,784</td><td>12,970</td></tr><tr><td>Less: Amount due within one year</td><td></td><td></td><td>675</td><td>542</td></tr><tr><td>Total long-term debt excluding amount due within one year</td><td></td><td></td><td>13,109</td><td>12,428</td></tr></table>



<table><tr><td rowspan="2"></td><td colspan="2">At December 31, 2021</td><td colspan="2">Balance Outstanding at December 31,</td></tr><tr><td>Maturity</td><td>Weighted Average Interest Rate</td><td>2021</td><td>2020</td></tr><tr><td>Mississippi Power</td><td></td><td></td><td></td><td>(in millions)</td></tr><tr><td>Senior notes</td><td>2024-2051</td><td>3.43%</td><td>$ 1,425</td><td>$ 900</td></tr><tr><td>Pollution control revenue bonds(c)</td><td>2025-2028</td><td>1.86%</td><td>76</td><td>76</td></tr><tr><td>Other revenue bonds</td><td></td><td></td><td>—</td><td>320</td></tr><tr><td>Other long-term debt</td><td></td><td></td><td>—</td><td>100</td></tr><tr><td>Finance lease obligations(f)</td><td></td><td></td><td>18</td><td>19</td></tr><tr><td>Unamortized debt premium (discount), net</td><td></td><td></td><td>2</td><td>11</td></tr><tr><td>Unamortized debt issuance expenses</td><td></td><td></td><td>(10)</td><td>(7)</td></tr><tr><td>Total long-term debt</td><td></td><td></td><td>1,511</td><td>1,419</td></tr><tr><td>Less: Amount due within one year</td><td></td><td></td><td>1</td><td>406</td></tr><tr><td>Total long-term debt excluding amount due within one year</td><td></td><td></td><td>$ 1,510</td><td>$ 1,013</td></tr><tr><td>Southern Power</td><td></td><td></td><td></td><td></td></tr><tr><td>Senior notes(a)</td><td>2022-2046</td><td>3.74%</td><td>$ 3,711</td><td>$ 3,714</td></tr><tr><td>Unamortized debt premium (discount), net</td><td></td><td></td><td>(6)</td><td>(6)</td></tr><tr><td>Unamortized debt issuance expenses</td><td></td><td></td><td>(17)</td><td>(16)</td></tr><tr><td>Total long-term debt</td><td></td><td></td><td>3,688</td><td>3,692</td></tr><tr><td>Less: Amount due within one year</td><td></td><td></td><td>679</td><td>299</td></tr><tr><td>Total long-term debt excluding amount due within one year</td><td></td><td></td><td>$ 3,009</td><td>$ 3,393</td></tr><tr><td>Southern Company Gas</td><td></td><td></td><td></td><td></td></tr><tr><td>Senior notes</td><td>2023-2051</td><td>3.96%</td><td>$ 4,348</td><td>$ 4,200</td></tr><tr><td>First mortgage bonds(d)</td><td>2023-2060</td><td>3.53%</td><td>2,100</td><td>1,900</td></tr><tr><td>Medium-term notes</td><td>2022-2027</td><td>7.60%</td><td>130</td><td>160</td></tr><tr><td>Unamortized fair value adjustment</td><td></td><td></td><td>359</td><td>393</td></tr><tr><td>Unamortized debt premium (discount), net</td><td></td><td></td><td>(35)</td><td>(27)</td></tr><tr><td>Total long-term debt</td><td></td><td></td><td>6,902</td><td>6,626</td></tr><tr><td>Less: Amount due within one year</td><td></td><td></td><td>47</td><td>333</td></tr><tr><td>Total long-term debt excluding amount due within one year</td><td></td><td></td><td>$ 6,855</td><td>$ 6,293</td></tr></table>

(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.

(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.



## Notes to Financial Statements

Maturities of long-term debt for the next five years are as follows:

<table><tr><td></td><td>Southern Company \( ^{(a)} \)</td><td>Alabama Power</td><td>Georgia Power \( ^{(b)} \)</td><td>Mississippi Power</td><td>Southern Power \( ^{(c)} \)</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>2022</td><td>2,157</td><td>751</td><td>676</td><td>1</td><td>677</td><td>46</td></tr><tr><td>2023</td><td>3,738</td><td>301</td><td>897</td><td>1</td><td>290</td><td>400</td></tr><tr><td>2024</td><td>2,280</td><td>22</td><td>498</td><td>201</td><td>—</td><td>—</td></tr><tr><td>2025</td><td>1,199</td><td>250</td><td>145</td><td>11</td><td>500</td><td>300</td></tr><tr><td>2026</td><td>3,723</td><td>45</td><td>441</td><td>1</td><td>964</td><td>530</td></tr></table>

(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 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 4 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 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:

<table><tr><td rowspan="2">Company</td><td colspan="4">Expires</td><td rowspan="2">Total</td><td rowspan="2">Unused</td><td rowspan="2">Due within One Year</td></tr><tr><td>2022</td><td>2023</td><td>2024</td><td>2026</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>Southern Company parent</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$2,000</td><td>$2,000</td><td>$1,998</td><td>$ —</td></tr><tr><td>Alabama Power</td><td>—</td><td>—</td><td>550</td><td>700</td><td>1,250</td><td>1,250</td><td>—</td></tr><tr><td>Georgia Power</td><td>—</td><td>—</td><td>—</td><td>1,750</td><td>1,750</td><td>1,726</td><td>—</td></tr><tr><td>Mississippi Power</td><td>—</td><td>125</td><td>150</td><td>—</td><td>275</td><td>275</td><td>—</td></tr><tr><td>Southern Power \( ^{(a)} \)</td><td>—</td><td>—</td><td>—</td><td>600</td><td>600</td><td>568</td><td>—</td></tr><tr><td>Southern Company Gas \( ^{(b)} \)</td><td>250</td><td>—</td><td>—</td><td>1,500</td><td>1,750</td><td>1,747</td><td>250</td></tr><tr><td>SEGCO</td><td>30</td><td>—</td><td>—</td><td>—</td><td>30</td><td>30</td><td>30</td></tr><tr><td>Southern Company</td><td>$280</td><td>$125</td><td>$700</td><td>$6,550</td><td>$7,655</td><td>$7,594</td><td>$280</td></tr></table>

(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 Nicro Gas is the borrower and which is restricted for working capital needs of Nicro Gas. Pursuant to the multi-year credit arrangement expiring in 2026, the allocations between Southern Company Gas Capital and Nicro 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  \( \frac{1}{4} \)  of 1% for the Registrants and Nicro 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, Nicro 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 Nicro 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, Nicro Gas, and SEGCO were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicro 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, Nicro 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 Nicro Gas. Nicro Gas' commercial paper program supports working capital needs at Nicro Gas as Nicro 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:

<table><tr><td rowspan="2"></td><td colspan="2">Notes Payable at December 31, 2021</td><td colspan="2">Notes Payable at December 31, 2020</td></tr><tr><td>Amount Outstanding</td><td>Weighted Average Interest Rate</td><td>Amount Outstanding</td><td>Weighted Average Interest Rate</td></tr><tr><td></td><td>(in millions)</td><td></td><td>(in millions)</td><td></td></tr><tr><td>Southern Company</td><td></td><td></td><td></td><td></td></tr><tr><td>Commercial paper</td><td>$1,140</td><td>0.3%</td><td>$609</td><td>0.3%</td></tr><tr><td>Short-term bank debt</td><td>300</td><td>0.7%</td><td>—</td><td>—%</td></tr><tr><td>Total</td><td>$1,440</td><td>0.4%</td><td>$609</td><td>0.3%</td></tr><tr><td>Georgia Power</td><td></td><td></td><td></td><td></td></tr><tr><td>Commercial paper</td><td>$ —</td><td>—%</td><td>$ 60</td><td>0.3%</td></tr><tr><td>Mississippi Power</td><td></td><td></td><td></td><td></td></tr><tr><td>Commercial paper</td><td>$ —</td><td>—%</td><td>$ 25</td><td>0.4%</td></tr><tr><td>Southern Power</td><td></td><td></td><td></td><td></td></tr><tr><td>Commercial paper</td><td>$ 211</td><td>0.3%</td><td>$175</td><td>0.3%</td></tr><tr><td>Southern Company Gas</td><td></td><td></td><td></td><td></td></tr><tr><td>Commercial paper:</td><td></td><td></td><td></td><td></td></tr><tr><td>Southern Company Gas Capital</td><td>$ 379</td><td>0.3%</td><td>$220</td><td>0.3%</td></tr><tr><td>Nicro Gas</td><td>530</td><td>0.3%</td><td>104</td><td>0.2%</td></tr><tr><td>Short-term bank debt:</td><td></td><td></td><td></td><td></td></tr><tr><td>Nicro Gas</td><td>300</td><td>0.7%</td><td>—</td><td>—%</td></tr><tr><td>Total</td><td>$1,209</td><td>0.4%</td><td>$324</td><td>0.2%</td></tr></table>

See “Bank Credit Arrangements” herein for information on bank term loan covenants that limit debt levels and cross-acceleration or cross-default provisions.

## 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:

<table><tr><td rowspan="2"></td><td colspan="3">Average Common Stock Shares</td></tr><tr><td>2021</td><td>2020</td><td>2019</td></tr><tr><td></td><td colspan="3">(in millions)</td></tr><tr><td>As reported shares</td><td>1,061</td><td>1,058</td><td>1,046</td></tr><tr><td>Effect of stock-based compensation</td><td>7</td><td>7</td><td>8</td></tr><tr><td>Diluted shares</td><td>1,068</td><td>1,065</td><td>1,054</td></tr></table>

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.

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:

<table><tr><td>Preferred Stock</td><td>Par Value/Stated Capital Per Share</td><td>Shares Outstanding</td><td>Redemption Price Per Share</td></tr><tr><td>4.92% Preferred Stock</td><td>$100</td><td>80,000</td><td>$103.23</td></tr><tr><td>4.72% Preferred Stock</td><td>$100</td><td>50,000</td><td>$102.18</td></tr><tr><td>4.64% Preferred Stock</td><td>$100</td><td>60,000</td><td>$103.14</td></tr><tr><td>4.60% Preferred Stock</td><td>$100</td><td>100,000</td><td>$104.20</td></tr><tr><td>4.52% Preferred Stock</td><td>$100</td><td>50,000</td><td>$102.93</td></tr><tr><td>4.20% Preferred Stock</td><td>$100</td><td>135,115</td><td>$105.00</td></tr><tr><td>5.00% Class A Preferred Stock</td><td>$ 25</td><td>10,000,000</td><td>$ 25.00 \( ^{(1)} \)</td></tr></table>

 \( ^{*} \)  \( ^{*} $  25.50 if prior to October 1, 2022



## Georgia Power

Georgia Power has preferred stock, Class A preferred stock, preference stock, and common stock authorized, but only common stock outstanding.

## Mississippi Power

Mississippi Power has preferred stock and common stock authorized, but only common stock outstanding.

## Dividend Restrictions

The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2021, consolidated retained earnings included $4.4 billion of undistributed retained earnings of the subsidiaries.

The traditional electric operating companies and Southern Power can only pay dividends to Southern Company out of retained earnings or paid-in-capital.

See Note 7 under “Southern Power” for information regarding the distribution requirements for certain Southern Power subsidiaries.

By regulation, Nior Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At December 31, 2021, the amount of Southern Company Gas’ subsidiary retained earnings restricted for dividend payment totaled $1.3 billion.

## Structural Considerations

Since Southern Company and Southern Company Gas are holding companies, the right of Southern Company and Southern Company Gas and, hence, the right of creditors of Southern Company or Southern Company Gas to participate in any distribution of the assets of any respective subsidiary of Southern Company or Southern Company Gas, whether upon liquidation, reorganization or otherwise, is subject to prior claims of creditors and preferred stockholders of such subsidiary.

Southern Company Gas' 100%-owned subsidiary, Southern Company Gas Capital, was established to provide for certain of Southern Company Gas' ongoing financing needs through a commercial paper program, the issuance of various debt, hybrid securities, and other financing arrangements. Southern Company Gas fully and unconditionally guarantees all debt issued by Southern Company Gas Capital. Nior 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.

## 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:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>At December 31, 2021</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Electric generating units</td><td>$ 802</td><td>$104</td><td>$1,217</td><td>$ —</td><td>$ —</td><td>$ —</td></tr><tr><td>Real estate/land</td><td>876</td><td>3</td><td>49</td><td>2</td><td>526</td><td>45</td></tr><tr><td>Communication towers</td><td>156</td><td>2</td><td>4</td><td>—</td><td>—</td><td>24</td></tr><tr><td>Railcars</td><td>32</td><td>10</td><td>20</td><td>2</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>103</td><td>5</td><td>1</td><td>24</td><td>—</td><td>1</td></tr><tr><td>Total</td><td>$1,969</td><td>$124</td><td>$1,291</td><td>$28</td><td>$526</td><td>$70</td></tr><tr><td>At December 31, 2020</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Electric generating units</td><td>$ 941</td><td>$146</td><td>$1,368</td><td>$ —</td><td>$ —</td><td>$ —</td></tr><tr><td>Real estate/land</td><td>815</td><td>4</td><td>53</td><td>2</td><td>451</td><td>61</td></tr><tr><td>Communication towers</td><td>158</td><td>2</td><td>3</td><td>—</td><td>—</td><td>20</td></tr><tr><td>Railcars</td><td>42</td><td>16</td><td>23</td><td>3</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>127</td><td>7</td><td>5</td><td>23</td><td>—</td><td>1</td></tr><tr><td>Total</td><td>$2,083</td><td>$175</td><td>$1,452</td><td>$28</td><td>$451</td><td>$82</td></tr></table>

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.

## 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.



Balance sheet amounts recorded for operating and finance leases are as follows:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>At December 31, 2021</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating Leases</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating lease ROU assets, net</td><td>$1,701</td><td>$108</td><td>$1,157</td><td>$10</td><td>$479</td><td>$70</td></tr><tr><td>Operating lease obligations - current</td><td>$ 250</td><td>$ 54</td><td>$ 156</td><td>$ 4</td><td>$ 28</td><td>$11</td></tr><tr><td>Operating lease obligations - non-current</td><td>1,503</td><td>66</td><td>999</td><td>6</td><td>497</td><td>59</td></tr><tr><td>Total operating lease obligations \( ^{(1)} \)</td><td>$1,754</td><td>$121</td><td>$1,155</td><td>$10</td><td>$525</td><td>$70</td></tr><tr><td>Finance Leases</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Finance lease ROU assets, net</td><td>$ 197</td><td>$ 4</td><td>$ 104</td><td>$17</td><td>$ —</td><td>$ —</td></tr><tr><td>Finance lease obligations - current</td><td>$ 16</td><td>$ 1</td><td>$ 10</td><td>$ 1</td><td>$ —</td><td>$ —</td></tr><tr><td>Finance lease obligations - non-current</td><td>199</td><td>3</td><td>126</td><td>17</td><td>—</td><td>—</td></tr><tr><td>Total finance lease obligations</td><td>$ 215</td><td>$ 4</td><td>$ 136</td><td>$18</td><td>$ —</td><td>$ —</td></tr><tr><td>At December 31, 2020</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating Leases</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating lease ROU assets, net</td><td>$1,802</td><td>$151</td><td>$1,308</td><td>$ 9</td><td>$415</td><td>$81</td></tr><tr><td>Operating lease obligations - current</td><td>$ 241</td><td>$ 51</td><td>$ 151</td><td>$ 2</td><td>$ 25</td><td>$15</td></tr><tr><td>Operating lease obligations - non-current</td><td>1,611</td><td>119</td><td>1,156</td><td>7</td><td>426</td><td>67</td></tr><tr><td>Total operating lease obligations \( ^{(1)} \)</td><td>$1,852</td><td>$170</td><td>$1,307</td><td>$ 9</td><td>$451</td><td>$82</td></tr><tr><td>Finance Leases</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Finance lease ROU assets, net</td><td>$ 218</td><td>$ 5</td><td>$ 115</td><td>$19</td><td>$ —</td><td>$ —</td></tr><tr><td>Finance lease obligations - current</td><td>$ 17</td><td>$ 1</td><td>$ 9</td><td>$ 1</td><td>$ —</td><td>$ —</td></tr><tr><td>Finance lease obligations - non-current</td><td>214</td><td>4</td><td>136</td><td>18</td><td>—</td><td>—</td></tr><tr><td>Total finance lease obligations</td><td>$ 231</td><td>$ 5</td><td>$ 145</td><td>$19</td><td>$ —</td><td>$ —</td></tr></table>

(*) 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.



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:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>2021</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Lease cost</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating lease cost \( ^{(r)} \)</td><td>313</td><td>58</td><td>208</td><td>2</td><td>33</td><td>19</td></tr><tr><td>Finance lease cost:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Amortization of ROU assets</td><td>21</td><td>1</td><td>11</td><td>1</td><td>—</td><td>—</td></tr><tr><td>Interest on lease obligations</td><td>11</td><td>—</td><td>16</td><td>1</td><td>—</td><td>—</td></tr><tr><td>Total finance lease cost</td><td>32</td><td>1</td><td>27</td><td>2</td><td>—</td><td>—</td></tr><tr><td>Short-term lease costs</td><td>48</td><td>15</td><td>24</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Variable lease cost</td><td>96</td><td>4</td><td>83</td><td>—</td><td>5</td><td>—</td></tr><tr><td>Sublease income</td><td>1</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total lease cost</td><td>490</td><td>78</td><td>342</td><td>4</td><td>38</td><td>19</td></tr><tr><td>2020</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Lease cost</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating lease cost \( ^{(r)} \)</td><td>309</td><td>55</td><td>212</td><td>3</td><td>29</td><td>19</td></tr><tr><td>Finance lease cost:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Amortization of ROU assets</td><td>26</td><td>1</td><td>15</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Interest on lease obligations</td><td>11</td><td>—</td><td>16</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total finance lease cost</td><td>37</td><td>1</td><td>31</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Short-term lease costs</td><td>39</td><td>11</td><td>26</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Variable lease cost</td><td>91</td><td>4</td><td>76</td><td>—</td><td>7</td><td>—</td></tr><tr><td>Sublease income</td><td>—</td><td>(1)</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total lease cost</td><td>476</td><td>70</td><td>345</td><td>3</td><td>36</td><td>19</td></tr><tr><td>2019</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Lease cost</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating lease cost \( ^{(r)} \)</td><td>310</td><td>54</td><td>206</td><td>3</td><td>28</td><td>18</td></tr><tr><td>Finance lease cost:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Amortization of ROU assets</td><td>28</td><td>1</td><td>15</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Interest on lease obligations</td><td>12</td><td>—</td><td>18</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total finance lease cost</td><td>40</td><td>1</td><td>33</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Short-term lease costs</td><td>48</td><td>19</td><td>22</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Variable lease cost</td><td>105</td><td>6</td><td>85</td><td>—</td><td>7</td><td>—</td></tr><tr><td>Sublease income</td><td>—</td><td>(1)</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total lease cost</td><td>503</td><td>79</td><td>346</td><td>3</td><td>35</td><td>18</td></tr></table>

(*) 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.

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:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>2021</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other information</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash paid for amounts included in the measurements of lease obligations:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating cash flows from operating leases</td><td>$308</td><td>$58</td><td>$211</td><td>$2</td><td>$28</td><td>$19</td></tr><tr><td>Operating cash flows from finance leases</td><td>9</td><td>—</td><td>17</td><td>1</td><td>—</td><td>—</td></tr><tr><td>Financing cash flows from finance leases</td><td>17</td><td>1</td><td>9</td><td>1</td><td>—</td><td>—</td></tr><tr><td>ROU assets obtained in exchange for new operating lease obligations</td><td>64</td><td>3</td><td>9</td><td>—</td><td>72</td><td>7</td></tr><tr><td>ROU assets obtained in exchange for new finance lease obligations</td><td>3</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>2020</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other information</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash paid for amounts included in the measurements of lease obligations:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating cash flows from operating leases</td><td>$310</td><td>$55</td><td>$215</td><td>$3</td><td>$28</td><td>$18</td></tr><tr><td>Operating cash flows from finance leases</td><td>9</td><td>—</td><td>18</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Financing cash flows from finance leases</td><td>22</td><td>1</td><td>11</td><td>—</td><td>—</td><td>—</td></tr><tr><td>ROU assets obtained in exchange for new operating lease obligations</td><td>227</td><td>63</td><td>32</td><td>—</td><td>51</td><td>4</td></tr><tr><td>ROU assets obtained in exchange for new finance lease obligations</td><td>10</td><td>2</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>2019</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other information</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash paid for amounts included in the measurements of lease obligations:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating cash flows from operating leases</td><td>$323</td><td>$54</td><td>$210</td><td>$3</td><td>27</td><td>18</td></tr><tr><td>Operating cash flows from finance leases</td><td>10</td><td>—</td><td>19</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Financing cash flows from finance leases</td><td>32</td><td>1</td><td>13</td><td>—</td><td>—</td><td>—</td></tr><tr><td>ROU assets obtained in exchange for new operating lease obligations</td><td>118</td><td>7</td><td>21</td><td>—</td><td>2</td><td>19</td></tr><tr><td>ROU assets obtained in exchange for new finance lease obligations</td><td>35</td><td>2</td><td>24</td><td>—</td><td>—</td><td>—</td></tr></table>



<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td>At December 31, 2021</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Weighted-average remaining lease term in years:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating leases</td><td>15.9</td><td>9.1</td><td>8.7</td><td>6.1</td><td>32.8</td><td>10.5</td></tr><tr><td>Finance leases</td><td>18.0</td><td>8.7</td><td>8.5</td><td>13.9</td><td>N/A</td><td>N/A</td></tr><tr><td>Weighted-average discount rate:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating leases</td><td>4.41%</td><td>4.37%</td><td>4.45%</td><td>2.74%</td><td>5.20%</td><td>3.61%</td></tr><tr><td>Finance leases</td><td>4.82%</td><td>3.09%</td><td>10.81%</td><td>2.74%</td><td>N/A</td><td>N/A</td></tr><tr><td>At December 31, 2020</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Weighted-average remaining lease term in years:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating leases</td><td>14.5</td><td>7.8</td><td>9.4</td><td>6.5</td><td>32.1</td><td>9.8</td></tr><tr><td>Finance leases</td><td>18.2</td><td>9.7</td><td>9.5</td><td>14.9</td><td>N/A</td><td>N/A</td></tr><tr><td>Weighted-average discount rate:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating leases</td><td>4.44%</td><td>4.14%</td><td>4.37%</td><td>3.26%</td><td>5.45%</td><td>3.67%</td></tr><tr><td>Finance leases</td><td>4.79%</td><td>3.20%</td><td>10.81%</td><td>2.74</td><td>N/A</td><td>N/A</td></tr></table>

Maturities of lease liabilities are as follows:

<table><tr><td rowspan="2"></td><td colspan="7">At December 31, 2021</td></tr><tr><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td><td></td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>Maturity Analysis</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating leases:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2022</td><td>$ 307</td><td>$ 59</td><td>$ 205</td><td>$ 4</td><td>$ 37</td><td>$ 14</td><td></td></tr><tr><td>2023</td><td>238</td><td>9</td><td>201</td><td>2</td><td>29</td><td>11</td><td></td></tr><tr><td>2024</td><td>195</td><td>7</td><td>164</td><td>1</td><td>29</td><td>11</td><td></td></tr><tr><td>2025</td><td>174</td><td>6</td><td>136</td><td>1</td><td>29</td><td>11</td><td></td></tr><tr><td>2026</td><td>154</td><td>5</td><td>133</td><td>1</td><td>30</td><td>8</td><td></td></tr><tr><td>Thereafter</td><td>1,575</td><td>69</td><td>566</td><td>2</td><td>995</td><td>31</td><td></td></tr><tr><td>Total</td><td>2,643</td><td>155</td><td>1,405</td><td>11</td><td>1,149</td><td>86</td><td></td></tr><tr><td>Less: Present value discount</td><td>889</td><td>34</td><td>250</td><td>1</td><td>624</td><td>16</td><td></td></tr><tr><td>Operating lease obligations</td><td>$1,754</td><td>$121</td><td>$1,155</td><td>$10</td><td>$ 525</td><td>$ 70</td><td></td></tr><tr><td>Finance leases:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2022</td><td>$ 25</td><td>$ 2</td><td>$ 25</td><td>$ 2</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>2023</td><td>22</td><td>1</td><td>25</td><td>2</td><td>—</td><td>—</td><td></td></tr><tr><td>2024</td><td>19</td><td>1</td><td>25</td><td>2</td><td>—</td><td>—</td><td></td></tr><td>2025</td><td>16</td><td>—</td><td>25</td><td>2</td><td>—</td><td>—</td><td></td><tr><td>2026</td><td>16</td><td>—</td><td>26</td><td>1</td><td>—</td><td>—</td><td></td></tr><tr><td>Thereafter</td><td>231</td><td>—</td><td>83</td><td>13</td><td>—</td><td>—</td><td></td></tr><tr><td>Total</td><td>329</td><td>4</td><td>209</td><td>22</td><td>—</td><td>—</td><td></td></tr><tr><td>Less: Present value discount</td><td>114</td><td>—</td><td>73</td><td>4</td><td>—</td><td>—</td><td></td></tr><tr><td>Finance lease obligations</td><td>$ 215</td><td>$ 4</td><td>$ 136</td><td>$18</td><td>$ —</td><td>$ —</td><td></td></tr></table>

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.

Lease income for 2021, 2020, and 2019, is as follows:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>2021</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Lease income - interest income on sales-type leases</td><td>$ 15</td><td>$ —</td><td>$ —</td><td>$14</td><td>$ 1</td><td>$ —</td></tr><tr><td>Lease income - operating leases</td><td>223</td><td>82</td><td>42</td><td>2</td><td>85</td><td>35</td></tr><tr><td>Variable lease income</td><td>429</td><td>—</td><td>—</td><td>—</td><td>456</td><td>—</td></tr><tr><td>Total lease income</td><td>$667</td><td>$82</td><td>$42</td><td>$16</td><td>$542</td><td>$35</td></tr><tr><td>2020</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Lease income - interest income on sales-type leases</td><td>$ 16</td><td>$ —</td><td>$ —</td><td>$12</td><td>$ —</td><td>$ —</td></tr><tr><td>Lease income - operating leases</td><td>208</td><td>45</td><td>58</td><td>2</td><td>87</td><td>35</td></tr><tr><td>Variable lease income</td><td>419</td><td>—</td><td>—</td><td>—</td><td>449</td><td>—</td></tr><tr><td>Total lease income</td><td>$643</td><td>$45</td><td>$58</td><td>$14</td><td>$536</td><td>$35</td></tr><tr><td>2019</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Lease income - interest income on sales-type leases</td><td>$ 9</td><td>$ —</td><td>$ —</td><td>$ 9</td><td>$ —</td><td>$ —</td></tr><tr><td>Lease income - operating leases</td><td>273</td><td>24</td><td>71</td><td>—</td><td>160</td><td>35</td></tr><tr><td>Variable lease income</td><td>403</td><td>—</td><td>—</td><td>—</td><td>434</td><td>—</td></tr><tr><td>Total lease income</td><td>$685</td><td>$24</td><td>$71</td><td>$ 9</td><td>$594</td><td>$35</td></tr></table>

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.

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 Tranquility 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:

<table><tr><td rowspan="2"></td><td colspan="3">At December 31, 2021</td></tr><tr><td>Southern Company</td><td>Mississippi Power</td><td>Southern Power</td></tr><tr><td></td><td colspan="3">(in millions)</td></tr><tr><td>2022</td><td>$ 37</td><td>$ 25</td><td>$ 12</td></tr><tr><td>2023</td><td>39</td><td>24</td><td>15</td></tr><tr><td>2024</td><td>38</td><td>23</td><td>15</td></tr><tr><td>2025</td><td>37</td><td>22</td><td>15</td></tr><tr><td>2026</td><td>36</td><td>21</td><td>15</td></tr><tr><td>Thereafter</td><td>390</td><td>183</td><td>207</td></tr><tr><td>Total undiscounted cash flows</td><td>$577</td><td>$298</td><td>$279</td></tr><tr><td>Net investment in sales-type lease \( ^{(1)} \)</td><td>340</td><td>167</td><td>173</td></tr><tr><td>Difference between undiscounted cash flows and discounted cash flows</td><td>$237</td><td>$131</td><td>$106</td></tr></table>

(*) 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:

<table><tr><td rowspan="3"></td><td colspan="6">At December 31, 2021</td></tr><tr><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Southern Power</td><td>Southern Company Gas</td><td></td></tr><tr><td></td><td></td><td></td><td colspan="3">(in millions)</td></tr><tr><td>2022</td><td>$ 188</td><td>$ 76</td><td>$ 8</td><td>$ 87</td><td>$ 35</td><td></td></tr><tr><td>2023</td><td>139</td><td>32</td><td>2</td><td>88</td><td>35</td><td></td></tr><tr><td>2024</td><td>107</td><td>5</td><td>—</td><td>90</td><td>33</td><td></td></tr><tr><td>2025</td><td>100</td><td>3</td><td>—</td><td>74</td><td>28</td><td></td></tr><tr><td>2026</td><td>99</td><td>3</td><td>—</td><td>73</td><td>28</td><td></td></tr><tr><td>Thereafter</td><td>883</td><td>23</td><td>—</td><td>240</td><td>407</td><td></td></tr><tr><td>Total</td><td>$1,516</td><td>$142</td><td>$10</td><td>$652</td><td>$566</td><td></td></tr></table>

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.

## 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:

<table><tr><td></td><td>December 31, 2020 \( ^{(1)} \)  (in millions)</td></tr><tr><td>Net rentals receivable</td><td>$ 734</td></tr><tr><td>Unearned income</td><td>(178)</td></tr><tr><td>Investment in leveraged leases</td><td>556</td></tr><tr><td>Deferred taxes from leveraged leases</td><td>(7)</td></tr><tr><td>Net investment in leveraged leases</td><td>$ 549</td></tr></table>

(*) 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.”

<table><tr><td></td><td>2021</td><td>2020</td><td>2019</td></tr><tr><td></td><td colspan="3">(in millions)</td></tr><tr><td>Pretax leveraged lease income (loss)</td><td>$17</td><td>$(180)</td><td>$11</td></tr><tr><td>Income tax benefit (expense)</td><td>(5)</td><td>98</td><td>—</td></tr><tr><td>Net leveraged lease income (loss)</td><td>$12</td><td>$ (82)</td><td>$11</td></tr></table>

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 of, the generation assets, in effect terminating the lease. As the remaining amount of the lease investment was charged against earnings in the second quarter 2020, termination would not be expected to result in additional charges. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments and meet its obligations associated with a future closure or retirement of the generation assets and associated properties, including the dry ash landfill.



## 10. INCOME TAXES

Southern Company files a consolidated federal income tax return and the Registrants file various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis, and each subsidiary is allocated an amount of tax similar to that which would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.

## Current and Deferred Income Taxes

Details of income tax provisions are as follows:

<table><tr><td rowspan="2"></td><td colspan="6">2021</td></tr><tr><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Federal —</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current</td><td>$ 50</td><td>$104</td><td>$ 311</td><td>$ 25</td><td>$ (340)</td><td>$ 85</td></tr><tr><td>Deferred</td><td>36</td><td>172</td><td>(449)</td><td>(15)</td><td>343</td><td>35</td></tr><tr><td></td><td>86</td><td>276</td><td>(138)</td><td>10</td><td>3</td><td>120</td></tr><tr><td>State —</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current</td><td>(25)</td><td>23</td><td>71</td><td>—</td><td>(16)</td><td>(68)</td></tr><tr><td>Deferred</td><td>206</td><td>73</td><td>(101)</td><td>11</td><td>—</td><td>223</td></tr><tr><td></td><td>181</td><td>96</td><td>(30)</td><td>11</td><td>(16)</td><td>155</td></tr><tr><td>Total</td><td>$ 267</td><td>$372</td><td>$ (168)</td><td>$ 21</td><td>$ (13)</td><td>$275</td></tr></table>

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Federal —</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current</td><td>$ 199</td><td>$198</td><td>$ 365</td><td>$ 18</td><td>$ (303)</td><td>$ 82</td></tr><tr><td>Deferred</td><td>70</td><td>44</td><td>(224)</td><td>(14)</td><td>299</td><td>53</td></tr><tr><td></td><td>269</td><td>242</td><td>141</td><td>4</td><td>(4)</td><td>135</td></tr><tr><td>State —</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current</td><td>100</td><td>61</td><td>60</td><td>—</td><td>(4)</td><td>35</td></tr><tr><td>Deferred</td><td>24</td><td>34</td><td>(49)</td><td>10</td><td>11</td><td>3</td></tr><tr><td></td><td>124</td><td>95</td><td>11</td><td>10</td><td>7</td><td>38</td></tr><tr><td>Total</td><td>$ 393</td><td>$337</td><td>$ 152</td><td>$ 14</td><td>$ 3</td><td>$ 173</td></tr></table>

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Federal —</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current</td><td>$ 156</td><td>$ 61</td><td>$ 264</td><td>$ (6)</td><td>$ (717)</td><td>$ (120)</td></tr><tr><td>Deferred</td><td>1,237</td><td>125</td><td>180</td><td>26</td><td>647</td><td>195</td></tr><tr><td></td><td>1,393</td><td>186</td><td>444</td><td>20</td><td>(70)</td><td>75</td></tr><tr><td>State —</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current</td><td>275</td><td>12</td><td>6</td><td>(1)</td><td>1</td><td>37</td></tr><tr><td>Deferred</td><td>130</td><td>72</td><td>22</td><td>11</td><td>13</td><td>18</td></tr><tr><td></td><td>405</td><td>84</td><td>28</td><td>10</td><td>14</td><td>55</td></tr><tr><td>Total</td><td>$ 1,798</td><td>$270</td><td>$ 472</td><td>$30</td><td>$ (56)</td><td>$ 130</td></tr></table>

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 Nicro 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:

<table><tr><td></td><td>Southern Company</td><td>Southern Power</td></tr><tr><td></td><td colspan="2">(in millions)</td></tr><tr><td>2021</td><td>$ 84</td><td>$ 58</td></tr><tr><td>2020</td><td>84</td><td>59</td></tr><tr><td>2019</td><td>181</td><td>151</td></tr></table>

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.

A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:

<table><tr><td rowspan="2"></td><td colspan="6">2021</td></tr><tr><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td>Federal statutory rate</td><td>21.0%</td><td>21.0%</td><td>21.0%</td><td>21.0%</td><td></td><td>21.0%</td></tr><tr><td>State income tax, net of federal deduction</td><td>5.5</td><td>4.6</td><td>(5.7)</td><td>4.9</td><td></td><td>(8.0)</td></tr><tr><td>Employee stock plans&#x27; dividend deduction</td><td>(0.9)</td><td>—</td><td>—</td><td>—</td><td></td><td>—</td></tr><tr><td>Non-deductible book depreciation</td><td>0.9</td><td>0.5</td><td>3.1</td><td>0.4</td><td></td><td>—</td></tr><tr><td>Flowback of excess deferred income taxes</td><td>(11.7)</td><td>(2.6)</td><td>(49.9)</td><td>(15.2)</td><td></td><td>—</td></tr><tr><td>AFUDC-Equity</td><td>(1.5)</td><td>(0.7)</td><td>(6.4)</td><td>—</td><td></td><td>—</td></tr><tr><td>Federal PTCs</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td>(4.6)</td></tr><tr><td>Amortization of ITC</td><td>(2.2)</td><td>(0.1)</td><td>(0.4)</td><td>—</td><td></td><td>(29.7)</td></tr><tr><td>Noncontrolling interests</td><td>0.8</td><td>—</td><td>—</td><td>—</td><td></td><td>13.4</td></tr><tr><td>Leveraged lease impairments and dispositions</td><td>(1.4)</td><td>—</td><td>—</td><td>—</td><td></td><td>—</td></tr><tr><td>Other</td><td>(0.1)</td><td>0.2</td><td>(1.9)</td><td>0.6</td><td></td><td>(0.4)</td></tr><tr><td>Effective income tax (benefit) rate</td><td>10.4%</td><td>22.9%</td><td>(40.2)%</td><td>11.7%</td><td></td><td>(8.3)%</td></tr></table>



<table><tr><td rowspan="2"></td><td colspan="6">2020</td></tr><tr><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td>Federal statutory rate</td><td>21.0%</td><td>21.0%</td><td>21.0%</td><td>21.0%</td><td>2.7%</td><td>21.0%</td></tr><tr><td>State income tax, net of federal deduction</td><td>2.8</td><td>5.0</td><td>0.5</td><td>4.8</td><td>2.7</td><td>4.0</td></tr><tr><td>Employee stock plans&#x27; dividend deduction</td><td>(0.7)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Non-deductible book depreciation</td><td>0.7</td><td>0.6</td><td>0.8</td><td>0.5</td><td>—</td><td>—</td></tr><tr><td>Flowback of excess deferred income taxes</td><td>(8.8)</td><td>(3.1)</td><td>(12.0)</td><td>(18.5)</td><td>—</td><td>(2.7)</td></tr><tr><td>AFUDC-Equity</td><td>(0.8)</td><td>(0.6)</td><td>(1.1)</td><td>(0.1)</td><td>—</td><td>—</td></tr><tr><td>Federal PTCs</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(2.5)</td><td>—</td></tr><tr><td>Amortization of ITC</td><td>(1.6)</td><td>(0.1)</td><td>(0.1)</td><td>(0.1)</td><td>(22.1)</td><td>(0.1)</td></tr><tr><td>Noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>—</td><td>3.1</td><td>—</td></tr><tr><td>Leveraged lease impairments</td><td>(1.6)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>0.2</td><td>(0.3)</td><td>(0.3)</td><td>0.9</td><td>(0.9)</td><td>0.5</td></tr><tr><td>Effective income tax (benefit) rate</td><td>11.2%</td><td>22.5%</td><td>8.8%</td><td>8.5%</td><td>1.3%</td><td>22.7%</td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="6">2019</td></tr><tr><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td>Federal statutory rate</td><td>21.0%</td><td>21.0%</td><td>21.0%</td><td>21.0%</td><td>2.1%</td><td>21.0%</td></tr><tr><td>State income tax, net of federal deduction</td><td>4.9</td><td>4.9</td><td>1.0</td><td>4.3</td><td>4.0</td><td>6.1</td></tr><tr><td>Employee stock plans&#x27; dividend deduction</td><td>(0.4)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Non-deductible book depreciation</td><td>0.3</td><td>0.6</td><td>0.5</td><td>0.4</td><td>—</td><td>—</td></tr><tr><td>Flowback of excess deferred income taxes</td><td>(2.1)</td><td>(5.3)</td><td>—</td><td>(12.6)</td><td>—</td><td>(6.0)</td></tr><tr><td>AFUDC-Equity</td><td>(0.4)</td><td>(0.8)</td><td>(0.6)</td><td>(0.1)</td><td>—</td><td>—</td></tr><tr><td>ITC basis difference</td><td>(0.1)</td><td>—</td><td>—</td><td>—</td><td>(1.9)</td><td>—</td></tr><tr><td>Amortization of ITC</td><td>(0.8)</td><td>(0.1)</td><td>(0.1)</td><td>(0.1)</td><td>(16.1)</td><td>(0.1)</td></tr><tr><td>Tax impact from sale of subsidiaries</td><td>5.1</td><td>—</td><td>—</td><td>—</td><td>(27.6)</td><td>(1.4)</td></tr><tr><td>Noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>—</td><td>0.8</td><td>—</td></tr><tr><td>Other</td><td>—</td><td>(0.4)</td><td>(0.3)</td><td>4.9</td><td>(0.6)</td><td>(1.4)</td></tr><tr><td>Effective income tax (benefit) rate</td><td>27.5%</td><td>19.9%</td><td>21.5%</td><td>17.8%</td><td>(20.4)%</td><td>18.2%</td></tr></table>



## 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:

<table><tr><td rowspan="2"></td><td colspan="6">December 31, 2021</td></tr><tr><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td>Deferred tax liabilities —</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Accelerated depreciation</td><td>$ 9,300</td><td>$2,541</td><td>$3,340</td><td>$ 330</td><td>$1,421</td><td>$1,428</td></tr><tr><td>Property basis differences</td><td>2,301</td><td>1,182</td><td>781</td><td>169</td><td>—</td><td>148</td></tr><tr><td>Federal effect of net state deferred tax assets</td><td>—</td><td>—</td><td>—</td><td>22</td><td>—</td><td>—</td></tr><tr><td>Leveraged lease basis differences</td><td>61</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Employee benefit obligations</td><td>820</td><td>268</td><td>382</td><td>41</td><td>11</td><td>57</td></tr><tr><td>Under recovered fuel and natural gas costs</td><td>315</td><td>47</td><td>109</td><td>15</td><td>—</td><td>144</td></tr><tr><td>Regulatory assets —</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Storm damage reserves</td><td>18</td><td>—</td><td>18</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Employee benefit obligations</td><td>825</td><td>205</td><td>256</td><td>38</td><td>—</td><td>15</td></tr><tr><td>Remaining book value of retired assets</td><td>271</td><td>145</td><td>121</td><td>5</td><td>—</td><td>—</td></tr><tr><td>Premium on reacquired debt</td><td>72</td><td>10</td><td>62</td><td>—</td><td>—</td><td>—</td></tr><tr><td>AROs</td><td>2,232</td><td>863</td><td>1,325</td><td>44</td><td>—</td><td>—</td></tr><tr><td>AROs</td><td>868</td><td>329</td><td>494</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>368</td><td>147</td><td>77</td><td>34</td><td>14</td><td>82</td></tr><tr><td>Total deferred income tax liabilities</td><td>17,451</td><td>5,737</td><td>6,965</td><td>698</td><td>1,446</td><td>1,874</td></tr><tr><td>Deferred tax assets —</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Federal effect of net state deferred tax liabilities</td><td>305</td><td>165</td><td>41</td><td>—</td><td>27</td><td>93</td></tr><tr><td>State effect of federal deferred taxes</td><td>135</td><td>135</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Employee benefit obligations</td><td>1,035</td><td>225</td><td>342</td><td>57</td><td>7</td><td>77</td></tr><tr><td>Other property basis differences</td><td>231</td><td>—</td><td>90</td><td>—</td><td>121</td><td>—</td></tr><tr><td>ITC and PTC carryforward</td><td>1,750</td><td>12</td><td>704</td><td>—</td><td>827</td><td>—</td></tr><tr><td>Long-term debt fair value adjustment</td><td>91</td><td>—</td><td>—</td><td>—</td><td>—</td><td>91</td></tr><tr><td>Other partnership basis difference</td><td>160</td><td>—</td><td>—</td><td>—</td><td>160</td><td>—</td></tr><tr><td>Other comprehensive losses</td><td>92</td><td>5</td><td>15</td><td>—</td><td>11</td><td>—</td></tr><tr><td>AROs</td><td>3,100</td><td>1,192</td><td>1,819</td><td>44</td><td>—</td><td>—</td></tr><tr><td>Estimated loss on plants under construction</td><td>825</td><td>—</td><td>825</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Other deferred state tax attributes</td><td>361</td><td>—</td><td>11</td><td>246</td><td>52</td><td>5</td></tr><tr><td>Regulatory liability associated with the Tax Reform Legislation (not subject to normalization)</td><td>268</td><td>237</td><td>19</td><td>12</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>561</td><td>193</td><td>153</td><td>34</td><td>53</td><td>62</td></tr><tr><td>Total deferred income tax assets</td><td>8,914</td><td>2,164</td><td>4,019</td><td>393</td><td>1,258</td><td>328</td></tr><tr><td>Valuation allowance</td><td>(207)</td><td>—</td><td>(73)</td><td>(41)</td><td>(27)</td><td>(9)</td></tr><tr><td>Net deferred income tax assets</td><td>8,707</td><td>2,164</td><td>3,946</td><td>352</td><td>1,231</td><td>319</td></tr><tr><td>Net deferred income taxes (assets)/liabilities</td><td>$ 8,744</td><td>$3,573</td><td>$3,019</td><td>$ 346</td><td>$ 215</td><td>$1,555</td></tr><tr><td>Recognized in the balance sheets:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Accumulated deferred income taxes — assets</td><td>$ (118)</td><td>$ —</td><td>$ —</td><td>$(118)</td><td>$ —</td><td>$ —</td></tr><tr><td>Accumulated deferred income taxes — liabilities</td><td>$ 8,862</td><td>$3,573</td><td>$3,019</td><td>$ 464</td><td>$ 215</td><td>$1,555</td></tr></table>



<table><tr><td rowspan="2"></td><td colspan="6">December 31, 2020</td></tr><tr><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td>Deferred tax liabilities —</td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Accelerated depreciation</td><td>$ 8,950</td><td>$2,453</td><td>$3,228</td><td>$ 319</td><td>$1,389</td><td>$ 1,349</td></tr><tr><td>Property basis differences</td><td>1,999</td><td>1,010</td><td>689</td><td>148</td><td>—</td><td>135</td></tr><tr><td>Federal effect of net state deferred tax assets</td><td>—</td><td>—</td><td>—</td><td>25</td><td>—</td><td>—</td></tr><tr><td>Leveraged lease basis differences</td><td>142</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Employee benefit obligations</td><td>739</td><td>250</td><td>362</td><td>39</td><td>12</td><td>26</td></tr><tr><td>Regulatory assets —</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Storm damage reserves</td><td>80</td><td>—</td><td>80</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Employee benefit obligations</td><td>1,313</td><td>348</td><td>438</td><td>62</td><td>—</td><td>45</td></tr><tr><td>Remaining book value of retired assets</td><td>270</td><td>123</td><td>141</td><td>6</td><td>—</td><td>—</td></tr><tr><td>Premium on reacquired debt</td><td>78</td><td>12</td><td>66</td><td>—</td><td>—</td><td>—</td></tr><tr><td>AROs</td><td>1,969</td><td>764</td><td>1,165</td><td>40</td><td>—</td><td>—</td></tr><tr><td>AROs</td><td>804</td><td>328</td><td>429</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>437</td><td>128</td><td>82</td><td>66</td><td>12</td><td>138</td></tr><tr><td>Total deferred income tax liabilities</td><td>16,781</td><td>5,416</td><td>6,680</td><td>705</td><td>1,413</td><td>1,693</td></tr><tr><td>Deferred tax assets —</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Federal effect of net state deferred tax liabilities</td><td>284</td><td>151</td><td>59</td><td>—</td><td>26</td><td>70</td></tr><tr><td>State effect of federal deferred taxes</td><td>126</td><td>126</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Employee benefit obligations</td><td>1,511</td><td>369</td><td>522</td><td>80</td><td>6</td><td>100</td></tr><tr><td>Other property basis differences</td><td>223</td><td>—</td><td>72</td><td>—</td><td>134</td><td>—</td></tr><tr><td>ITC and PTC carryforward</td><td>1,853</td><td>12</td><td>539</td><td>—</td><td>1,110</td><td>—</td></tr><tr><td>Long-term debt fair value adjustment</td><td>86</td><td>—</td><td>—</td><td>—</td><td>—</td><td>86</td></tr><tr><td>Other partnership basis difference</td><td>166</td><td>—</td><td>—</td><td>—</td><td>166</td><td>—</td></tr><tr><td>Other comprehensive losses</td><td>128</td><td>7</td><td>17</td><td>—</td><td>25</td><td>—</td></tr><tr><td>AROs</td><td>2,773</td><td>1,092</td><td>1,594</td><td>40</td><td>—</td><td>—</td></tr><tr><td>Estimated loss on plants under construction</td><td>369</td><td>—</td><td>369</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Other deferred state tax attributes</td><td>357</td><td>—</td><td>9</td><td>250</td><td>68</td><td>10</td></tr><tr><td>Regulatory liability associated with the Tax Reform Legislation (not subject to normalization)</td><td>338</td><td>243</td><td>76</td><td>19</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>660</td><td>143</td><td>186</td><td>39</td><td>52</td><td>166</td></tr><tr><td>Total deferred income tax assets</td><td>8,874</td><td>2,143</td><td>3,443</td><td>428</td><td>1,587</td><td>432</td></tr><tr><td>Valuation allowance</td><td>(136)</td><td>—</td><td>(35)</td><td>(41)</td><td>(35)</td><td>(4)</td></tr><tr><td>Net deferred income tax assets</td><td>8,738</td><td>2,143</td><td>3,408</td><td>387</td><td>1,552</td><td>428</td></tr><tr><td>Net deferred income taxes/(liabilities)</td><td>$ 8,043</td><td>$3,273</td><td>$3,272</td><td>$ 318</td><td>$ (139)</td><td>$ 1,265</td></tr><tr><td>Recognized in the balance sheets:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Accumulated deferred income taxes — assets</td><td>$ (132)</td><td>$ —</td><td>$ —</td><td>$ (129)</td><td>$ (262)</td><td>$ —</td></tr><tr><td>Accumulated deferred income taxes — liabilities</td><td>$ 8,175</td><td>$3,273</td><td>$3,272</td><td>$ 447</td><td>$ 123</td><td>$ 1,265</td></tr></table>

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.



## Tax Credit Carryforwards

Federal ITC/PTC carryforwards at December 31, 2021 were as follows:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Southern Power</td></tr><tr><td></td><td colspan="4">(in millions)</td></tr><tr><td>Federal ITC/PTC carryforwards</td><td>$1,218</td><td>$ 12</td><td>$ 173</td><td>$ 827</td></tr><tr><td>Tax year in which federal ITC/PTC carryforwards begin expiring</td><td>2031</td><td>2032</td><td>2031</td><td>2035</td></tr><tr><td>Year by which federal ITC/PTC carryforwards are expected to be utilized</td><td>2024</td><td>2024</td><td>2024</td><td>2024</td></tr></table>

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:

<table><tr><td>Company/Jurisdiction</td><td>Approximate Net State Income Tax Benefit of NOL Carryforwards</td><td>Tax Year NOL Begins Expiring</td></tr><tr><td>Mississippi Power</td><td></td><td></td></tr><tr><td>Mississippi</td><td>$195</td><td>2031</td></tr><tr><td>Southern Power</td><td></td><td></td></tr><tr><td>Oklahoma</td><td>27</td><td>2035</td></tr><tr><td>Florida</td><td>10</td><td>2034</td></tr><tr><td>South Carolina</td><td>2</td><td>2036</td></tr><tr><td>Other states</td><td>2</td><td>Various</td></tr><tr><td>Southern Power Total</td><td>$ 41</td><td></td></tr><tr><td>Other(*)</td><td></td><td></td></tr><tr><td>New York</td><td>11</td><td>2035</td></tr><tr><td>New York City</td><td>14</td><td>2035</td></tr><tr><td>Other states</td><td>17</td><td>Various</td></tr><tr><td>Southern Company Total</td><td>$278</td><td></td></tr></table>

(*) 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.

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:

<table><tr><td></td><td>Southern Company (in millions)</td></tr><tr><td>Unrecognized tax benefits at December 31, 2018 and 2019</td><td>-</td></tr><tr><td>Tax positions changes - increase from prior periods</td><td>44</td></tr><tr><td>Unrecognized tax benefits at December 31, 2020</td><td>44</td></tr><tr><td>Tax positions changes - increase from prior periods</td><td>3</td></tr><tr><td>Unrecognized tax benefits at December 31, 2021</td><td>47</td></tr></table>

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, trusted 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.

## 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.

<table><tr><td rowspan="2">Assumptions used to determine net periodic costs:</td><td colspan="6">2021</td></tr><tr><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td>Pension plans</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount rate - benefit obligations</td><td>2.81%</td><td>2.85%</td><td>2.79%</td><td>2.80%</td><td>2.99%</td><td>2.75%</td></tr><tr><td>Discount rate - interest costs</td><td>2.13</td><td>2.17</td><td>2.09</td><td>2.12</td><td>2.46</td><td>2.10</td></tr><tr><td>Discount rate - service costs</td><td>3.18</td><td>3.23</td><td>3.21</td><td>3.20</td><td>3.22</td><td>2.97</td></tr><tr><td>Expected long-term return on plan assets</td><td>8.25</td><td>8.25</td><td>8.25</td><td>8.25</td><td>8.26</td><td>8.25</td></tr><tr><td>Annual salary increase</td><td>4.80</td><td>4.80</td><td>4.80</td><td>4.80</td><td>4.81</td><td>4.80</td></tr><tr><td>Other postretirement benefit plans</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount rate - benefit obligations</td><td>2.56%</td><td>2.63%</td><td>2.52%</td><td>2.53%</td><td>2.78%</td><td>2.46%</td></tr><tr><td>Discount rate - interest costs</td><td>1.84</td><td>1.91</td><td>1.82</td><td>1.78</td><td>2.12</td><td>1.64</td></tr><tr><td>Discount rate - service costs</td><td>3.07</td><td>3.13</td><td>3.08</td><td>3.06</td><td>3.05</td><td>3.01</td></tr><tr><td>Expected long-term return on plan assets</td><td>7.09</td><td>7.18</td><td>6.84</td><td>6.98</td><td>—</td><td>6.54</td></tr><tr><td>Annual salary increase</td><td>4.80</td><td>4.80</td><td>4.80</td><td>4.80</td><td>4.81</td><td>4.80</td></tr></table>



<table><tr><td rowspan="2">Assumptions used to determine net periodic costs:</td><td colspan="6">2020</td></tr><tr><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td>Pension plans</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount rate - benefit obligations</td><td>3.41%</td><td>3.44%</td><td>3.40%</td><td>3.41%</td><td>3.52%</td><td>3.39%</td></tr><tr><td>Discount rate - interest costs</td><td>2.99</td><td>3.01</td><td>2.96</td><td>2.99</td><td>3.18</td><td>2.99</td></tr><tr><td>Discount rate - service costs</td><td>3.66</td><td>3.69</td><td>3.67</td><td>3.67</td><td>3.70</td><td>3.53</td></tr><tr><td>Expected long-term return on plan assets</td><td>8.25</td><td>8.25</td><td>8.25</td><td>8.25</td><td>8.26</td><td>8.25</td></tr><tr><td>Annual salary increase</td><td>4.73</td><td>4.73</td><td>4.73</td><td>4.73</td><td>4.74</td><td>4.73</td></tr><tr><td>Other postretirement benefit plans</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount rate - benefit obligations</td><td>3.24%</td><td>3.28%</td><td>3.22%</td><td>3.22%</td><td>3.39%</td><td>3.19%</td></tr><tr><td>Discount rate - interest costs</td><td>2.80</td><td>2.84</td><td>2.79</td><td>2.76</td><td>2.97</td><td>2.71</td></tr><tr><td>Discount rate - service costs</td><td>3.57</td><td>3.61</td><td>3.57</td><td>3.57</td><td>3.57</td><td>3.52</td></tr><tr><td>Expected long-term return on plan assets</td><td>7.25</td><td>7.36</td><td>7.05</td><td>7.07</td><td>—</td><td>6.69</td></tr><tr><td>Annual salary increase</td><td>4.73</td><td>4.73</td><td>4.73</td><td>4.73</td><td>4.74</td><td>4.73</td></tr></table>

<table><tr><td rowspan="2">Assumptions used to determine net periodic costs:</td><td colspan="6">2019</td></tr><tr><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td>Pension plans</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount rate - benefit obligations</td><td>4.49%</td><td>4.51%</td><td>4.48%</td><td>4.49%</td><td>4.65%</td><td>4.47%</td></tr><tr><td>Discount rate - interest costs</td><td>4.12</td><td>4.14</td><td>4.10</td><td>4.12</td><td>4.35</td><td>4.11</td></tr><tr><td>Discount rate - service costs</td><td>4.70</td><td>4.73</td><td>4.72</td><td>4.73</td><td>4.75</td><td>4.57</td></tr><tr><td>Expected long-term return on plan assets</td><td>7.75</td><td>7.75</td><td>7.75</td><td>7.75</td><td>7.76</td><td>7.75</td></tr><tr><td>Annual salary increase</td><td>4.34</td><td>4.46</td><td>4.46</td><td>4.46</td><td>4.46</td><td>3.07</td></tr><tr><td>Other postretirement benefit plans</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount rate - benefit obligations</td><td>4.37%</td><td>4.40%</td><td>4.36%</td><td>4.35%</td><td>4.50%</td><td>4.32%</td></tr><tr><td>Discount rate - interest costs</td><td>3.98</td><td>4.01</td><td>3.97</td><td>3.95</td><td>4.14</td><td>3.91</td></tr><tr><td>Discount rate - service costs</td><td>4.63</td><td>4.67</td><td>4.64</td><td>4.64</td><td>4.65</td><td>4.56</td></tr><tr><td>Expected long-term return on plan assets</td><td>6.86</td><td>6.76</td><td>6.85</td><td>6.79</td><td>—</td><td>6.49</td></tr><tr><td>Annual salary increase</td><td>4.34</td><td>4.46</td><td>4.46</td><td>4.46</td><td>4.46</td><td>3.07</td></tr></table>

<table><tr><td rowspan="2">Assumptions used to determine benefit obligations:</td><td colspan="6">2021</td></tr><tr><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td>Pension plans</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount rate</td><td>3.09%</td><td>3.12%</td><td>3.07%</td><td>3.07%</td><td>3.21%</td><td>3.04%</td></tr><tr><td>Annual salary increase</td><td>4.80</td><td>4.80</td><td>4.80</td><td>4.80</td><td>4.81</td><td>4.80</td></tr><tr><td>Other postretirement benefit plans</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount rate</td><td>2.90%</td><td>2.95%</td><td>2.87%</td><td>2.88%</td><td>3.07%</td><td>2.82%</td></tr><tr><td>Annual salary increase</td><td>4.80</td><td>4.80</td><td>4.80</td><td>4.80</td><td>4.81</td><td>4.80</td></tr></table>

<table><tr><td rowspan="2">Assumptions used to determine benefit obligations:</td><td colspan="6">2020</td></tr><tr><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td>Pension plans</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount rate</td><td>2.81%</td><td>2.85%</td><td>2.79%</td><td>2.80%</td><td>2.99%</td><td>2.75%</td></tr><tr><td>Annual salary increase</td><td>4.80</td><td>4.80</td><td>4.80</td><td>4.80</td><td>4.81</td><td>4.80</td></tr><tr><td>Other postretirement benefit plans</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Discount rate</td><td>2.56%</td><td>2.63%</td><td>2.52%</td><td>2.53%</td><td>2.78%</td><td>2.46%</td></tr><tr><td>Annual salary increase</td><td>4.80</td><td>4.80</td><td>4.80</td><td>4.80</td><td>4.81</td><td>4.80</td></tr></table>



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.

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:

<table><tr><td></td><td>Initial Cost Trend Rate</td><td>Ultimate Cost Trend Rate</td><td>Year That Ultimate Rate is Reached</td></tr><tr><td>Pre-65</td><td>6.00%</td><td>4.50%</td><td>2028</td></tr><tr><td>Post-65 medical</td><td>5.00</td><td>4.50</td><td>2028</td></tr><tr><td>Post-65 prescription</td><td>6.25</td><td>4.50</td><td>2029</td></tr></table>

## Pension Plans

The total accumulated benefit obligation for the pension plans at December 31, 2021 and 2020 was as follows:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td colspan="6">(in millions)</td></tr><tr><td>December 31, 2021</td><td>$14,687</td><td>$3,362</td><td>$4,562</td><td>$672</td><td>$178</td><td>$1,030</td></tr><tr><td>December 31, 2020</td><td>14,922</td><td>3,414</td><td>4,657</td><td>683</td><td>175</td><td>1,072</td></tr></table>

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:

<table><tr><td rowspan="3"></td><td colspan="6">2021</td></tr><tr><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td colspan="6">(in millions)</td></tr><tr><td>Change in benefit obligation</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Benefit obligation at beginning of year</td><td>$16,646</td><td>$3,854</td><td>$5,127</td><td>$754</td><td>$217</td><td>$1,189</td></tr><tr><td>Service cost</td><td>434</td><td>102</td><td>112</td><td>18</td><td>10</td><td>37</td></tr><tr><td>Interest cost</td><td>346</td><td>82</td><td>104</td><td>16</td><td>5</td><td>24</td></tr><tr><td>Benefits paid</td><td>(651)</td><td>(137)</td><td>(210)</td><td>(28)</td><td>(4)</td><td>(73)</td></tr><tr><td>Actuarial gain</td><td>(393)</td><td>(95)</td><td>(121)</td><td>(17)</td><td>(6)</td><td>(43)</td></tr><tr><td>Balance at end of year</td><td>16,382</td><td>3,806</td><td>5,012</td><td>743</td><td>222</td><td>1,134</td></tr><tr><td>Change in plan assets</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Fair value of plan assets at beginning of year</td><td>15,367</td><td>3,684</td><td>4,844</td><td>701</td><td>186</td><td>1,123</td></tr><tr><td>Actual return on plan assets</td><td>2,449</td><td>586</td><td>781</td><td>111</td><td>30</td><td>181</td></tr><tr><td>Employer contributions</td><td>60</td><td>8</td><td>—</td><td>2</td><td>1</td><td>10</td></tr><tr><td>Benefits paid</td><td>(651)</td><td>(137)</td><td>(210)</td><td>(28)</td><td>(4)</td><td>(73)</td></tr><tr><td>Fair value of plan assets at end of year</td><td>17,225</td><td>4,141</td><td>5,415</td><td>786</td><td>213</td><td>1,241</td></tr><tr><td>Accrued asset (liability)</td><td>$ 843</td><td>$ 335</td><td>$ 403</td><td>$ 43</td><td>$ (9)</td><td>$ 107</td></tr></table>



<table><tr><td rowspan="2"></td><td colspan="6">2020</td></tr><tr><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td>Change in benefit obligation</td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Benefit obligation at beginning of year</td><td>$14,788</td><td>$3,404</td><td>$4,610</td><td>$671</td><td>$ 185</td><td>$1,067</td></tr><tr><td>Service cost</td><td>376</td><td>89</td><td>96</td><td>15</td><td>8</td><td>33</td></tr><tr><td>Interest cost</td><td>432</td><td>100</td><td>133</td><td>20</td><td>6</td><td>31</td></tr><tr><td>Benefits paid</td><td>(629)</td><td>(132)</td><td>(202)</td><td>(27)</td><td>(6)</td><td>(69)</td></tr><tr><td>Actuarial loss</td><td>1,679</td><td>393</td><td>490</td><td>75</td><td>24</td><td>127</td></tr><tr><td>Balance at end of year</td><td>16,646</td><td>3,854</td><td>5,127</td><td>754</td><td>217</td><td>1,189</td></tr><tr><td>Change in plan assets</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Fair value of plan assets at beginning of year</td><td>14,057</td><td>3,357</td><td>4,442</td><td>641</td><td>169</td><td>1,050</td></tr><tr><td>Actual return on plan assets</td><td>1,881</td><td>450</td><td>594</td><td>85</td><td>22</td><td>139</td></tr><tr><td>Employer contributions</td><td>58</td><td>9</td><td>10</td><td>2</td><td>1</td><td>3</td></tr><tr><td>Benefits paid</td><td>(629)</td><td>(132)</td><td>(202)</td><td>(27)</td><td>(6)</td><td>(69)</td></tr><tr><td>Fair value of plan assets at end of year</td><td>15,367</td><td>3,684</td><td>4,844</td><td>701</td><td>186</td><td>1,123</td></tr><tr><td>Accrued liability</td><td>$ (1,279)</td><td>$ (170)</td><td>$ (283)</td><td>$ (53)</td><td>$ (31)</td><td>$ (66)</td></tr></table>

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.

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Projected benefit obligations:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Qualified pension plan</td><td>$15,568</td><td>$3,678</td><td>$4,852</td><td>$708</td><td>$193</td><td>$1,066</td></tr><tr><td>Non-qualified pension plan</td><td>814</td><td>129</td><td>160</td><td>36</td><td>29</td><td>68</td></tr></table>

Amounts recognized in the balance sheets at December 31, 2021 and 2020 related to the Registrants' pension plans consist of the following:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>December 31, 2021:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Prepaid pension costs \( ^{(a)} \)</td><td>$ 1,657</td><td>$ 464</td><td>$ 563</td><td>$ 78</td><td>$ 20</td><td>$ 175</td></tr><tr><td>Other regulatory assets, deferred \( ^{(b)} \)</td><td>2,920</td><td>809</td><td>971</td><td>146</td><td>—</td><td>91</td></tr><tr><td>Other current liabilities</td><td>(55)</td><td>(9)</td><td>(12)</td><td>(2)</td><td>(2)</td><td>(2)</td></tr><tr><td>Employee benefit obligations \( ^{(c)} \)</td><td>(759)</td><td>(120)</td><td>(148)</td><td>(33)</td><td>(27)</td><td>(66)</td></tr><tr><td>Other regulatory liabilities, deferred</td><td>(119)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>AOCI</td><td>100</td><td>—</td><td>—</td><td>—</td><td>35</td><td>(45)</td></tr><tr><td>December 31, 2020:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Prepaid pension costs</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 70</td></tr><tr><td>Other regulatory assets, deferred \( ^{(b)} \)</td><td>4,655</td><td>1,286</td><td>1,598</td><td>235</td><td>—</td><td>205</td></tr><tr><td>Other current liabilities</td><td>(52)</td><td>(9)</td><td>(10)</td><td>(2)</td><td>(2)</td><td>(2)</td></tr><tr><td>Employee benefit obligations \( ^{(c)} \)</td><td>(1,227)</td><td>(161)</td><td>(273)</td><td>(51)</td><td>(29)</td><td>(134)</td></tr><tr><td>Other regulatory liabilities, deferred</td><td>(34)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>AOCI</td><td>245</td><td>—</td><td>—</td><td>—</td><td>60</td><td>1</td></tr></table>

(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.

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td></tr><tr><td>Balance at December 31, 2021</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Regulatory assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Prior service cost</td><td>$ 11</td><td>$ 5</td><td>$ 8</td><td>$ 1</td><td>$ (11)</td></tr><tr><td>Net loss</td><td>2,790</td><td>804</td><td>963</td><td>145</td><td>38</td></tr><tr><td>Regulatory amortization</td><td>—</td><td>—</td><td>—</td><td>—</td><td>64</td></tr><tr><td>Total regulatory assets \( ^{(1)} \)</td><td>$ 2,801</td><td>$ 809</td><td>$ 971</td><td>$ 146</td><td>$ 91</td></tr><tr><td>Balance at December 31, 2020</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Regulatory assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Prior service cost</td><td>$ 11</td><td>$ 5</td><td>$ 9</td><td>$ 2</td><td>$ (13)</td></tr><tr><td>Net loss</td><td>4,610</td><td>1,281</td><td>1,589</td><td>233</td><td>135</td></tr><tr><td>Regulatory amortization</td><td>—</td><td>—</td><td>—</td><td>—</td><td>83</td></tr><tr><td>Total regulatory assets \( ^{(1)} \)</td><td>$ 4,621</td><td>$ 1,286</td><td>$ 1,598</td><td>$ 235</td><td>$ 205</td></tr></table>

(*) 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.

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:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Regulatory assets (liabilities):(1)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Balance at December 31, 2019</td><td>$ 3,993</td><td>$1,130</td><td>$1,416</td><td>$203</td><td>$ 172</td></tr><tr><td>Net loss</td><td>884</td><td>228</td><td>269</td><td>45</td><td>45</td></tr><tr><td>Reclassification adjustments:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Amortization of prior service costs</td><td>(1)</td><td>(1)</td><td>(1)</td><td>—</td><td>2</td></tr><tr><td>Amortization of net loss</td><td>(255)</td><td>(71)</td><td>(86)</td><td>(13)</td><td>(8)</td></tr><tr><td>Amortization of regulatory assets(1)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(6)</td></tr><tr><td>Total reclassification adjustments</td><td>(256)</td><td>(72)</td><td>(87)</td><td>(13)</td><td>(12)</td></tr><tr><td>Total change</td><td>628</td><td>156</td><td>182</td><td>32</td><td>33</td></tr><tr><td>Balance at December 31, 2020</td><td>$ 4,621</td><td>$1,286</td><td>$1,598</td><td>$235</td><td>$ 205</td></tr><tr><td>Net gain</td><td>(1,523)</td><td>(394)</td><td>(527)</td><td>(74)</td><td>(97)</td></tr><tr><td>Reclassification adjustments:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Amortization of prior service costs</td><td>(1)</td><td>(1)</td><td>(1)</td><td>—</td><td>2</td></tr><tr><td>Amortization of net loss</td><td>(296)</td><td>(82)</td><td>(99)</td><td>(15)</td><td>(9)</td></tr><tr><td>Amortization of regulatory assets(1)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(10)</td></tr><tr><td>Total reclassification adjustments</td><td>(297)</td><td>(83)</td><td>(100)</td><td>(15)</td><td>(17)</td></tr><tr><td>Total change</td><td>(1,820)</td><td>(477)</td><td>(627)</td><td>(89)</td><td>(114)</td></tr><tr><td>Balance at December 31, 2021</td><td>$ 2,801</td><td>$ 809</td><td>$ 971</td><td>$ 146</td><td>$ 91</td></tr></table>

(*) Amounts for Southern Company exclude regulatory assets of $210 million and $224 million at December 31, 2021 and 2020, respectively, associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company.



Presented below are the amounts included in AOCI at December 31, 2021 and 2020 related to the portion of the defined benefit pension plan attributable to Southern Company, Southern Power, and Southern Company Gas that had not yet been recognized in net periodic pension cost.

<table><tr><td></td><td>Southern Company</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td>(in millions)</td><td></td></tr><tr><td>Balance at December 31, 2021</td><td></td><td></td><td></td></tr><tr><td>AOCI:</td><td></td><td></td><td></td></tr><tr><td>Prior service cost</td><td>$ (2)</td><td>$ —</td><td>$ (3)</td></tr><tr><td>Net (gain) loss</td><td>102</td><td>35</td><td>(42)</td></tr><tr><td>Total AOCI</td><td>$ 100</td><td>$ 35</td><td>$ (45)</td></tr><tr><td>Balance at December 31, 2020</td><td></td><td></td><td></td></tr><tr><td>AOCI:</td><td></td><td></td><td></td></tr><tr><td>Prior service cost</td><td>$ (3)</td><td>$ —</td><td>$ (4)</td></tr><tr><td>Net loss</td><td>248</td><td>60</td><td>5</td></tr><tr><td>Total AOCI</td><td>$ 245</td><td>$ 60</td><td>$ 1</td></tr></table>

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:

<table><tr><td></td><td>Southern Company</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td>(in millions)</td><td></td></tr><tr><td>AOCI:</td><td></td><td></td><td></td></tr><tr><td>Balance at December 31, 2019</td><td>$ 185</td><td>$ 46</td><td>$ (14)</td></tr><tr><td>Net loss</td><td>74</td><td>16</td><td>15</td></tr><tr><td>Reclassification adjustments:</td><td></td><td></td><td></td></tr><tr><td>Amortization of prior service costs</td><td>—</td><td>—</td><td>1</td></tr><tr><td>Amortization of net loss</td><td>(14)</td><td>(2)</td><td>(1)</td></tr><tr><td>Total reclassification adjustments</td><td>(14)</td><td>(2)</td><td>—</td></tr><tr><td>Total change</td><td>60</td><td>14</td><td>15</td></tr><tr><td>Balance at December 31, 2020</td><td>$ 245</td><td>$ 60</td><td>$ 1</td></tr><tr><td>Net gain</td><td>(128)</td><td>(22)</td><td>(47)</td></tr><tr><td>Reclassification adjustments:</td><td></td><td></td><td></td></tr><tr><td>Amortization of net gain (loss)</td><td>(17)</td><td>(3)</td><td>1</td></tr><tr><td>Total reclassification adjustments</td><td>(17)</td><td>(3)</td><td>1</td></tr><tr><td>Total change</td><td>(145)</td><td>(25)</td><td>(46)</td></tr><tr><td>Balance at December 31, 2021</td><td>$ 100</td><td>$ 35</td><td>$ (45)</td></tr></table>



Components of net periodic pension cost for the Registrants were as follows:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>2021</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Service cost</td><td>$ 434</td><td>$ 102</td><td>$ 112</td><td>$ 18</td><td>$ 10</td><td>$ 37</td></tr><tr><td>Interest cost</td><td>346</td><td>82</td><td>104</td><td>16</td><td>5</td><td>24</td></tr><tr><td>Expected return on plan assets</td><td>(1,191)</td><td>(287)</td><td>(375)</td><td>(55)</td><td>(14)</td><td>(86)</td></tr><tr><td>Recognized net loss</td><td>314</td><td>82</td><td>100</td><td>15</td><td>3</td><td>13</td></tr><tr><td>Net amortization</td><td>1</td><td>1</td><td>1</td><td>—</td><td>—</td><td>15</td></tr><tr><td>Prior service cost</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(3)</td></tr><tr><td>Net periodic pension cost (income)</td><td>$ (96)</td><td>$ (20)</td><td>$ (58)</td><td>$ (6)</td><td>$ 4</td><td>$ —</td></tr><tr><td>2020</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Service cost</td><td>$ 376</td><td>$ 89</td><td>$ 96</td><td>$ 15</td><td>$ 8</td><td>$ 33</td></tr><tr><td>Interest cost</td><td>432</td><td>100</td><td>133</td><td>20</td><td>6</td><td>31</td></tr><tr><td>Expected return on plan assets</td><td>(1,100)</td><td>(264)</td><td>(347)</td><td>(51)</td><td>(13)</td><td>(75)</td></tr><tr><td>Recognized net loss</td><td>269</td><td>71</td><td>86</td><td>13</td><td>2</td><td>6</td></tr><tr><td>Net amortization</td><td>1</td><td>1</td><td>1</td><td>—</td><td>—</td><td>15</td></tr><tr><td>Prior service cost</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(3)</td></tr><tr><td>Net periodic pension cost (income)</td><td>$ (22)</td><td>$ (3)</td><td>$ (31)</td><td>$ (3)</td><td>$ 3</td><td>$ 7</td></tr><tr><td>2019</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Service cost</td><td>$ 292</td><td>$ 69</td><td>$ 74</td><td>$ 12</td><td>$ 7</td><td>$ 25</td></tr><tr><td>Interest cost</td><td>492</td><td>114</td><td>156</td><td>22</td><td>5</td><td>36</td></tr><tr><td>Expected return on plan assets</td><td>(885)</td><td>(206)</td><td>(292)</td><td>(40)</td><td>(10)</td><td>(60)</td></tr><tr><td>Recognized net loss</td><td>120</td><td>37</td><td>44</td><td>6</td><td>1</td><td>2</td></tr><tr><td>Net amortization</td><td>2</td><td>—</td><td>1</td><td>—</td><td>—</td><td>14</td></tr><tr><td>Prior service cost</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(3)</td></tr><tr><td>Net periodic pension cost (income)</td><td>$ 21</td><td>$ 14</td><td>$ (17)</td><td>$ —</td><td>$ 3</td><td>$ 14</td></tr></table>

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.



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:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Benefit Payments:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2022</td><td>$ 690</td><td>$148</td><td>$ 223</td><td>$ 31</td><td>$ 6</td><td>$ 65</td></tr><tr><td>2023</td><td>714</td><td>155</td><td>229</td><td>31</td><td>6</td><td>65</td></tr><tr><td>2024</td><td>736</td><td>159</td><td>235</td><td>32</td><td>6</td><td>64</td></tr><tr><td>2025</td><td>759</td><td>165</td><td>240</td><td>34</td><td>7</td><td>64</td></tr><tr><td>2026</td><td>780</td><td>171</td><td>245</td><td>35</td><td>7</td><td>64</td></tr><tr><td>2027 to 2031</td><td>4,138</td><td>921</td><td>1,275</td><td>187</td><td>42</td><td>329</td></tr></table>

## Other Postretirement Benefits

Changes in the APBO and the fair value of the Registrants' plan assets during the plan years ended December 31, 2021 and 2020 were as follows:

<table><tr><td rowspan="2"></td><td colspan="6">2021</td></tr><tr><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Change in benefit obligation</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Benefit obligation at beginning of year</td><td>$1,948</td><td>$463</td><td>$699</td><td>$81</td><td>$12</td><td>$248</td></tr><tr><td>Service cost</td><td>24</td><td>6</td><td>7</td><td>1</td><td>—</td><td>2</td></tr><tr><td>Interest cost</td><td>35</td><td>9</td><td>12</td><td>1</td><td>—</td><td>4</td></tr><tr><td>Benefits paid</td><td>(105)</td><td>(22)</td><td>(36)</td><td>(5)</td><td>—</td><td>(18)</td></tr><tr><td>Actuarial (gain) loss</td><td>(54)</td><td>(16)</td><td>(26)</td><td>(2)</td><td>(1)</td><td>1</td></tr><tr><td>Retiree drug subsidy</td><td>1</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Balance at end of year</td><td>1,849</td><td>440</td><td>656</td><td>76</td><td>11</td><td>237</td></tr><tr><td>Change in plan assets</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Fair value of plan assets at beginning of year</td><td>1,158</td><td>458</td><td>427</td><td>27</td><td>—</td><td>128</td></tr><tr><td>Actual return on plan assets</td><td>154</td><td>55</td><td>55</td><td>4</td><td>—</td><td>18</td></tr><tr><td>Employer contributions</td><td>43</td><td>(2)</td><td>4</td><td>3</td><td>—</td><td>15</td></tr><tr><td>Benefits paid</td><td>(104)</td><td>(22)</td><td>(36)</td><td>(5)</td><td>—</td><td>(18)</td></tr><tr><td>Fair value of plan assets at end of year</td><td>1,251</td><td>489</td><td>450</td><td>29</td><td>—</td><td>143</td></tr><tr><td>Accrued asset (liability)</td><td>$ (598)</td><td>$ 49</td><td>$ (206)</td><td>$ (47)</td><td>$ (11)</td><td>$ (94)</td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="6">2020</td></tr><tr><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Change in benefit obligation</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Benefit obligation at beginning of year</td><td>$1,985</td><td>$462</td><td>$742</td><td>$ 87</td><td>$ 11</td><td>$ 250</td></tr><tr><td>Service cost</td><td>22</td><td>6</td><td>6</td><td>1</td><td>1</td><td>2</td></tr><tr><td>Interest cost</td><td>54</td><td>13</td><td>20</td><td>2</td><td>—</td><td>7</td></tr><tr><td>Benefits paid</td><td>(126)</td><td>(29)</td><td>(46)</td><td>(6)</td><td>—</td><td>(17)</td></tr><tr><td>Actuarial (gain) loss</td><td>7</td><td>9</td><td>(26)</td><td>(3)</td><td>—</td><td>6</td></tr><tr><td>Retiree drug subsidy</td><td>6</td><td>2</td><td>3</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Balance at end of year</td><td>1,948</td><td>463</td><td>699</td><td>81</td><td>12</td><td>248</td></tr><tr><td>Change in plan assets</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Fair value of plan assets at beginning of year</td><td>1,061</td><td>413</td><td>403</td><td>26</td><td>—</td><td>115</td></tr><tr><td>Actual return on plan assets</td><td>145</td><td>60</td><td>50</td><td>3</td><td>—</td><td>18</td></tr><tr><td>Employer contributions</td><td>72</td><td>12</td><td>17</td><td>4</td><td>—</td><td>12</td></tr><tr><td>Benefits paid</td><td>(120)</td><td>(27)</td><td>(43)</td><td>(6)</td><td>—</td><td>(17)</td></tr><tr><td>Fair value of plan assets at end of year</td><td>1,158</td><td>458</td><td>427</td><td>27</td><td>—</td><td>128</td></tr><tr><td>Accrued liability</td><td>$ (790)</td><td>$ (5)</td><td>$ (272)</td><td>$ (54)</td><td>$ (12)</td><td>$ (120)</td></tr></table>



Amounts recognized in the balance sheets at December 31, 2021 and 2020 related to the Registrants' other postretirement benefit plans consist of the following:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>December 31, 2021:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Prepaid other postretirement benefit costs \( ^{(a)} \)</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Other regulatory assets, deferred \( ^{(b)} \)</td><td>97</td><td>-</td><td>30</td><td>2</td><td>-</td><td>-</td></tr><tr><td>Other current liabilities</td><td>(5)</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Employee benefit obligations \( ^{(c)} \)</td><td>(593)</td><td>-</td><td>(206)</td><td>(47)</td><td>(11)</td><td>(94)</td></tr><tr><td>Other regulatory liabilities, deferred</td><td>(171)</td><td>(62)</td><td>(40)</td><td>(1)</td><td>-</td><td>(34)</td></tr><tr><td>AOCI</td><td>-</td><td>-</td><td>-</td><td>-</td><td>2</td><td>(5)</td></tr><tr><td>December 31, 2020:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other regulatory assets, deferred \( ^{(b)} \)</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Other current liabilities</td><td>(5)</td><td>-</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>Employee benefit obligations \( ^{(c)} \)</td><td>(785)</td><td>(5)</td><td>(272)</td><td>(54)</td><td>(12)</td><td>(120)</td></tr><tr><td>Other regulatory liabilities, deferred</td><td>(86)</td><td>(21)</td><td>-</td><td>-</td><td>-</td><td>-</td></tr><tr><td>AOCI</td><td>8</td><td>-</td><td>-</td><td>-</td><td>3</td><td>-</td></tr></table>

(a) Included in prepaid pension and other postretirement benefit costs on Alabama Power's balance sheet.

(b) Amounts for Southern Company exclude regulatory assets of $40 million and $47 million at December 31, 2021 and 2020, respectively, associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company.

(c) Included in other deferred credits and liabilities on Southern Power's consolidated balance sheets.

Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2021 and 2020 related to the other postretirement benefit plans of Southern Company, the traditional electric operating companies, and Southern Company Gas that had not yet been recognized in net periodic other postretirement benefit cost.

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Balance at December 31, 2021:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Regulatory assets (liabilities):</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Prior service cost</td><td>$ 13</td><td>$ 3</td><td>$ 5</td><td>$ 1</td><td>$ 1</td></tr><tr><td>Net gain</td><td>(87)</td><td>(65)</td><td>(15)</td><td>—</td><td>(51)</td></tr><tr><td>Regulatory amortization</td><td>—</td><td>—</td><td>—</td><td>—</td><td>16</td></tr><tr><td>Total regulatory assets (liabilities) \( ^{(1)} \)</td><td>$(74)</td><td>$ (62)</td><td>$(10)</td><td>$ 1</td><td>$(34)</td></tr><tr><td>Balance at December 31, 2020:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Regulatory assets (liabilities):</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Prior service cost</td><td>$ 12</td><td>$ 3</td><td>$ 5</td><td>$—</td><td>$ 1</td></tr><tr><td>Net (gain) loss</td><td>39</td><td>(24)</td><td>42</td><td>5</td><td>(49)</td></tr><tr><td>Regulatory amortization</td><td>—</td><td>—</td><td>—</td><td>—</td><td>25</td></tr><tr><td>Total regulatory assets (liabilities) \( ^{(1)} \)</td><td>$ 51</td><td>$ (21)</td><td>$ 47</td><td>$ 5</td><td>$(23)</td></tr></table>

(*) Amounts for Southern Company exclude regulatory assets of $40 million and $47 million at December 31, 2021 and 2020, respectively, associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company.



The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2021 and 2020 are presented in the following table:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Net regulatory assets (liabilities):(1)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Balance at December 31, 2019</td><td>$ 121</td><td>$ 1</td><td>$ 96</td><td>$ 10</td><td>$ (11)</td></tr><tr><td>Net gain</td><td>(65)</td><td>(22)</td><td>(47)</td><td>(5)</td><td>(5)</td></tr><tr><td>Reclassification adjustments:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Amortization of prior service costs</td><td>1</td><td>—</td><td>1</td><td>—</td><td>—</td></tr><tr><td>Amortization of net loss</td><td>(6)</td><td>—</td><td>(3)</td><td>—</td><td>—</td></tr><tr><td>Amortization of regulatory assets(1)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(7)</td></tr><tr><td>Total reclassification adjustments</td><td>(5)</td><td>—</td><td>(2)</td><td>—</td><td>(7)</td></tr><tr><td>Total change</td><td>(70)</td><td>(22)</td><td>(49)</td><td>(5)</td><td>(12)</td></tr><tr><td>Balance at December 31, 2020</td><td>$ 51</td><td>$ (21)</td><td>$ 47</td><td>$ 5</td><td>$ (23)</td></tr><tr><td>Net gain</td><td>(120)</td><td>(41)</td><td>(55)</td><td>(4)</td><td>(2)</td></tr><tr><td>Reclassification adjustments:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Amortization of prior service costs</td><td>1</td><td>—</td><td>1</td><td>—</td><td>—</td></tr><tr><td>Amortization of net loss</td><td>(6)</td><td>—</td><td>(3)</td><td>—</td><td>—</td></tr><tr><td>Amortization of regulatory assets(1)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(9)</td></tr><tr><td>Total reclassification adjustments</td><td>(5)</td><td>—</td><td>(2)</td><td>—</td><td>(9)</td></tr><tr><td>Total change</td><td>(125)</td><td>(41)</td><td>(57)</td><td>(4)</td><td>(11)</td></tr><tr><td>Balance at December 31, 2021</td><td>$ (74)</td><td>$ (62)</td><td>$ (10)</td><td>$ 1</td><td>$ (34)</td></tr></table>

(*) Amounts for Southern Company exclude regulatory assets of $40 million and $47 million at December 31, 2021 and 2020, respectively, associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company.

Presented below are the amounts included in AOCI at December 31, 2021 and 2020 related to the other postretirement benefit plans of Southern Company, Southern Power, and Southern Company Gas that had not yet been recognized in net periodic other postretirement benefit cost.

<table><tr><td></td><td>Southern Company</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td>(in millions)</td><td></td></tr><tr><td>Balance at December 31, 2021</td><td></td><td></td><td></td></tr><tr><td>AOCI:</td><td></td><td></td><td></td></tr><tr><td>Prior service cost</td><td>$ 1</td><td>$ —</td><td>$ 1</td></tr><tr><td>Net (gain) loss</td><td>(1)</td><td>2</td><td>(6)</td></tr><tr><td>Total AOCI</td><td>$ —</td><td>$ 2</td><td>$ (5)</td></tr><tr><td>Balance at December 31, 2020</td><td></td><td></td><td></td></tr><tr><td>AOCI:</td><td></td><td></td><td></td></tr><tr><td>Prior service cost</td><td>$ 1</td><td>$ —</td><td>$ 1</td></tr><tr><td>Net (gain) loss</td><td>7</td><td>3</td><td>(1)</td></tr><tr><td>Total AOCI</td><td>$ 8</td><td>$ 3</td><td>$ —</td></tr></table>



The components of OCI related to the other postretirement benefit plans for the plan years ended December 31, 2021 and 2020 are presented in the following table:

<table><tr><td></td><td>Southern Company</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td colspan="3">(in millions)</td></tr><tr><td>AOCI:</td><td></td><td></td><td></td></tr><tr><td>Balance at December 31, 2019</td><td>$ 2</td><td>$ 2</td><td>$ (4)</td></tr><tr><td>Net loss</td><td>2</td><td>1</td><td>—</td></tr><tr><td>Reclassification adjustments:</td><td></td><td></td><td></td></tr><tr><td>Amortization of net gain (loss)</td><td>4</td><td>—</td><td>4</td></tr><tr><td>Total change</td><td>6</td><td>1</td><td>4</td></tr><tr><td>Balance at December 31, 2020</td><td>$ 8</td><td>$ 3</td><td>$ —</td></tr><tr><td>Net gain</td><td>(11)</td><td>(1)</td><td>—</td></tr><tr><td>Reclassification adjustments:</td><td></td><td></td><td></td></tr><tr><td>Amortization of net gain (loss)</td><td>3</td><td>—</td><td>(5)</td></tr><tr><td>Total change</td><td>(8)</td><td>(1)</td><td>(5)</td></tr><tr><td>Balance at December 31, 2021</td><td>$ —</td><td>$ 2</td><td>$ (5)</td></tr></table>

Components of the other postretirement benefit plans' net periodic cost for the Registrants were as follows:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>2021</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Service cost</td><td>$ 24</td><td>$ 6</td><td>$ 7</td><td>$ 1</td><td>$ —</td><td>$ 2</td></tr><tr><td>Interest cost</td><td>35</td><td>9</td><td>12</td><td>1</td><td>—</td><td>4</td></tr><tr><td>Expected return on plan assets</td><td>(76)</td><td>(30)</td><td>(26)</td><td>(1)</td><td>1</td><td>(10)</td></tr><tr><td>Net amortization</td><td>2</td><td>—</td><td>2</td><td>—</td><td>—</td><td>6</td></tr><tr><td>Net periodic postretirement benefit cost (income)</td><td>$ (15)</td><td>$ (15)</td><td>$ (5)</td><td>$ 1</td><td>$ 1</td><td>$ 2</td></tr><tr><td>2020</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Service cost</td><td>$ 22</td><td>$ 6</td><td>$ 6</td><td>$ 1</td><td>$ 1</td><td>$ 2</td></tr><tr><td>Interest cost</td><td>54</td><td>13</td><td>20</td><td>2</td><td>—</td><td>7</td></tr><tr><td>Expected return on plan assets</td><td>(72)</td><td>(29)</td><td>(26)</td><td>(1)</td><td>—</td><td>(10)</td></tr><tr><td>Net amortization</td><td>1</td><td>—</td><td>2</td><td>—</td><td>—</td><td>6</td></tr><tr><td>Net periodic postretirement benefit cost (income)</td><td>$ 5</td><td>$ (10)</td><td>$ 2</td><td>$ 2</td><td>$ 1</td><td>$ 5</td></tr><tr><td>2019</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Service cost</td><td>$ 18</td><td>$ 5</td><td>$ 5</td><td>$ 1</td><td>$ 1</td><td>$ 1</td></tr><tr><td>Interest cost</td><td>69</td><td>16</td><td>26</td><td>3</td><td>—</td><td>9</td></tr><tr><td>Expected return on plan assets</td><td>(65)</td><td>(26)</td><td>(25)</td><td>(2)</td><td>—</td><td>(7)</td></tr><tr><td>Net amortization</td><td>—</td><td>4</td><td>1</td><td>—</td><td>—</td><td>6</td></tr><tr><td>Net periodic postretirement benefit cost (income)</td><td>$ 22</td><td>$ (1)</td><td>$ 7</td><td>$ 2</td><td>$ 1</td><td>$ 9</td></tr></table>



The service cost component of net periodic postretirement benefit cost is included in operations and maintenance expenses and all other components of net periodic postretirement benefit cost are included in other income (expense), net in the Registrants' statements of income.

The Registrants’ future benefit payments, including prescription drug benefits, are provided in the table below. These amounts reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans.

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Benefit payments:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2022</td><td>$ 111</td><td>$ 24</td><td>$ 40</td><td>$ 5</td><td>$ —</td><td>$ 17</td></tr><tr><td>2023</td><td>110</td><td>24</td><td>39</td><td>5</td><td>—</td><td>17</td></tr><tr><td>2024</td><td>109</td><td>24</td><td>38</td><td>5</td><td>—</td><td>18</td></tr><tr><td>2025</td><td>112</td><td>25</td><td>40</td><td>5</td><td>1</td><td>17</td></tr><tr><td>2026</td><td>112</td><td>25</td><td>40</td><td>5</td><td>1</td><td>17</td>
The image is too blurry to be recognized.
2027 to 2031
552
128
199
22
3
75
Benefit Plan Assets
Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Registrants’ investment policies for both the pension plans and the other postretirement benefit plans cover a diversified mix of assets as described below. Derivative instruments may be used to gain efficient exposure to the various asset classes and as hedging tools. Additionally, the Registrants minimize the risk of large losses primarily through diversification but also monitor and manage other aspects of risk.
The investment strategy for plan assets related to the Southern Company system’s qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Southern Company system employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Management believes the portfolio is well-diversified with no significant concentrations of risk.
Southern Company’s investment strategy also includes adjusting the established asset allocation to invest a larger portion of the portfolio in fixed rate debt securities should the qualified pension plan achieve a predetermined funding threshold. Any future reallocation of plan assets based on achieving the funding threshold would likely result in a reduction in the expected long-term return on plan assets used to determine pension income. However, the amount of such a decrease and the related financial statement impact cannot be determined at this time.</td></tr></table>

## Benefit Plan Assets

Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Registrants’ investment policies for both the pension plans and the other postretirement benefit plans cover a diversified mix of assets as described below. Derivative instruments may be used to gain efficient exposure to the various asset classes and as hedging tools. Additionally, the Registrants minimize the risk of large losses primarily through diversification but also monitor and manage other aspects of risk.

The investment strategy for plan assets related to the Southern Company system’s qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Southern Company system employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Management believes the portfolio is well-diversified with no significant concentrations of risk.

Southern Company’s investment strategy also includes adjusting the established asset allocation to invest a larger portion of the portfolio in fixed rate debt securities should the qualified pension plan achieve a predetermined funding threshold. Any future reallocation of plan assets based on achieving the funding threshold would likely result in a reduction in the expected long-term return on plan assets used to determine pension income. However, the amount of such a decrease and the related financial statement impact cannot be determined at this time.



## Investment Strategies and Benefit Plan Asset Fair Values

A description of the major asset classes that the pension and other postretirement benefit plans are comprised of, along with the valuation methods used for fair value measurement, is provided below:

<table><tr><td>Description</td><td>Valuation Methodology</td></tr><tr><td>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.</td><td>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.</td></tr><tr><td>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.</td><td>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.</td></tr><tr><td>Fixed income: A mix of domestic and international bonds.</td><td>Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy&#x27;s separate accounts. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities.</td></tr><tr><td>Trust-owned life insurance (TOLI): Investments of taxable trusts aimed at minimizing the impact of taxes on the portfolio.</td><td>Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy&#x27;s separate accounts. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities.</td></tr><tr><td>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.</td><td>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.</td></tr><tr><td>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.</td><td>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.</td></tr><tr><td>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.</td><td>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.</td></tr></table>

For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. The fair values presented herein exclude cash, receivables related to investment income and pending investment sales, and payables related to pending investment purchases. The Registrants did not have any investments classified as Level 3 at December 31, 2020.



Fair Value Measurements Using

<table><tr><td rowspan="2">At December 31, 2021:</td><td colspan="2">Fair Value Measurements Using</td><td rowspan="2">Net Asset Value as a Practical Expedient (NAV)</td><td rowspan="2">Total</td><td rowspan="2">Target Allocation</td><td rowspan="2">Actual Allocation</td></tr><tr><td>Quoted Prices in Active Markets for Identical Assets (Level 1)</td><td>Significant Other Observable Inputs (Level 2)</td></tr><tr><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td><td></td></tr><tr><td>Mississippi Power</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td></td><td>51%</td></tr><tr><td>Domestic equity</td><td>$142</td><td>$ 61</td><td>$—</td><td>$ —</td><td>$ 203</td><td></td></tr><tr><td>International equity</td><td>126</td><td>64</td><td>—</td><td>—</td><td>190</td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td></td><td>23</td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>55</td><td>—</td><td>—</td><td>55</td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>80</td><td>—</td><td>—</td><td>80</td><td></td></tr><tr><td>Pooled funds</td><td>—</td><td>35</td><td>—</td><td>—</td><td>35</td><td></td></tr><tr><td>Cash equivalents and other</td><td>18</td><td>—</td><td>—</td><td>—</td><td>18</td><td></td></tr><tr><td>Real estate investments</td><td>32</td><td>—</td><td>—</td><td>93</td><td>125</td><td>14</td></tr><tr><td>Special situations</td><td>—</td><td>—</td><td>—</td><td>8</td><td>8</td><td>3</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>—</td><td>73</td><td>73</td><td>9</td></tr><tr><td>Total</td><td>$318</td><td>$295</td><td>$—</td><td>$174</td><td>$ 787</td><td>100%</td></tr><tr><td>Southern Power</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td></td><td>51%</td></tr><tr><td>Domestic equity</td><td>$ 38</td><td>$ 16</td><td>$—</td><td>$ —</td><td>$ 54</td><td></td></tr><tr><td>International equity</td><td>34</td><td>17</td><td>—</td><td>—</td><td>51</td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td></td><td>23</td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>15</td><td>—</td><td>—</td><td>15</td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>22</td><td>—</td><td>—</td><td>22</td><td></td></tr><tr><td>Pooled funds</td><td>—</td><td>10</td><td>—</td><td>—</td><td>10</td><td></td></tr><tr><td>Cash equivalents and other</td><td>5</td><td>—</td><td>—</td><td>—</td><td>5</td><td></td></tr><tr><td>Real estate investments</td><td>9</td><td>—</td><td>—</td><td>25</td><td>34</td><td>14</td></tr><tr><td>Special situations</td><td>—</td><td>—</td><td>—</td><td>2</td><td>2</td><td>3</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>—</td><td>20</td><td>20</td><td>9</td></tr><tr><td>Total</td><td>$ 86</td><td>$ 80</td><td>$—</td><td>$ 47</td><td>$ 213</td><td>100%</td></tr><tr><td>Southern Company Gas</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td></td><td>51%</td></tr><tr><td>Domestic equity</td><td>$223</td><td>$ 96</td><td>$—</td><td>$ —</td><td>$ 319</td><td></td></tr><tr><td>International equity</td><td>197</td><td>101</td><td>—</td><td>—</td><td>298</td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td></td><td>23</td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>87</td><td>—</td><td>—</td><td>87</td><td></td></tr><tr><td>Mortgage- and asset-backed securities</td><td>—</td><td>1</td><td>—</td><td>—</td><td>1</td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>126</td><td>—</td><td>—</td><td>126</td><td></td></tr><tr><td>Pooled funds</td><td>—</td><td>56</td><td>—</td><td>—</td><td>56</td><td></td></tr><tr><td>Cash equivalents and other</td><td>29</td><td>—</td><td>—</td><td>—</td><td>29</td><td></td></tr><tr><td>Real estate investments</td><td>51</td><td>—</td><td>—</td><td>147</td><td>198</td><td>14</td></tr><tr><td>Special situations</td><td>—</td><td>—</td><td>—</td><td>12</td><td>12</td><td>3</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>—</td><td>115</td><td>115</td><td>9</td></tr><tr><td>Total</td><td>$500</td><td>$467</td><td>$—</td><td>$274</td><td>$1,241</td><td>100%</td></tr></table>



Fair Value Measurements Using

<table><tr><td rowspan="2">At December 31, 2020:</td><td colspan="2">Quoted Prices in Active Markets for Identical Assets (Level 1)</td><td rowspan="2">Significant Other Observable Inputs (Level 2)</td><td rowspan="2">Net Asset Value as a Practical Expedient (NAV)</td><td rowspan="2">Total</td><td rowspan="2">Target Allocation</td><td rowspan="2">Actual Allocation</td></tr><tr><td colspan="2">(in millions)</td></tr><tr><td>Southern Company</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Domestic equity</td><td>$2,852</td><td>$1,247</td><td>$</td><td>—</td><td>$4,099</td><td></td><td>51%</td></tr><tr><td>International equity</td><td>2,660</td><td>1,497</td><td></td><td>—</td><td>4,157</td><td></td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td></td><td>23</td><td>23</td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>951</td><td></td><td>—</td><td>951</td><td></td><td></td></tr><tr><td>Mortgage- and asset-backed securities</td><td>—</td><td>9</td><td></td><td>—</td><td>9</td><td></td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>1,673</td><td></td><td>—</td><td>1,673</td><td></td><td></td></tr><tr><td>Pooled funds</td><td>—</td><td>772</td><td></td><td>—</td><td>772</td><td></td><td></td></tr><tr><td>Cash equivalents and other</td><td>356</td><td>5</td><td></td><td>—</td><td>361</td><td></td><td></td></tr><tr><td>Real estate investments</td><td>542</td><td>—</td><td>1,596</td><td>2,138</td><td>14</td><td>13</td><td></td></tr><tr><td>Special situations</td><td>—</td><td>—</td><td>166</td><td>166</td><td>3</td><td>1</td><td></td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>1,104</td><td>1,104</td><td>9</td><td>7</td><td></td></tr><tr><td>Total</td><td>$6,410</td><td>$6,154</td><td>$2,866</td><td>$15,430</td><td>100%</td><td>100%</td><td></td></tr><tr><td>Alabama Power</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td></td><td>51%</td><td>56%</td></tr><tr><td>Domestic equity</td><td>$685</td><td>$299</td><td>$</td><td>—</td><td>$984</td><td></td><td></td></tr><tr><td>International equity</td><td>638</td><td>359</td><td></td><td>—</td><td>997</td><td></td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td></td><td>23</td><td>23</td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>228</td><td></td><td>—</td><td>228</td><td></td><td></td></tr><tr><td>Mortgage- and asset-backed securities</td><td>—</td><td>2</td><td></td><td>—</td><td>2</td><td></td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>401</td><td></td><td>—</td><td>401</td><td></td><td></td></tr><tr><td>Pooled funds</td><td>—</td><td>185</td><td></td><td>—</td><td>185</td><td></td><td></td></tr><tr><td>Cash equivalents and other</td><td>85</td><td>1</td><td></td><td>—</td><td>86</td><td></td><td></td></tr><tr><td>Real estate investments</td><td>130</td><td>—</td><td>382</td><td>512</td><td>14</td><td>13</td><td></td></tr><tr><td>Special situations</td><td>—</td><td>—</td><td>40</td><td>40</td><td>3</td><td>1</td><td></td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>264</td><td>264</td><td>9</td><td>7</td><td></td></tr><tr><td>Total</td><td>$1,538</td><td>$1,475</td><td>$686</td><td>$3,699</td><td>100%</td><td>100%</td><td></td></tr><tr><td>Georgia Power</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td></td><td>51%</td><td>56%</td></tr><tr><td>Domestic equity</td><td>$899</td><td>$393</td><td>$</td><td>—</td><td>$1,292</td><td></td><td></td></tr><tr><td>International equity</td><td>839</td><td>472</td><td></td><td>—</td><td>1,311</td><td></td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td></td><td>23</td><td>23</td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>300</td><td></td><td>—</td><td>300</td><td></td><td></td></tr><tr><td>Mortgage- and asset-backed securities</td><td>—</td><td>3</td><td></td><td>—</td><td>3</td><td></td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>527</td><td></td><td>—</td><td>527</td><td></td><td></td></tr><tr><td>Pooled funds</td><td>—</td><td>243</td><td></td><td>—</td><td>243</td><td></td><td></td></tr><tr><td>Cash equivalents and other</td><td>112</td><td>1</td><td></td><td>—</td><td>113</td><td></td><td></td></tr><tr><td>Real estate investments</td><td>171</td><td>—</td><td>503</td><td>674</td><td>14</td><td>13</td><td></td></tr><tr><td>Special situations</td><td>—</td><td>—</td><td>53</td><td>53</td><td>3</td><td>1</td><td></td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>348</td><td>348</td><td>9</td><td>7</td><td></td></tr><tr><td>Total</td><td>$2,021</td><td>$1,939</td><td>$904</td><td>$4,864</td><td>100%</td><td>100%</td><td></td></tr></table>



Fair Value Measurements Using

<table><tr><td rowspan="2">At December 31, 2020:</td><td colspan="6">Fair Value Measurements Using</td></tr><tr><td>Quoted Prices in Active Markets for Identical Assets (Level 1)</td><td>Significant Other Observable Inputs (Level 2)</td><td>Net Asset Value as a Practical Expedient (NAV)</td><td>Total</td><td>Target Allocation</td><td>Actual Allocation</td></tr><tr><td></td><td colspan="6">(in millions)</td></tr><tr><td>Mississippi Power</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td></td><td>51%</td></tr><tr><td>Domestic equity</td><td>$131</td><td>$ 57</td><td>$ —</td><td>$ 188</td><td></td><td></td></tr><tr><td>International equity</td><td>122</td><td>68</td><td>—</td><td>190</td><td></td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td>23</td><td>23</td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>43</td><td>—</td><td>43</td><td></td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>76</td><td>—</td><td>76</td><td></td><td></td></tr><tr><td>Pooled funds</td><td>—</td><td>35</td><td>—</td><td>35</td><td></td><td></td></tr><tr><td>Cash equivalents and other</td><td>16</td><td>—</td><td>—</td><td>16</td><td></td><td></td></tr><tr><td>Real estate investments</td><td>25</td><td>—</td><td>73</td><td>98</td><td>14</td><td>13</td></tr><tr><td>Special situations</td><td>—</td><td>—</td><td>8</td><td>8</td><td>3</td><td>1</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>50</td><td>50</td><td>9</td><td>7</td></tr><tr><td>Total</td><td>$294</td><td>$279</td><td>$131</td><td>$ 704</td><td>100%</td><td>100%</td></tr><tr><td>Southern Power</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td></td><td>51%</td></tr><tr><td>Domestic equity</td><td>$ 35</td><td>$ 15</td><td>$ —</td><td>$ 50</td><td></td><td></td></tr><tr><td>International equity</td><td>32</td><td>19</td><td>—</td><td>51</td><td></td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td>23</td><td>23</td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>12</td><td>—</td><td>12</td><td></td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>20</td><td>—</td><td>20</td><td></td><td></td></tr><tr><td>Pooled funds</td><td>—</td><td>9</td><td>—</td><td>9</td><td></td><td></td></tr><tr><td>Cash equivalents and other</td><td>4</td><td>—</td><td>—</td><td>4</td><td></td><td></td></tr><tr><td>Real estate investments</td><td>7</td><td>—</td><td>19</td><td>26</td><td>14</td><td>13</td></tr><tr><td>Special situations</td><td>—</td><td>—</td><td>2</td><td>2</td><td>3</td><td>1</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>13</td><td>13</td><td>9</td><td>7</td></tr><tr><td>Total</td><td>$ 78</td><td>$ 75</td><td>$ 34</td><td>$ 187</td><td>100%</td><td>100%</td></tr><tr><td>Southern Company Gas</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td></td><td>51%</td></tr><tr><td>Domestic equity</td><td>$209</td><td>$ 91</td><td>$ —</td><td>$ 300</td><td></td><td></td></tr><tr><td>International equity</td><td>195</td><td>109</td><td>—</td><td>304</td><td></td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td>23</td><td>23</td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>69</td><td>—</td><td>69</td><td></td><td></td></tr><tr><td>Mortgage- and asset-backed securities</td><td>—</td><td>1</td><td>—</td><td>1</td><td></td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>122</td><td>—</td><td>122</td><td></td><td></td></tr><tr><td>Pooled funds</td><td>—</td><td>56</td><td>—</td><td>56</td><td></td><td></td></tr><tr><td>Cash equivalents and other</td><td>26</td><td>—</td><td>—</td><td>26</td><td></td><td></td></tr><tr><td>Real estate investments</td><td>40</td><td>—</td><td>117</td><td>157</td><td>14</td><td>13</td></tr><tr><td>Special situations</td><td>—</td><td>—</td><td>12</td><td>12</td><td>3</td><td>1</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>81</td><td>81</td><td>9</td><td>7</td></tr><tr><td>Total</td><td>$470</td><td>$448</td><td>$210</td><td>$1,128</td><td>100%</td><td>100%</td></tr></table>



The fair values, and actual allocations relative to the target allocations, of the applicable Registrants' other postretirement benefit plan assets at December 31, 2021 and 2020 are presented below.

Fair Value Measurements Using

<table><tr><td>At December 31, 2021:</td><td>Quoted Prices in Active Markets for Identical Assets (Level 1)</td><td>Significant Other Observable Inputs (Level 2)</td><td>Net Asset Value as a Practical Expedient (NAV)</td><td>Total</td><td>Target Allocation</td><td>Actual Allocation</td></tr><tr><td>Southern Company</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td>64%</td><td>66%</td></tr><tr><td>Domestic equity</td><td>$123</td><td>$112</td><td>$ —</td><td>$ 235</td><td></td><td></td></tr><tr><td>International equity</td><td>73</td><td>99</td><td>—</td><td>172</td><td></td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td>27</td><td>25</td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>37</td><td>—</td><td>37</td><td></td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>50</td><td>—</td><td>50</td><td></td><td></td></tr><tr><td>Pooled funds</td><td>—</td><td>90</td><td>—</td><td>90</td><td></td><td></td></tr><tr><td>Cash equivalents and other</td><td>14</td><td>—</td><td>—</td><td>14</td><td></td><td></td></tr><tr><td>Trust-owned life insurance</td><td>—</td><td>530</td><td>—</td><td>530</td><td></td><td></td></tr><tr><td>Real estate investments</td><td>20</td><td>—</td><td>54</td><td>74</td><td>5</td><td>6</td></tr><tr><td>Special situations</td><td>—</td><td>—</td><td>5</td><td>5</td><td>1</td><td>—</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>42</td><td>42</td><td>3</td><td>3</td></tr><tr><td>Total</td><td>$230</td><td>$918</td><td>$101</td><td>$1,249</td><td>100%</td><td>100%</td></tr><tr><td>Alabama Power</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td>71%</td><td>69%</td></tr><tr><td>Domestic equity</td><td>$ 26</td><td>$ 11</td><td>$ —</td><td>$ 37</td><td></td><td></td></tr><tr><td>International equity</td><td>23</td><td>12</td><td>—</td><td>35</td><td></td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td>21</td><td>21</td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>10</td><td>—</td><td>10</td><td></td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>18</td><td>—</td><td>18</td><td></td><td></td></tr><tr><td>Pooled funds</td><td>—</td><td>6</td><td>—</td><td>6</td><td></td><td></td></tr><tr><td>Cash equivalents and other</td><td>3</td><td>—</td><td>—</td><td>3</td><td></td><td></td></tr><tr><td>Trust-owned life insurance</td><td>—</td><td>341</td><td>—</td><td>341</td><td></td><td></td></tr><tr><td>Real estate investments</td><td>6</td><td>—</td><td>17</td><td>23</td><td>4</td><td>7</td></tr><tr><td>Special situations</td><td>—</td><td>—</td><td>2</td><td>2</td><td>1</td><td>—</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>13</td><td>13</td><td>3</td><td>3</td></tr><tr><td>Total</td><td>$ 58</td><td>$398</td><td>$ 32</td><td>$ 488</td><td>100%</td><td>100%</td></tr><tr><td>Georgia Power</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td>60%</td><td>62%</td></tr><tr><td>Domestic equity</td><td>$ 65</td><td>$ 13</td><td>$ —</td><td>$ 78</td><td></td><td></td></tr><tr><td>International equity</td><td>22</td><td>50</td><td>—</td><td>72</td><td></td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td>33</td><td>30</td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>9</td><td>—</td><td>9</td><td></td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>14</td><td>—</td><td>14</td><td></td><td></td></tr><tr><td>Pooled funds</td><td>—</td><td>46</td><td>—</td><td>46</td><td></td><td></td></tr><tr><td>Cash equivalents and other</td><td>5</td><td>—</td><td>—</td><td>5</td><td></td><td></td></tr><tr><td>Trust-owned life insurance</td><td>—</td><td>189</td><td>—</td><td>189</td><td></td><td></td></tr><tr><td>Real estate investments</td><td>7</td><td>—</td><td>16</td><td>23</td><td>4</td><td>5</td></tr><tr><td>Special situations</td><td>—</td><td>—</td><td>1</td><td>1</td><td>1</td><td>—</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>13</td><td>13</td><td>2</td><td>3</td></tr><tr><td>Total</td><td>$ 99</td><td>$321</td><td>$ 30</td><td>$ 450</td><td>100%</td><td>100%</td></tr></table>



Fair Value Measurements Using

<table><tr><td rowspan="2">At December 31, 2021:</td><td colspan="2">Fair Value Measurements Using</td><td rowspan="2">Total</td><td rowspan="2">Target Allocation</td><td rowspan="2">Actual Allocation</td></tr><tr><td>Quoted Prices in Active Markets for Identical Assets (Level 1)</td><td>Significant Other Observable Inputs (Level 2)</td></tr><tr><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>Mississippi Power</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td>43%</td></tr><tr><td>Domestic equity</td><td>$ 4</td><td>$ 2</td><td>$—</td><td>$ 6</td><td></td></tr><tr><td>International equity</td><td>4</td><td>2</td><td>—</td><td>6</td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td>36</td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>5</td><td>—</td><td>5</td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>2</td><td>—</td><td>2</td><td></td></tr><tr><td>Pooled funds</td><td>—</td><td>1</td><td>—</td><td>1</td><td></td></tr><tr><td>Cash equivalents and other</td><td>1</td><td>—</td><td>—</td><td>1</td><td></td></tr><tr><td>Real estate investments</td><td>1</td><td>—</td><td>3</td><td>4</td><td>11</td></tr><tr><td>Special situations</td><td>—</td><td>—</td><td>—</td><td>2</td><td>1</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>2</td><td>2</td><td>8</td></tr><tr><td>Total</td><td>$10</td><td>$ 12</td><td>$ 5</td><td>$ 27</td><td>100%</td></tr><tr><td>Southern Company Gas</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td>72%</td></tr><tr><td>Domestic equity</td><td>$ 3</td><td>$ 76</td><td>$—</td><td>$ 79</td><td></td></tr><tr><td>International equity</td><td>2</td><td>24</td><td>—</td><td>26</td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td>26</td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>1</td><td>—</td><td>1</td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>1</td><td>—</td><td>1</td><td></td></tr><tr><td>Pooled funds</td><td>—</td><td>30</td><td>—</td><td>30</td><td></td></tr><tr><td>Cash equivalents and other</td><td>2</td><td>—</td><td>—</td><td>2</td><td></td></tr><tr><td>Real estate investments</td><td>1</td><td>—</td><td>2</td><td>3</td><td>1</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>1</td><td>1</td><td>1</td></tr><tr><td>Total</td><td>$ 8</td><td>$132</td><td>$ 3</td><td>$143</td><td>100%</td></tr></table>



Fair Value Measurements Using

<table><tr><td rowspan="2">At December 31, 2020:</td><td colspan="2">Fair Value Measurements Using</td><td rowspan="2">Total</td><td rowspan="2">Target Allocation</td><td rowspan="2">Actual Allocation</td></tr><tr><td>Quoted Prices in Active Markets for Identical Assets (Level 1)</td><td>Significant Other Observable Inputs (Level 2)</td></tr><tr><td></td><td>(in millions)</td><td></td><td></td><td></td><td></td></tr><tr><td>Southern Company</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td>63%</td></tr><tr><td>Domestic equity</td><td>$113</td><td>$ 98</td><td>$ —</td><td>$ 211</td><td></td></tr><tr><td>International equity</td><td>71</td><td>102</td><td>—</td><td>173</td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td>28</td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>32</td><td>—</td><td>32</td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>44</td><td>—</td><td>44</td><td></td></tr><tr><td>Pooled funds</td><td>—</td><td>86</td><td>—</td><td>86</td><td></td></tr><tr><td>Cash equivalents and other</td><td>15</td><td>—</td><td>—</td><td>15</td><td></td></tr><tr><td>Trust-owned life insurance</td><td>—</td><td>508</td><td>—</td><td>508</td><td></td></tr><tr><td>Real estate investments</td><td>15</td><td>—</td><td>42</td><td>57</td><td>5</td></tr><tr><td>Special situations</td><td>—</td><td>—</td><td>4</td><td>4</td><td>1</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>29</td><td>29</td><td>3</td></tr><tr><td>Total</td><td>$214</td><td>$870</td><td>$75</td><td>$1,159</td><td>100%</td></tr><tr><td>Alabama Power</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td>68%</td></tr><tr><td>Domestic equity</td><td>$ 26</td><td>$ 11</td><td>$ —</td><td>$ 37</td><td></td></tr><tr><td>International equity</td><td>23</td><td>13</td><td>—</td><td>36</td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td>24</td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>11</td><td>—</td><td>11</td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>14</td><td>—</td><td>14</td><td></td></tr><tr><td>Pooled funds</td><td>—</td><td>7</td><td>—</td><td>7</td><td></td></tr><tr><td>Cash equivalents and other</td><td>5</td><td>—</td><td>—</td><td>5</td><td></td></tr><tr><td>Trust-owned life insurance</td><td>—</td><td>321</td><td>—</td><td>321</td><td></td></tr><tr><td>Real estate investments</td><td>5</td><td>—</td><td>13</td><td>18</td><td>4</td></tr><tr><td>Special situations</td><td>—</td><td>—</td><td>1</td><td>1</td><td>1</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>9</td><td>9</td><td>3</td></tr><tr><td>Total</td><td>$ 59</td><td>$377</td><td>$23</td><td>$ 459</td><td>100%</td></tr><tr><td>Georgia Power</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td>60%</td></tr><tr><td>Domestic equity</td><td>$ 58</td><td>$ 10</td><td>$ —</td><td>$ 68</td><td></td></tr><tr><td>International equity</td><td>21</td><td>50</td><td>—</td><td>71</td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td>33</td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>8</td><td>—</td><td>8</td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>13</td><td>—</td><td>13</td><td></td></tr><tr><td>Pooled funds</td><td>—</td><td>46</td><td>—</td><td>46</td><td></td></tr><tr><td>Cash equivalents and other</td><td>5</td><td>—</td><td>—</td><td>5</td><td></td></tr><tr><td>Trust-owned life insurance</td><td>—</td><td>188</td><td>—</td><td>188</td><td></td></tr><tr><td>Real estate investments</td><td>5</td><td>—</td><td>13</td><td>18</td><td>4</td></tr><tr><td>Special situations</td><td>—</td><td>—</td><td>1</td><td>1</td><td>1</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>9</td><td>9</td><td>2</td></tr><tr><td>Total</td><td>$ 89</td><td>$315</td><td>$23</td><td>$ 427</td><td>100%</td></tr></table>



<table><tr><td rowspan="2"></td><td colspan="4">Fair Value Measurements Using</td><td rowspan="2">Total</td><td rowspan="2">Target Allocation</td><td rowspan="2">Actual Allocation</td></tr><tr><td>Quoted Prices in Active Markets for Identical Assets (Level 1)</td><td>Significant Other Observable Inputs (Level 2)</td><td>Net Asset Value as a Practical Expedient (NAV)</td><td></td></tr><tr><td>At December 31, 2020:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td><td></td></tr><tr><td>Mississippi Power</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td></td><td></td><td>43%</td></tr><tr><td>Domestic equity</td><td>$ 4</td><td>$ 2</td><td>$ —</td><td>$ 6</td><td></td><td></td><td></td></tr><tr><td>International equity</td><td>4</td><td>2</td><td>—</td><td>6</td><td></td><td></td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td></td><td>37</td><td>36</td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>5</td><td>—</td><td>5</td><td></td><td></td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>2</td><td>—</td><td>2</td><td></td><td></td><td></td></tr><tr><td>Pooled funds</td><td>—</td><td>1</td><td>—</td><td>1</td><td></td><td></td><td></td></tr><tr><td>Cash equivalents and other</td><td>1</td><td>—</td><td>—</td><td>1</td><td></td><td></td><td></td></tr><tr><td>Real estate investments</td><td>1</td><td>—</td><td>2</td><td>3</td><td>11</td><td>11</td><td></td></tr><tr><td>Special situations</td><td>—</td><td>—</td><td>—</td><td>2</td><td>2</td><td>1</td><td></td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>2</td><td>2</td><td>7</td><td>6</td><td></td></tr><tr><td>Total</td><td>$10</td><td>$ 12</td><td>$ 4</td><td>$ 26</td><td>100%</td><td>100%</td><td></td></tr><tr><td>Southern Company Gas</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity:</td><td></td><td></td><td></td><td></td><td></td><td>72%</td><td>76%</td></tr><tr><td>Domestic equity</td><td>$ 2</td><td>$ 66</td><td>$ —</td><td>$ 68</td><td></td><td></td><td></td></tr><tr><td>International equity</td><td>2</td><td>25</td><td>—</td><td>27</td><td></td><td></td><td></td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td>26</td><td>22</td><td></td></tr><tr><td>U.S. Treasury, government, and agency bonds</td><td>—</td><td>1</td><td>—</td><td>1</td><td></td><td></td><td></td></tr><tr><td>Corporate bonds</td><td>—</td><td>1</td><td>—</td><td>1</td><td></td><td></td><td></td><tr><td>Pooled funds</td><td>—</td><td>25</td><td>—</td><td>25</td><td></td><td></td><td></td></tr><tr><td>Cash equivalents and other</td><td>1</td><td>—</td><td>—</td><td>1</td><td></td><td></td><td></td></tr><tr><td>Real estate investments</td><td>—</td><td>—</td><td>1</td><td>1</td><td>1</td><td>1</td><td></td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>1</td><td>1</td><td>1</td><td>1</td><td></td><td></td></tr><tr><td>Total</td><td>$ 5</td><td>$118</td><td>$ 2</td><td>$125</td><td>100%</td><td>100%</td><td></td></tr></tr></table>

## Employee Savings Plan

Southern Company and its subsidiaries also sponsor 401(k) defined contribution plans covering substantially all employees and provide matching contributions up to specified percentages of an employee's eligible pay. Total matching contributions made to the plans for 2021, 2020, and 2019 were as follows:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>2021</td><td>$119</td><td>$26</td><td>$28</td><td>$5</td><td>$2</td><td>$16</td></tr><tr><td>2020</td><td>120</td><td>26</td><td>29</td><td>5</td><td>2</td><td>16</td></tr><tr><td>2019</td><td>113</td><td>25</td><td>27</td><td>4</td><td>2</td><td>15</td></tr></table>



## 12. STOCK COMPENSATION

Stock-based compensation primarily in the form of Southern Company performance share units (PSU) and restricted stock units (RSU) may be granted through the Equity and Incentive Compensation Plan to Southern Company system employees ranging from line management to executives.

At December 31, 2021, the number of current and former employees participating in stock-based compensation programs for the Registrants was as follows:

<table><tr><td></td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas</td></tr><tr><td>Number of employees</td><td>1,728</td><td>241</td><td>271</td><td>70</td><td>45</td><td>173</td></tr></table>

The majority of PSUs and RSUs awarded contain terms where employees become immediately vested in PSUs and RSUs upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately, while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. In addition, the Registrants recognize forfeitures as they occur.

All unvested PSUs and RSUs vest immediately upon a change in control where Southern Company is not the surviving corporation.

## Performance Share Units

PSUs granted to employees vest at the end of a three-year performance period. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of PSUs granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors.

Southern Company has issued three types of PSUs, each with a unique performance goal. These types of PSUs include total shareholder return (TSR) awards based on the TSR for Southern Company common stock during the three-year performance period as compared to a group of industry peers; ROE awards based on Southern Company's equity-weighted return over the performance period; and EPS awards based on Southern Company's cumulative EPS over the performance period. EPS awards were last granted in 2017.

The fair value of TSR awards is determined as of the grant date using a Monte Carlo simulation model. In determining the fair value of the TSR awards issued to employees, the expected volatility is based on the historical volatility of Southern Company's stock over a period equal to the performance period. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the awards. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of TSR awards granted:

<table><tr><td>Year Ended December 31</td><td>2021</td><td>2020</td><td>2019</td></tr><tr><td>Expected volatility</td><td>30.0%</td><td>15.4%</td><td>15.6%</td></tr><tr><td>Expected term (in years)</td><td>3</td><td>3</td><td>3</td></tr><tr><td>Interest rate</td><td>0.2%</td><td>1.4%</td><td>2.4%</td></tr><tr><td>Weighted average grant-date fair value</td><td>$69.06</td><td>$77.65</td><td>$62.71</td></tr></table>

The Registrants recognize TSR award compensation expense on a straight-line basis over the three-year performance period without remeasurement.

The fair values of EPS awards and ROE awards are based on the closing stock price of Southern Company common stock on the date of the grant. The weighted average grant-date fair value of the ROE awards granted during 2021, 2020, and 2019 was $59.49, $68.42, and $49.38, respectively. Compensation expense for EPS and ROE awards is generally recognized ratably over the three-year performance period adjusted for expected changes in EPS and ROE performance. Total compensation cost recognized for vested EPS awards and ROE awards reflects final performance metrics.

Southern Company had 2.2 million unvested PSUs outstanding at December 31, 2020. In February 2021, the PSUs that vested for the three-year performance period ended December 31, 2020 were converted into 2.5 million shares outstanding at a share price of $60.10. During 2021, Southern Company granted 1.3 million PSUs and 1.3 million PSUs were vested or forfeited, resulting in 2.2 million unvested PSUs outstanding at December 31, 2021. In February 2022, the PSUs that vested for the three-year performance period ended December 31, 2021 were converted into 2.5 million shares outstanding at a weighted average share price of $66.57.



Total PSU compensation cost, and the related tax benefit recognized in income, for the years ended December 31, 2021, 2020, and 2019 are as follows:

<table><tr><td></td><td>2021</td><td>2020</td><td>2019</td></tr><tr><td></td><td colspan="3">(in millions)</td></tr><tr><td>Southern Company</td><td></td><td></td><td></td></tr><tr><td>Compensation cost recognized in income</td><td>$112</td><td>$84</td><td>$77</td></tr><tr><td>Tax benefit of compensation cost recognized in income</td><td>29</td><td>22</td><td>20</td></tr><tr><td>Southern Company Gas</td><td></td><td></td><td></td></tr><tr><td>Compensation cost recognized in income</td><td>$17</td><td>$13</td><td>$14</td></tr><tr><td>Tax benefit of compensation cost recognized in income</td><td>4</td><td>4</td><td>4</td></tr></table>

Total PSU compensation cost and the related tax benefit recognized in income were immaterial for all periods presented for all other Registrants. The compensation cost related to the grant of Southern Company PSUs to the employees of each Subsidiary Registrant is recognized in each Subsidiary Registrant's financial statements with a corresponding credit to equity representing a capital contribution from Southern Company.

At December 31, 2021, Southern Company’s total unrecognized compensation cost related to PSUs was $32 million and is expected to be recognized over a weighted-average period of approximately 19 months. The total unrecognized compensation cost related to PSUs at December 31, 2021 was immaterial for all other Registrants.

## Restricted Stock Units

The fair value of RSUs is based on the closing stock price of Southern Company common stock on the date of the grant. The weighted average grant-date fair values of RSUs granted during 2021, 2020, and 2019 were $59.56, $67.60, and $50.44, respectively. For most RSU awards, one-third of the RSUs vest each year throughout a three-year service period and compensation cost for RSUs is generally recognized over the corresponding one-, two-, or three-year vesting period. Shares of Southern Company common stock are delivered to employees at the end of each vesting period.

Southern Company had 1.2 million RSUs outstanding at December 31, 2020. During 2021, Southern Company granted 0.5 million RSUs and 0.6 million RSUs were vested or forfeited, resulting in 1.1 million unvested RSUs outstanding at December 31, 2021, including RSUs related to employee retention agreements.

For the years ended December 31, 2021, 2020, and 2019, Southern Company’s total compensation cost for RSUs recognized in income was $32 million, $29 million, and $28 million, respectively. The related tax benefit also recognized in income was $8 million, $8 million, and $7 million for the years ended December 31, 2021, 2020, and 2019, respectively. Total unrecognized compensation cost related to RSUs at December 31, 2021, which is being recognized over a weighted-average period of approximately 16 months, is immaterial for Southern Company.

Total RSUs outstanding and total compensation cost and related tax benefit for the RSUs recognized in income for the years ended December 31, 2021, 2020, and 2019, as well as the total unrecognized compensation cost at December 31, 2021, were immaterial for all other Registrants. The compensation cost related to the grant of Southern Company RSUs to the employees of each Subsidiary Registrant is recognized in such Subsidiary Registrant's financial statements with a corresponding credit to equity representing a capital contribution from Southern Company.

## Stock Options

In 2015, Southern Company discontinued granting stock options. As of December 31, 2017, all stock option awards were vested and compensation cost fully recognized. Stock options expire no later than 10 years after the grant date and the latest possible exercise will occur by November 2024. At December 31, 2021, the weighted average remaining contractual term for the options outstanding and exercisable was approximately 19 months.

Southern Company’s activity in the stock option program for 2021 is summarized below:

<table><tr><td></td><td>Shares Subject to Option</td><td>Weighted Average Exercise Price</td></tr><tr><td></td><td>(in millions)</td><td></td></tr><tr><td>Outstanding at December 31, 2020</td><td>4.3</td><td>43.04</td></tr><tr><td>Exercised</td><td>1.5</td><td>43.21</td></tr><tr><td>Outstanding and Exercisable at December 31, 2021</td><td>2.8</td><td>42.95</td></tr></table>



Southern Company’s cash receipts from issuances related to stock options exercised under the share-based payment arrangements for the years ended December 31, 2021, 2020, and 2019 were $66 million, $66 million, and $482 million, respectively.

At December 31, 2021, the aggregate intrinsic value for the options outstanding and exercisable was as follows:

<table><tr><td></td><td>Southern Company</td><td>Georgia Power</td><td>Southern Company Gas</td></tr><tr><td></td><td colspan="3">(in millions)</td></tr><tr><td>Total intrinsic value for outstanding and exercisable options</td><td>$71</td><td>$17</td><td>$8</td></tr></table>

The aggregate intrinsic value for the options outstanding and exercisable was immaterial for Alabama Power, Mississippi Power, and Southern Power at December 31, 2021.

Total intrinsic value of options exercised, and the related tax benefit, for the years ended December 31, 2021, 2020, and 2019 are presented below:

<table><tr><td>Year Ended December 31</td><td>2021</td><td>2020</td><td>2019</td></tr><tr><td></td><td colspan="3">(in millions)</td></tr><tr><td>Southern Company</td><td></td><td></td><td></td></tr><tr><td>Intrinsic value of options exercised</td><td>$34</td><td>$38</td><td>$167</td></tr><tr><td>Tax benefit of options exercised</td><td>7</td><td>9</td><td>35</td></tr><tr><td>Alabama Power</td><td></td><td></td><td></td></tr><tr><td>Intrinsic value of options exercised</td><td>$3</td><td>$5</td><td>$21</td></tr><tr><td>Tax benefit of options exercised</td><td>1</td><td>1</td><td>4</td></tr><tr><td>Georgia Power</td><td></td><td></td><td></td></tr><tr><td>Intrinsic value of options exercised</td><td>$14</td><td>$9</td><td>$30</td></tr><tr><td>Tax benefit of options exercised</td><td>3</td><td>2</td><td>6</td></tr></table>

Total intrinsic value of options exercised, and the related tax benefit recognized in income, for the years ended December 31, 2021, 2020, and 2019 were immaterial for Mississippi Power, Southern Power, and Southern Company Gas.

## 13. FAIR VALUE MEASUREMENTS

Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.

• Level 1 consists of observable market data in an active market for identical assets or liabilities.

• Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.

• Level 3 consists of unobservable market data. The input may reflect the assumptions of each Registrant of what a market participant would use in pricing an asset or liability. If there is little available market data, then each Registrant’s own assumptions are the best available information.

In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.

Net asset value as a practical expedient is the classification used for assets that do not have readily determined fair values. Fund managers value the assets using various inputs and techniques depending on the nature of the underlying investments.



At December 31, 2021, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

<table><tr><td rowspan="2"></td><td colspan="5">Fair Value Measurements Using</td></tr><tr><td>Quoted Prices in Active Markets for Identical Assets (Level 1)</td><td>Significant Other Observable Inputs (Level 2)</td><td>Significant Unobservable Inputs (Level 3)</td><td>Net Asset Value as a Practical Expedient (NAV)</td><td>Total</td></tr><tr><td>At December 31, 2021:</td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Southern Company</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives \( ^{(a)} \)</td><td>$ 24</td><td>$ 195</td><td>$ —</td><td>$ —</td><td>$ 219</td></tr><tr><td>Interest rate derivatives</td><td>—</td><td>19</td><td>—</td><td>—</td><td>19</td></tr><tr><td>Investments in trusts: \) ^{(b)(c)}</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Domestic equity</td><td>791</td><td>225</td><td>—</td><td>—</td><td>1,016</td></tr><tr><td>Foreign equity</td><td>165</td><td>188</td><td>—</td><td>—</td><td>353</td></tr><tr><td>U.S. Treasury and government agency securities</td><td>—</td><td>314</td><td>—</td><td>—</td><td>314</td></tr><tr><td>Municipal bonds</td><td>—</td><td>56</td><td>—</td><td>—</td><td>56</td></tr><tr><td>Pooled funds - fixed income</td><td>—</td><td>13</td><td>—</td><td>—</td><td>13</td></tr><tr><td>Corporate bonds</td><td>1</td><td>522</td><td>—</td><td>—</td><td>523</td></tr><tr><td>Mortgage and asset backed securities</td><td>—</td><td>93</td><td>—</td><td>—</td><td>93</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>—</td><td>150</td><td>150</td></tr><tr><td>Cash and cash equivalents</td><td>2</td><td>—</td><td>—</td><td>—</td><td>2</td></tr><tr><td>Other</td><td>22</td><td>25</td><td>—</td><td>—</td><td>47</td></tr><tr><td>Cash equivalents</td><td>1,160</td><td>14</td><td>—</td><td>—</td><td>1,174</td></tr><tr><td>Other investments</td><td>9</td><td>35</td><td>—</td><td>—</td><td>44</td></tr><tr><td>Total</td><td>$2,174</td><td>$1,699</td><td>$ —</td><td>$150</td><td>$4,023</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives \( ^{(a)} \)</td><td>$ 10</td><td>$ 36</td><td>$ —</td><td>$ —</td><td>$ 46</td></tr><tr><td>Interest rate derivatives</td><td>—</td><td>29</td><td>—</td><td>—</td><td>29</td></tr><tr><td>Foreign currency derivatives</td><td>—</td><td>79</td><td>—</td><td>—</td><td>79</td></tr><tr><td>Contingent consideration</td><td>—</td><td>—</td><td>14</td><td>—</td><td>14</td></tr><tr><td>Other</td><td>—</td><td>13</td><td>—</td><td>—</td><td>13</td></tr><tr><td>Total</td><td>$ 10</td><td>$ 157</td><td>$14</td><td>$ —</td><td>$ 181</td></tr><tr><td>Alabama Power</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives</td><td>$ —</td><td>$ 55</td><td>$ —</td><td>$ —</td><td>$ 55</td></tr><tr><td>Nuclear decommissioning trusts: \) ^{(b)}</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Domestic equity</td><td>468</td><td>216</td><td>—</td><td>—</td><td>684</td></tr><tr><td>Foreign equity</td><td>165</td><td>—</td><td>—</td><td>—</td><td>165</td></tr><tr><td>U.S. Treasury and government agency securities</td><td>—</td><td>21</td><td>—</td><td>—</td><td>21</td></tr><tr><td>Municipal bonds</td><td>—</td><td>1</td><td>—</td><td>—</td><td>1</td></tr><tr><td>Corporate bonds</td><td>1</td><td>271</td><td>—</td><td>—</td><td>272</td></tr><tr><td>Mortgage and asset backed securities</td><td>—</td><td>22</td><td>—</td><td>—</td><td>22</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>—</td><td>150</td><td>150</td></tr><tr><td>Other</td><td>9</td><td>—</td><td>—</td><td>—</td><td>9</td></tr><tr><td>Cash equivalents</td><td>839</td><td>14</td><td>—</td><td>—</td><td>853</td></tr><tr><td>Other investments</td><td>—</td><td>35</td><td>—</td><td>—</td><td>35</td></tr><tr><td>Total</td><td>$1,482</td><td>$ 635</td><td>$ —</td><td>$150</td><td>$2,267</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives</td><td>$ —</td><td>$ 11</td><td>$ —</td><td>$ —</td><td>$ 11</td></tr></table>



Fair Value Measurements Using

<table><tr><td rowspan="2"></td><td colspan="5">Fair Value Measurements Using</td></tr><tr><td>Quoted Prices in Active Markets for Identical Assets (Level 1)</td><td>Significant Other Observable Inputs (Level 2)</td><td>Significant Unobservable Inputs (Level 3)</td><td>Net Asset Value as a Practical Expedient (NAV)</td><td>Total</td></tr><tr><td>At December 31, 2021:</td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Georgia Power</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives</td><td>$ —</td><td>$ 75</td><td>$ —</td><td>$ —</td><td>$ 75</td></tr><tr><td>Nuclear decommissioning trusts: \( ^{(b)(c)} \)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Domestic equity</td><td>323</td><td>1</td><td>—</td><td>—</td><td>324</td></tr><tr><td>Foreign equity</td><td>—</td><td>185</td><td>—</td><td>—</td><td>185</td></tr><tr><td>U.S. Treasury and government agency securities</td><td>—</td><td>293</td><td>—</td><td>—</td><td>293</td></tr><tr><td>Municipal bonds</td><td>—</td><td>55</td><td>—</td><td>—</td><td>55</td></tr><tr><td>Corporate bonds</td><td>—</td><td>251</td><td>—</td><td>—</td><td>251</td></tr><tr><td>Mortgage and asset backed securities</td><td>—</td><td>71</td><td>—</td><td>—</td><td>71</td></tr><tr><td>Other</td><td>13</td><td>25</td><td>—</td><td>—</td><td>38</td></tr><tr><td>Total</td><td>$336</td><td>$956</td><td>$ —</td><td>$ —</td><td>$1,292</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives</td><td>$ —</td><td>$ 8</td><td>$ —</td><td>$ —</td><td>$ 8</td></tr><tr><td>Mississippi Power</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives</td><td>$ —</td><td>$ 56</td><td>$ —</td><td>$ —</td><td>$ 56</td></tr><tr><td>Cash equivalents</td><td>40</td><td>—</td><td>—</td><td>—</td><td>40</td></tr><tr><td>Total</td><td>$ 40</td><td>$ 56</td><td>$ —</td><td>$ —</td><td>$ 96</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives</td><td>$ —</td><td>$ 5</td><td>$ —</td><td>$ —</td><td>$ 5</td></tr><tr><td>Southern Power</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives</td><td>$ —</td><td>$ 4</td><td>$ —</td><td>$ —</td><td>$ 4</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Foreign currency derivatives</td><td>$ —</td><td>$ 16</td><td>$ —</td><td>$ —</td><td>$ 16</td></tr><tr><td>Contingent consideration</td><td>—</td><td>—</td><td>14</td><td>—</td><td>14</td></tr><tr><td>Other</td><td>—</td><td>13</td><td>—</td><td>—</td><td>13</td></tr><tr><td>Total</td><td>$ —</td><td>$ 29</td><td>$ 14</td><td>$ —</td><td>$ 43</td></tr><tr><td>Southern Company Gas</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives \( ^{(a)} \)</td><td>$ 24</td><td>$ 5</td><td>$ —</td><td>$ —</td><td>$ 29</td></tr><tr><td>Interest rate derivatives</td><td>—</td><td>6</td><td>—</td><td>—</td><td>6</td></tr><tr><td>Non-qualified deferred compensation trusts:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Domestic equity</td><td>—</td><td>8</td><td>—</td><td>—</td><td>8</td></tr><tr><td>Foreign equity</td><td>—</td><td>3</td><td>—</td><td>—</td><td>3</td></tr><tr><td>Pooled funds - fixed income</td><td>—</td><td>13</td><td>—</td><td>—</td><td>13</td></tr><tr><td>Cash equivalents</td><td>2</td><td>—</td><td>—</td><td>—</td><td>2</td></tr><tr><td>Total</td><td>$ 26</td><td>$ 35</td><td>$ —</td><td>$ —</td><td>$ 61</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives \( ^{(a)(b)} \)</td><td>$ 10</td><td>$ 12</td><td>$ —</td><td>$ —</td><td>$ 22</td></tr><tr><td>Interest rate derivatives</td><td>—</td><td>5</td><td>—</td><td>—</td><td>5</td></tr><tr><td>Total</td><td>$ 10</td><td>$ 17</td><td>$ —</td><td>$ —</td><td>$ 27</td></tr></table>

(a) Excludes immaterial cash collateral.

(b) Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 under “Nuclear Decommissioning” for additional information.

(c) Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. See Note 6 under “Nuclear Decommissioning” for additional information.



At December 31, 2020, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

<table><tr><td rowspan="2"></td><td colspan="5">Fair Value Measurements Using</td></tr><tr><td>Quoted Prices in Active Markets for Identical Assets (Level 1)</td><td>Significant Other Observable Inputs (Level 2)</td><td>Significant Unobservable Inputs (Level 3)</td><td>Net Asset Value as a Practical Expedient (NAV)</td><td>Total</td></tr><tr><td>At December 31, 2020:</td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Southern Company</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives \( ^{(a)} \)</td><td>$ 401</td><td>$ 271</td><td>$32</td><td>$ —</td><td>$ 704</td></tr><tr><td>Interest rate derivatives</td><td>—</td><td>20</td><td>—</td><td>—</td><td>20</td></tr><tr><td>Foreign currency derivatives</td><td>—</td><td>87</td><td>—</td><td>—</td><td>87</td></tr><tr><td>Investments in trusts: \( ^{(b)(c)} \)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Domestic equity</td><td>862</td><td>151</td><td>—</td><td>—</td><td>1,013</td></tr><tr><td>Foreign equity</td><td>85</td><td>253</td><td>—</td><td>—</td><td>338</td></tr><tr><td>U.S. Treasury and government agency securities</td><td>—</td><td>284</td><td>—</td><td>—</td><td>284</td></tr><tr><td>Municipal bonds</td><td>—</td><td>85</td><td>—</td><td>—</td><td>85</td></tr><tr><td>Pooled funds - fixed income</td><td>—</td><td>17</td><td>—</td><td>—</td><td>17</td></tr><tr><td>Corporate bonds</td><td>13</td><td>386</td><td>—</td><td>—</td><td>399</td></tr><tr><td>Mortgage and asset backed securities</td><td>—</td><td>83</td><td>—</td><td>—</td><td>83</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>—</td><td>76</td><td>76</td></tr><tr><td>Cash and cash equivalents</td><td>1</td><td>—</td><td>—</td><td>—</td><td>1</td></tr><tr><td>Other</td><td>28</td><td>7</td><td>—</td><td>—</td><td>35</td></tr><tr><td>Cash equivalents</td><td>575</td><td>9</td><td>—</td><td>—</td><td>584</td></tr><tr><td>Other investments</td><td>9</td><td>24</td><td>—</td><td>—</td><td>33</td></tr><tr><td>Total</td><td>$ 1,974</td><td>$ 1,677</td><td>$ 32</td><td>$ 76</td><td>$ 3,759</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives \( ^{(a)} \)</td><td>$ 389</td><td>$ 204</td><td>$ 4</td><td>$ —</td><td>$ 597</td></tr><tr><td>Foreign currency derivatives</td><td>—</td><td>23</td><td>—</td><td>—</td><td>23</td></tr><tr><td>Contingent consideration</td><td>—</td><td>—</td><td>17</td><td>—</td><td>17</td></tr><tr><td>Total</td><td>$ 389</td><td>$ 227</td><td>$ 21</td><td>$ —</td><td>$ 637</td></tr><tr><td>Alabama Power</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives</td><td>$ —</td><td>$ 12</td><td>$ —</td><td>$ —</td><td>$ 12</td></tr><tr><td>Nuclear decommissioning trusts: \( ^{(b)} \)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Domestic equity</td><td>543</td><td>141</td><td>—</td><td>—</td><td>684</td></tr><tr><td>Foreign equity</td><td>85</td><td>73</td><td>—</td><td>—</td><td>158</td></tr><tr><td>U.S. Treasury and government agency securities</td><td>—</td><td>21</td><td>—</td><td>—</td><td>21</td></tr><tr><td>Municipal bonds</td><td>—</td><td>1</td><td>—</td><td>—</td><td>1</td></tr><tr><td>Corporate bonds</td><td>13</td><td>167</td><td>—</td><td>—</td><td>180</td></tr><tr><td>Mortgage and asset backed securities</td><td>—</td><td>29</td><td>—</td><td>—</td><td>29</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>—</td><td>76</td><td>76</td></tr><tr><td>Other</td><td>7</td><td>—</td><td>—</td><td>—</td><td>7</td></tr><tr><td>Cash equivalents</td><td>311</td><td>9</td><td>—</td><td>—</td><td>320</td></tr><tr><td>Other investments</td><td>—</td><td>24</td><td>—</td><td>—</td><td>24</td></tr><tr><td>Total</td><td>$ 959</td><td>$ 477</td><td>$ —</td><td>$ 76</td><td>$ 1,512</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives</td><td>$ —</td><td>$ 7</td><td>$ —</td><td>$ —</td><td>$ 7</td></tr></table>



Fair Value Measurements Using

<table><tr><td>At December 31, 2020:</td><td>Quoted Prices in Active Markets for Identical Assets (Level 1)</td><td>Significant Other Observable Inputs (Level 2)</td><td>Significant Unobservable Inputs (Level 3)</td><td>Net Asset Value as a Practical Expedient (NAV)</td><td>Total</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Georgia Power</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives</td><td>$ —</td><td>$ 15</td><td>$ —</td><td>$ —</td><td>$ 15</td></tr><tr><td>Nuclear decommissioning trusts: \( ^{(b)(c)} \)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Domestic equity</td><td>319</td><td>1</td><td>—</td><td>—</td><td>320</td></tr><tr><td>Foreign equity</td><td>—</td><td>177</td><td>—</td><td>—</td><td>177</td></tr><tr><td>U.S. Treasury and government agency securities</td><td>—</td><td>263</td><td>—</td><td>—</td><td>263</td></tr><tr><td>Municipal bonds</td><td>—</td><td>84</td><td>—</td><td>—</td><td>84</td></tr><tr><td>Corporate bonds</td><td>—</td><td>219</td><td>—</td><td>—</td><td>219</td></tr><tr><td>Mortgage and asset backed securities</td><td>—</td><td>54</td><td>—</td><td>—</td><td>54</td></tr><tr><td>Other</td><td>21</td><td>7</td><td>—</td><td>—</td><td>28</td></tr><tr><td>Total</td><td>$340</td><td>$820</td><td>$ —</td><td>$ —</td><td>$1,160</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives</td><td>$ —</td><td>$ 13</td><td>$ —</td><td>$ —</td><td>$ 13</td></tr><tr><td>Mississippi Power</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives</td><td>$ —</td><td>$ 9</td><td>$ —</td><td>$ —</td><td>$ 9</td></tr><tr><td>Cash equivalents</td><td>21</td><td>—</td><td>—</td><td>—</td><td>21</td></tr><tr><td>Total</td><td>$ 21</td><td>$ 9</td><td>$ —</td><td>$ —</td><td>$ 30</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives</td><td>$ —</td><td>$ 9</td><td>$ —</td><td>$ —</td><td>$ 9</td></tr><tr><td>Southern Power</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives</td><td>$ —</td><td>$ 2</td><td>$ —</td><td>$ —</td><td>$ 2</td></tr><tr><td>Foreign currency derivatives</td><td>—</td><td>87</td><td>—</td><td>—</td><td>87</td></tr><tr><td>Total</td><td>$ —</td><td>$ 89</td><td>$ —</td><td>$ —</td><td>$ 89</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives</td><td>$ —</td><td>$ 3</td><td>$ —</td><td>$ —</td><td>$ 3</td></tr><tr><td>Foreign currency derivatives</td><td>—</td><td>23</td><td>—</td><td>—</td><td>23</td></tr><tr><td>Contingent consideration</td><td>—</td><td>—</td><td>17</td><td>—</td><td>17</td></tr><tr><td>Total</td><td>$ —</td><td>$ 26</td><td>$ 17</td><td>$ —</td><td>$ 43</td></tr><tr><td>Southern Company Gas</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives \( ^{(a)} \)</td><td>$ 401</td><td>$233</td><td>$ 32</td><td>$ —</td><td>$ 666</td></tr><tr><td>Non-qualified deferred compensation trusts:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Domestic equity</td><td>—</td><td>9</td><td>—</td><td>—</td><td>9</td></tr><tr><td>Foreign equity</td><td>—</td><td>3</td><td>—</td><td>—</td><td>3</td></tr><tr><td>Pooled funds - fixed income</td><td>—</td><td>17</td><td>—</td><td>—</td><td>17</td></tr><tr><td>Cash equivalents</td><td>1</td><td>—</td><td>—</td><td>—</td><td>1</td></tr><tr><td>Total</td><td>$ 402</td><td>$ 262</td><td>$ 32</td><td>$ —</td><td>$ 696</td></tr><tr><td>Liabilities:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives \( ^{(a)(b)} \)</td><td>$ 389</td><td>$ 172</td><td>$ 4</td><td>$ —</td><td>$ 565</td></tr></table>

(a) Excludes $6 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value and cash collateral of $28 million.

(b) Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 under “Nuclear Decommissioning” for additional information.

(c) Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. See Note 6 under “Nuclear Decommissioning” for additional information.



## Valuation Methodologies

The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 14 for additional information on how these derivatives are used.

For fair value measurements of the investments within the nuclear decommissioning trusts and the non-qualified deferred compensation trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available.

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. See Note 6 under “Nuclear Decommissioning” for additional information.

Southern Power has contingent payment obligations related to certain acquisitions whereby it is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation of the respective facility and continue through 2026. The obligations are categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.

Southern Power also has payment obligations through 2040 whereby it must reimburse the transmission owners for interconnection facilities and network upgrades constructed to support connection of a Southern Power generating facility to the transmission system. The obligations are categorized as Level 2 under Fair Value Measurements as the fair value is determined using observable inputs for the contracted amounts and reimbursement period, as well as a discount rate. The fair value of the obligations reflects the net present value of expected payments.

“Other investments” include investments traded in the open market that have maturities greater than 90 days, which are categorized as Level 2 under Fair Value Measurements and are comprised of corporate bonds, bank certificates of deposit, treasury bonds, and/or agency bonds.

The fair value measurements of private equity investments held in Alabama Power’s nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient totaled $150 million and $76 million at December 31, 2021 and 2020, respectively. Unfunded commitments related to the private equity investments totaled $69 million and $73 million at December 31, 2021 and 2020, respectively. Private equity investments include high-quality private equity funds across several market sectors and funds that invest in real estate assets. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.



At December 31, 2021 and 2020, other financial instruments for which the carrying amount did not equal fair value were as follows:

<table><tr><td></td><td>Southern Company \( ^{(1)} \)</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Power</td><td>Southern Company Gas \( ^{(1)} \)</td></tr><tr><td></td><td></td><td></td><td></td><td>(in billions)</td><td></td><td></td></tr><tr><td>At December 31, 2021:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Long-term debt, including securities due within one year:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Carrying amount</td><td>$52.1</td><td>$9.7</td><td>$13.6</td><td>$1.5</td><td>$3.7</td><td>$6.9</td></tr><tr><td>Fair value</td><td>57.1</td><td>10.9</td><td>15.1</td><td>1.6</td><td>4.1</td><td>7.8</td></tr><tr><td>At December 31, 2020:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Long-term debt, including securities due within one year:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Carrying amount</td><td>$48.3</td><td>$8.9</td><td>$12.8</td><td>$1.4</td><td>$3.7</td><td>$6.6</td></tr><tr><td>Fair value</td><td>56.3</td><td>10.7</td><td>15.2</td><td>1.6</td><td>4.2</td><td>8.0</td></tr></table>

(*) The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the remaining lives of the respective bonds, the latest being through 2043.

The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the Registrants.

## Commodity Contracts with Level 3 Valuation Inputs

Prior to July 1, 2021, Southern Company Gas had Level 3 physical natural gas forward contracts related to Sequent. See Note 15 under "Southern Company Gas" for information regarding the sale of Sequent. The following table provides a reconciliation of Southern Company Gas' Level 3 contracts during 2021.

<table><tr><td></td><td>2021</td></tr><tr><td>Beginning balance</td><td>(in millions)</td></tr><tr><td>Instruments realized or otherwise settled during period</td><td>$ 28</td></tr><tr><td>Changes in fair value</td><td>(6)</td></tr><tr><td>Sale of Sequent</td><td>(4)</td></tr><tr><td>Ending balance</td><td>(18)</td></tr></table>

Changes in fair value of Level 3 instruments represent changes in gains and losses reported on Southern Company Gas' statements of income in natural gas revenues prior to the sale of Sequent.



## 14. DERIVATIVES

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' wholesale gas operations used various contracts in its commercial activities that generally met the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note 13 for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with the classification of the hedged interest or principal, respectively. See Note 1 under "Financial Instruments" for additional information. See Note 15 under "Southern Company Gas" for additional information regarding the sale of Sequent.

## Energy-Related Derivatives

The traditional electric operating companies, Southern Power, and Southern Company Gas enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.

Southern Company Gas also enters into weather derivative contracts as economic hedges in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.

Energy-related derivative contracts are accounted for under one of three methods:

• Regulatory Hedges – Energy-related derivative contracts designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through an approved cost recovery mechanism.

• Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in AOCI before being recognized in the statements of income in the same period and in the same income statement line item as the earnings effect of the hedged transactions.

• Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.



At December 31, 2021, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:

<table><tr><td></td><td>Net Purchased mmBtu</td><td>Longest Hedge Date</td><td>Longest Non-Hedge Date</td></tr><tr><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>Southern Company \( ^{(1)} \)</td><td>311</td><td>2030</td><td>2025</td></tr><tr><td>Alabama Power</td><td>74</td><td>2024</td><td>—</td></tr><tr><td>Georgia Power</td><td>89</td><td>2024</td><td>—</td></tr><tr><td>Mississippi Power</td><td>75</td><td>2025</td><td>—</td></tr><tr><td>Southern Power</td><td>5</td><td>2030</td><td>2022</td></tr><tr><td>Southern Company Gas \( ^{(1)} \)</td><td>68</td><td>2024</td><td>2025</td></tr></table>

(*) Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 74 million mmBtu and short natural gas positions of 6 million mmBtu at December 31, 2021, which is also included in Southern Company's total volume. See Note 15 under "Southern Company Gas" for information regarding the sale of Sequent.

In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 26 million mmBtu for Southern Company, which includes 6 million mmBtu for Alabama Power, 8 million mmBtu for Georgia Power, 4 million mmBtu for Mississippi Power, and 8 million mmBtu for Southern Power.

For cash flow hedges of energy-related derivatives, the estimated pre-tax gains (losses) expected to be reclassified from AOCI to earnings for the year ending December 31, 2022 are immaterial for all Registrants.

## Interest Rate Derivatives

Southern Company and certain subsidiaries may enter into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

At December 31, 2021, the following interest rate derivatives were outstanding:

<table><tr><td></td><td>Notional Amount</td><td>Interest Rate Received</td><td>Weighted Average Interest Rate Paid</td><td>Hedge Maturity Date</td><td>Fair Value Gain (Loss) December 31, 2021</td></tr><tr><td></td><td>(in millions)</td><td></td><td></td><td></td><td>(in millions)</td></tr><tr><td>Fair Value Hedges of Existing Debt</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Southern Company parent</td><td>$ 400</td><td>1.75%</td><td>1-month LIBOR + 0.68%</td><td>March 2028</td><td>$ (5)</td></tr><tr><td>Southern Company parent</td><td>1,000</td><td>3.70%</td><td>1-month LIBOR + 2.36%</td><td>April 2030</td><td>(6)</td></tr><tr><td>Southern Company Gas</td><td>500</td><td>1.75%</td><td>1-month LIBOR + 0.38%</td><td>January 2031</td><td>1</td></tr><tr><td>Southern Company</td><td>$1,900</td><td></td><td></td><td></td><td>$ (10)</td></tr></table>

For cash flow hedge interest rate derivatives, the estimated pre-tax gains (losses) expected to be reclassified from AOCI to interest expense for the year ending December 31, 2022 total $ (21) million for Southern Company and are immaterial for all other Registrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2051 for Southern Company, 2051 for Alabama Power, 2044 for Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.

## Foreign Currency Derivatives

Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or



losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Southern Company has elected to exclude the cross-currency basis spread from the assessment of effectiveness in the fair value hedges of its foreign currency risk and record any difference between the change in the fair value of the excluded components and the amounts recognized in earnings as a component of OCI.

At December 31, 2021, the following foreign currency derivatives were outstanding:

<table><tr><td></td><td>Pay Notional</td><td>Pay Rate</td><td>Receive Notional</td><td>Receive Rate</td><td>Hedge Maturity Date</td><td>Fair Value Gain (Loss) December 31, 2021</td></tr><tr><td></td><td>(in millions)</td><td></td><td>(in millions)</td><td></td><td></td><td>(in millions)</td></tr><tr><td>Fair Value Hedges of Existing Debt</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Southern Company parent</td><td>$1,476</td><td>3.39%</td><td>€ 1,250</td><td>1.88%</td><td>September 2027</td><td>$(63)</td></tr><tr><td>Cash Flow Hedges of Existing Debt</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Southern Power</td><td>$ 677</td><td>2.95%</td><td>€ 600</td><td>1.00%</td><td>June 2022</td><td>$ (5)</td></tr><tr><td>Southern Power</td><td>564</td><td>3.78%</td><td>500</td><td>1.85%</td><td>June 2026</td><td>(10)</td></tr><tr><td>Southern Power total</td><td>$1,241</td><td></td><td>€ 1,100</td><td></td><td></td><td>$(15)</td></tr><tr><td>Southern Company</td><td>$2,717</td><td></td><td>€ 2,350</td><td></td><td></td><td>$(78)</td></tr></table>

The estimated pre-tax gains (losses) related to Southern Power’s foreign currency derivatives accounted for as cash flow hedges expected to be reclassified from AOCI to earnings for the year ending December 31, 2022 are $(13) million.

## Derivative Financial Statement Presentation and Amounts

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. The fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.



At December 31, 2021 and 2020, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:

<table><tr><td rowspan="2">Derivative Category and Balance Sheet Location</td><td colspan="2">2021</td><td colspan="2">2020</td></tr><tr><td>Assets</td><td>Liabilities</td><td>Assets</td><td>Liabilities</td></tr><tr><td>Southern Company</td><td></td><td></td><td>(in millions)</td><td></td></tr><tr><td>Derivatives designated as hedging instruments for regulatory purposes</td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives:</td><td></td><td></td><td></td><td></td></tr><tr><td>Assets from risk management activities/Other current liabilities</td><td>$129</td><td>$ 30</td><td>$ 24</td><td>$ 11</td></tr><tr><td>Other deferred charges and assets/Other deferred credits and liabilities</td><td>72</td><td>6</td><td>18</td><td>19</td></tr><tr><td>Total derivatives designated as hedging instruments for regulatory purposes</td><td>$201</td><td>$ 36</td><td>$ 42</td><td>$ 30</td></tr><tr><td>Derivatives designated as hedging instruments in cash flow and fair value hedges</td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives:</td><td></td><td></td><td></td><td></td></tr><tr><td>Assets from risk management activities/Other current liabilities</td><td>$ 7</td><td>$ 5</td><td>$ 3</td><td>$ 5</td></tr><tr><td>Other deferred charges and assets/Other deferred credits and liabilities</td><td>1</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Interest rate derivatives:</td><td></td><td></td><td></td><td></td></tr><tr><td>Assets from risk management activities/Other current liabilities</td><td>19</td><td>—</td><td>20</td><td>—</td></tr><tr><td>Other deferred charges and assets/Other deferred credits and liabilities</td><td>—</td><td>29</td><td>—</td><td>—</td></tr><tr><td>Foreign currency derivatives:</td><td></td><td></td><td></td><td></td></tr><tr><td>Assets from risk management activities/Other current liabilities</td><td>—</td><td>39</td><td>—</td><td>23</td></tr><tr><td>Other deferred charges and assets/Other deferred credits and liabilities</td><td>—</td><td>40</td><td>87</td><td>—</td></tr><tr><td>Total derivatives designated as hedging instruments in cash flow and fair value hedges</td><td>$ 27</td><td>$113</td><td>$ 110</td><td>$ 28</td></tr><tr><td>Derivatives not designated as hedging instruments</td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives:</td><td></td><td></td><td></td><td></td></tr><tr><td>Assets from risk management activities/Other current liabilities</td><td>$ 9</td><td>$ 4</td><td>$ 388</td><td>$ 331</td></tr><tr><td>Other deferred charges and assets/Other deferred credits and liabilities</td><td>1</td><td>—</td><td>270</td><td>232</td></tr><tr><td>Total derivatives not designated as hedging instruments</td><td>$ 10</td><td>$ 4</td><td>$ 658</td><td>$ 563</td></tr><tr><td>Gross amounts recognized</td><td>$238</td><td>$153</td><td>$ 810</td><td>$ 621</td></tr><tr><td>Gross amounts offset(a)</td><td>$ (25)</td><td>$ (28)</td><td>$ (529)</td><td>$ (557)</td></tr><tr><td>Net amounts recognized in the Balance Sheets(b)</td><td>$213</td><td>$125</td><td>$ 281</td><td>$ 64</td></tr><tr><td>Alabama Power</td><td></td><td></td><td></td><td></td></tr><tr><td>Derivatives designated as hedging instruments for regulatory purposes</td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives:</td><td></td><td></td><td></td><td></td></tr><tr><td>Other current assets/Other current liabilities</td><td>$ 30</td><td>$ 9</td><td>$ 7</td><td>$ 2</td></tr><tr><td>Other deferred charges and assets/Other deferred credits and liabilities</td><td>25</td><td>2</td><td>5</td><td>5</td></tr><tr><td>Total derivatives designated as hedging instruments for regulatory purposes</td><td>$ 55</td><td>$ 11</td><td>$ 12</td><td>$ 7</td></tr><tr><td>Gross amounts offset</td><td>$ (5)</td><td>$ (5)</td><td>$ (7)</td><td>$ (7)</td></tr><tr><td>Net amounts recognized in the Balance Sheets</td><td>$ 50</td><td>$ 6</td><td>$ 5</td><td>$ —</td></tr><tr><td>Georgia Power</td><td></td><td></td><td></td><td></td></tr><tr><td>Derivatives designated as hedging instruments for regulatory purposes</td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives:</td><td></td><td></td><td></td><td></td></tr><tr><td>Other current assets/Other current liabilities</td><td>$ 54</td><td>$ 6</td><td>$ 7</td><td>$ 5</td></tr><tr><td>Other deferred charges and assets/Other deferred credits and liabilities</td><td>21</td><td>2</td><td>8</td><td>8</td></tr><tr><td>Total derivatives designated as hedging instruments for regulatory purposes</td><td>$ 75</td><td>$ 8</td><td>$ 15</td><td>$ 13</td></tr><tr><td>Gross amounts offset</td><td>$ (8)</td><td>$ (8)</td><td>$ (12)</td><td>$ (12)</td></tr><tr><td>Net amounts recognized in the Balance Sheets</td><td>$ 67</td><td>$ —</td><td>$ 3</td><td>$ 1</td></tr></table>



<table><tr><td rowspan="2">Derivative Category and Balance Sheet Location</td><td colspan="2">2021</td><td colspan="2">2020</td></tr><tr><td>Assets</td><td>Liabilities</td><td>Assets</td><td>Liabilities</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td></tr><tr><td>Mississippi Power</td><td></td><td></td><td></td><td></td></tr><tr><td>Derivatives designated as hedging instruments for regulatory purposes</td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives:</td><td></td><td></td><td></td><td></td></tr><tr><td>Other current assets/Other current liabilities</td><td>$30</td><td>$ 3</td><td>$ 4</td><td>$ 3</td></tr><tr><td>Other deferred charges and assets/Other deferred credits and liabilities</td><td>26</td><td>2</td><td>5</td><td>6</td></tr><tr><td>Total derivatives designated as hedging instruments for regulatory purposes</td><td>$56</td><td>$ 5</td><td>$ 9</td><td>$ 9</td></tr><tr><td>Gross amounts offset</td><td>$ (4)</td><td>$ (4)</td><td>$ (7)</td><td>$ (7)</td></tr><tr><td>Net amounts recognized in the Balance Sheets</td><td>$52</td><td>$ 1</td><td>$ 2</td><td>$ 2</td></tr><tr><td>Southern Power</td><td></td><td></td><td></td><td></td></tr><tr><td>Derivatives designated as hedging instruments in cash flow and fair value hedges</td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives:</td><td></td><td></td><td></td><td></td></tr><tr><td>Other current assets/Other current liabilities</td><td>$ 2</td><td>$ —</td><td>$ 2</td><td>$ 2</td></tr><tr><td>Other deferred charges and assets/Other deferred credits and liabilities</td><td>1</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Foreign currency derivatives:</td><td></td><td></td><td></td><td></td></tr><tr><td>Other current assets/Other current liabilities</td><td>—</td><td>16</td><td>—</td><td>23</td></tr><tr><td>Other deferred charges and assets/Other deferred credits and liabilities</td><td>—</td><td>—</td><td>87</td><td>—</td></tr><tr><td>Total derivatives designated as hedging instruments in cash flow and fair value hedges</td><td>$ 3</td><td>$ 16</td><td>$ 89</td><td>$ 25</td></tr><tr><td>Derivatives not designated as hedging instruments</td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives:</td><td></td><td></td><td></td><td></td></tr><tr><td>Other current assets/Other current liabilities</td><td>$ 1</td><td>$ —</td><td>$ —</td><td>$ 1</td></tr><tr><td>Net amounts recognized in the Balance Sheets</td><td>$ 4</td><td>$ 16</td><td>$ 89</td><td>$ 26</td></tr><tr><td>Southern Company Gas</td><td></td><td></td><td></td><td></td></tr><tr><td>Derivatives designated as hedging instruments for regulatory purposes</td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives:</td><td></td><td></td><td></td><td></td></tr><tr><td>Assets from risk management activities/Other current liabilities</td><td>$15</td><td>$ 12</td><td>$ 6</td><td>$ 1</td></tr><tr><td>Derivatives designated as hedging instruments in cash flow and fair value hedges</td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives:</td><td></td><td></td><td></td><td></td></tr><tr><td>Assets from risk management activities/Other current liabilities</td><td>$ 5</td><td>$ 5</td><td>$ 1</td><td>$ 3</td></tr><tr><td>Interest rate derivatives:</td><td></td><td></td><td></td><td></td></tr><tr><td>Assets from risk management activities/Other current liabilities</td><td>6</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Other deferred charges and assets/Other deferred credits and liabilities</td><td>—</td><td>6</td><td>—</td><td>—</td></tr><tr><td>Total derivatives designated as hedging instruments in cash flow and fair value hedges</td><td>$11</td><td>$ 11</td><td>$ 1</td><td>$ 3</td></tr><tr><td>Derivatives not designated as hedging instruments</td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives:</td><td></td><td></td><td></td><td></td></tr><tr><td>Assets from risk management activities/Other current liabilities</td><td>$ 8</td><td>$ 4</td><td>$ 388</td><td>$ 330</td></tr><tr><td>Other deferred charges and assets/Other deferred credits and liabilities</td><td>1</td><td>—</td><td>270</td><td>232</td></tr><tr><td>Total derivatives not designated as hedging instruments</td><td>$ 9</td><td>$ 4</td><td>$ 658</td><td>$ 562</td></tr><tr><td>Gross amounts recognized</td><td>$35</td><td>$ 27</td><td>$ 665</td><td>$ 566</td></tr><tr><td>Gross amounts offset(a)</td><td>$ (8)</td><td>$ (11)</td><td>$ (503)</td><td>$ (531)</td></tr><tr><td>Net amounts recognized in the Balance Sheets(b)</td><td>$27</td><td>$ 16</td><td>$ 162</td><td>$ 35</td></tr></table>

(a) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $3 million and $28 million at December 31, 2021 and 2020, respectively.
(b) Net amounts of derivative instruments outstanding exclude immaterial premium and intrinsic value associated with weather derivatives for all periods presented.



At December 31, 2021 and 2020, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheets

<table><tr><td>Derivative Category and Balance Sheet Location</td><td>Southern Company</td><td>Alabama Power</td><td>Georgia Power</td><td>Mississippi Power</td><td>Southern Company Gas</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>At December 31, 2021:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other regulatory assets, current</td><td>$ (17)</td><td>$ (6)</td><td>$ —</td><td>$ —</td><td>$ (11)</td></tr><tr><td>Other regulatory liabilities, current</td><td>107</td><td>28</td><td>48</td><td>27</td><td>4</td></tr><tr><td>Other regulatory liabilities, deferred</td><td>65</td><td>22</td><td>19</td><td>24</td><td>—</td></tr><tr><td>Total energy-related derivative gains (losses)</td><td>$ 155</td><td>$ 44</td><td>$ 67</td><td>$ 51</td><td>$ (7)</td></tr><tr><td>At December 31, 2020:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other regulatory assets, deferred</td><td>$ (2)</td><td>$ —</td><td>$ (1)</td><td>$ (1)</td><td>$ —</td></tr><tr><td>Other regulatory liabilities, current</td><td>12</td><td>5</td><td>2</td><td>1</td><td>4</td></tr><tr><td>Other regulatory liabilities, deferred</td><td>2</td><td>1</td><td>1</td><td>—</td><td>—</td></tr><tr><td>Total energy-related derivative gains (losses)</td><td>$ 12</td><td>$ 6</td><td>$ 2</td><td>$ —</td><td>$ 4</td></tr></table>

For the years ended December 31, 2021, 2020, and 2019, the pre-tax effects of cash flow and fair value hedge accounting on AOCI for the applicable Registrants were as follows:

<table><tr><td>Gain (Loss) From Derivatives Recognized in OCI</td><td>2021</td><td>2020</td><td>2019</td></tr><tr><td></td><td></td><td>(in millions)</td><td></td></tr><tr><td>Southern Company</td><td></td><td></td><td></td></tr><tr><td>Cash flow hedges:</td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives</td><td>$ 34</td><td>$ (8)</td><td>$ (13)</td></tr><tr><td>Interest rate derivatives</td><td>5</td><td>(26)</td><td>(57)</td></tr><tr><td>Foreign currency derivatives</td><td>(103)</td><td>48</td><td>(84)</td></tr><tr><td>Fair value hedges(1):</td><td></td><td></td><td></td></tr><tr><td>Foreign currency derivatives</td><td>(3)</td><td>—</td><td>—</td></tr><tr><td>Total</td><td>$ (67)</td><td>$ 14</td><td>$ (154)</td></tr><tr><td>Georgia Power</td><td></td><td></td><td></td></tr><tr><td>Cash flow hedges:</td><td></td><td></td><td></td></tr><tr><td>Interest rate derivatives</td><td>$ —</td><td>$ (3)</td><td>$ (59)</td></tr><tr><td>Southern Power</td><td></td><td></td><td></td></tr><tr><td>Cash flow hedges:</td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives</td><td>$ 12</td><td>$ (2)</td><td>$ (4)</td></tr><tr><td>Foreign currency derivatives</td><td>(103)</td><td>48</td><td>(84)</td></tr><tr><td>Total</td><td>$ (91)</td><td>$ 46</td><td>$ (88)</td></tr><tr><td>Southern Company Gas</td><td></td><td></td><td></td></tr><tr><td>Cash flow hedges:</td><td></td><td></td><td></td></tr><tr><td>Energy-related derivatives</td><td>$ 22</td><td>$ (6)</td><td>$ (9)</td></tr><tr><td>Interest rate derivatives</td><td>—</td><td>(23)</td><td>2</td></tr><tr><td>Total</td><td>$ 22</td><td>$ (29)</td><td>$ (7)</td></tr></table>

(*) Represents amounts excluded from the assessment of effectiveness for which the difference between changes in fair value and periodic amortization is recorded in OCI.

The pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on AOCI were immaterial for the other Registrants for all years presented.



The pre-tax effects of cash flow and fair value hedge accounting on income for the years ended December 31, 2021, 2020, and 2019 were as follows:

<table><tr><td>Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships</td><td>2021</td><td>2020</td><td>2019</td></tr><tr><td></td><td></td><td>(in millions)</td><td></td></tr><tr><td>Southern Company</td><td></td><td></td><td></td></tr><tr><td>Total cost of natural gas</td><td>$ 1,619</td><td>$ 972</td><td>$ 1,319</td></tr><tr><td>Gain (loss) on energy-related cash flow hedges \( ^{(a)} \)</td><td>17</td><td>(8)</td><td>(2)</td></tr><tr><td>Total depreciation and amortization</td><td>3,565</td><td>3,518</td><td>3,038</td></tr><tr><td>Gain (loss) on energy-related cash flow hedges \( ^{(a)} \)</td><td>9</td><td>(3)</td><td>(6)</td></tr><tr><td>Total interest expense, net of amounts capitalized</td><td>(1,837)</td><td>(1,821)</td><td>(1,736)</td></tr><tr><td>Gain (loss) on interest rate cash flow hedges \( ^{(a)} \)</td><td>(27)</td><td>(26)</td><td>(20)</td></tr><tr><td>Gain (loss) on foreign currency cash flow hedges \( ^{(a)} \)</td><td>(24)</td><td>(23)</td><td>(24)</td></tr><tr><td>Gain (loss) on interest rate fair value hedges \( ^{(b)} \)</td><td>(30)</td><td>27</td><td>42</td></tr><tr><td>Total other income (expense), net</td><td>456</td><td>336</td><td>252</td></tr><tr><td>Gain (loss) on foreign currency cash flow hedges \( ^{(a)(c)} \)</td><td>(104)</td><td>114</td><td>(24)</td></tr><tr><td>Gain (loss) on foreign currency fair value hedges</td><td>(63)</td><td>—</td><td>—</td></tr><tr><td>Amount excluded from effectiveness testing recognized in earnings</td><td>3</td><td>—</td><td>—</td></tr><tr><td>Southern Power</td><td></td><td></td><td></td></tr><tr><td>Total depreciation and amortization</td><td>$ 517</td><td>$ 494</td><td>$ 479</td></tr><tr><td>Gain (loss) on energy-related cash flow hedges \( ^{(a)} \)</td><td>9</td><td>(3)</td><td>(6)</td></tr><tr><td>Total interest expense, net of amounts capitalized</td><td>(147)</td><td>(151)</td><td>(169)</td></tr><tr><td>Gain (loss) on foreign currency cash flow hedges \( ^{(a)} \)</td><td>(24)</td><td>(23)</td><td>(24)</td></tr><tr><td>Total other income (expense), net</td><td>10</td><td>19</td><td>47</td></tr><tr><td>Gain (loss) on foreign currency cash flow hedges \( ^{(a)(c)} \)</td><td>(104)</td><td>114</td><td>(24)</td></tr><tr><td>Southern Company Gas</td><td></td><td></td><td></td></tr><tr><td>Total cost of natural gas</td><td>$ 1,619</td><td>$ 972</td><td>$ 1,319</td></tr><tr><td>Gain (loss) on energy-related cash flow hedges \( ^{(a)} \)</td><td>17</td><td>(8)</td><td>(2)</td></tr></table>

(a) Reclassified from AOCI into earnings.

(b) For fair value hedges, changes in the fair value of the derivative contracts are generally equal to changes in the fair value of the underlying debt and have no material impact on income.

(c) The reclassification from AOCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.

The pre-tax effects of cash flow and fair value hedge accounting on income for interest rate derivatives and energy-related derivatives were immaterial for the other Registrants for all years presented.

At December 31, 2021 and 2020, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

<table><tr><td rowspan="2"></td><td colspan="2">Carrying Amount of the Hedged Item</td><td colspan="2">Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item</td></tr><tr><td>At December 31, 2021</td><td>At December 31, 2020</td><td>At December 31, 2021</td><td>At December 31, 2020</td></tr><tr><td>Balance Sheet Location of Hedged Items</td><td colspan="2">(in millions)</td><td colspan="2">(in millions)</td></tr><tr><td>Southern Company</td><td></td><td></td><td></td><td></td></tr><tr><td>Securities due within one year</td><td>$ —</td><td>$(1,509)</td><td>$ —</td><td>$(10)</td></tr><tr><td>Long-term debt</td><td>(3,280)</td><td>—</td><td>9</td><td>—</td></tr><tr><td>Southern Company Gas</td><td></td><td></td><td></td><td></td></tr><tr><td>Long-term debt</td><td>$ (493)</td><td>$ —</td><td>$ 2</td><td>$ —</td></tr></table>



The pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas for the years ended December 31, 2021, 2020, and 2019 were as follows:

<table><tr><td rowspan="2">Derivatives in Non-Designated Hedging Relationships</td><td rowspan="2">Statements of Income Location</td><td colspan="3">Gain (Loss)</td></tr><tr><td>2021</td><td>2020</td><td>2019</td></tr><tr><td></td><td></td><td colspan="3">(in millions)</td></tr><tr><td>Energy-related derivatives</td><td>Natural gas revenues \( ^{(1)} \)</td><td>(117)</td><td>$ 134</td><td>$ 223</td></tr><tr><td></td><td>Cost of natural gas</td><td>(27)</td><td>15</td><td>10</td></tr><tr><td>Total derivatives in non-designated hedging relationships</td><td></td><td>(144)</td><td>$ 149</td><td>$ 233</td></tr></table>

(*) Excludes the impact of weather derivatives recorded in natural gas revenues of $9 million and $3 million for 2020 and 2019, respectively, as they are accounted for based on intrinsic value rather than fair value. There was no weather derivatives impact for 2021.

The pre-tax effects of energy-related derivatives not designated as hedging instruments were immaterial for all other Registrants for all years presented.

## Contingent Features

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At December 31, 2021, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

For the applicable Registrants, the fair value of interest rate and energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial at December 31, 2021. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade. Following the sale of Gulf Power to NextEra Energy, Gulf Power has continued participating in the Southern Company power pool; however, on December 21, 2021, NextEra Energy provided a 180-day notice of its intention to cease such participation.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.

Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions and they may be required to post collateral based on the value of the positions in these accounts and the associated margin requirements. At December 31, 2021, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At December 31, 2021, cash collateral held on deposit in broker margin accounts was immaterial.

The Registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Registrants only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk.

Southern Company Gas uses established credit policies to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. government securities held by a trustee. Prior to entering a physical transaction, Southern Company Gas assigns its counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.



Southern Company Gas utilizes netting agreements whenever possible to mitigate exposure to counterparty credit risk. Netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty across product lines and against cash collateral, provided the netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, counterparties are settled net, they are recorded on a gross basis on the balance sheet as energy marketing receivables and energy marketing payables.

The Registrants do not anticipate a material adverse effect on their respective financial statements as a result of counterparty nonperformance.

## 15. ACQUISITIONS AND DISPOSITIONS

None of the dispositions discussed herein, both individually and combined, represented a strategic shift in operations for the applicable Registrants that has, or is expected to have, a major effect on its operations and financial results; therefore, none of the assets related to the sales have been classified as discontinued operations for any of the periods presented.

## Southern Company

In January 2019, Southern Company completed the sale of all of the capital stock of Gulf Power to a wholly-owned subsidiary of NextEra Energy, for an aggregate cash purchase price of approximately $5.8 billion (less $1.3 billion of indebtedness assumed), including the final working capital adjustments. The gain associated with the sale of Gulf Power totaled $2.6 billion pre-tax ($1.4 billion after tax).

In July 2019, PowerSecure completed the sale of its utility infrastructure services business for approximately $65 million, including the final working capital adjustments. In contemplation of this sale, a goodwill impairment charge of $32 million was recorded in the second quarter 2019. In December 2019, PowerSecure completed the sale of its lighting business for approximately $9 million, which included cash of $4 million and a note receivable from the buyer of $5 million. In contemplation of this sale, an impairment charge of $18 million was recorded in the third quarter 2019 related to goodwill, identifiable intangibles, and other assets.

In December 2019, Southern Company completed the sale of one of its leveraged lease investments for an aggregate cash purchase price of approximately $20 million. The sale resulted in an immaterial gain.

In connection with the annual impairment analysis of a leveraged lease investment during the fourth quarter 2020, Southern Company management concluded that the estimated residual value of the generation assets should be reduced due to significant uncertainty as to whether the related natural gas generation assets would continue to operate at the end of the lease term in 2040 and recorded a $34 million ($17 million after tax) impairment charge. Also during the fourth quarter 2020, Southern Company management initiated steps to sell the investment and reclassified it as held for sale at December 31, 2020. In the fourth quarter 2020 and the second quarter 2021, additional charges of $18 million ($14 million after tax) and $7 million ($6 million after tax), respectively, were recorded to further reduce the investment to its estimated fair value, less costs to sell. On October 29, 2021, Southern Company completed the sale to the lessee for $45 million. No gain or loss was recognized on the sale; however, it did result in the recognition of approximately $16 million of additional tax benefits.

On December 13, 2021, Southern Company completed the termination of its leasehold interest in assets associated with its two international leveraged lease projects and received cash proceeds of approximately $673 million after the accelerated exercise of the lessee's purchase options. The pre-tax gain associated with the transaction was approximately $93 million ($99 million gain after tax).

## Alabama Power

In August 2020, Alabama Power completed its acquisition of the Central Alabama Generating Station, an approximately 885-MW combined cycle generation facility in Autauga County, Alabama. The total purchase price was $461 million, of which $452 million was related to net assets recorded within property, plant, and equipment on the balance sheet and the remainder primarily related to inventory, current receivables, and accounts payable. Alabama Power assumed an existing power sales agreement under which the full output of the generating facility remains committed to another third party for its remaining term of approximately three years. During the remaining term, the estimated revenues from the power sales agreement are expected to offset the associated costs of operation. See Notes 2 and 9 under “Alabama Power” and “Lessor,” respectively, for additional information.

On September 23, 2021, Alabama Power entered into an agreement to acquire all of the equity interests in Calhoun Power Company, LLC, which owns and operates the Calhoun Generating Station. See Note 2 under “Alabama Power – Certificates of Convenience and Necessity” for additional information.

## Southern Power

Southern Power’s acquisition-related costs for the projects discussed under “Asset Acquisitions” and “Construction Projects” below were expensed as incurred and were not material for any of the years presented.



## Asset Acquisitions

<table><tr><td>Project Facility</td><td>Resource</td><td>Seller</td><td>Approximate Nameplate Capacity (MW)</td><td>Location</td><td>Southern Power Ownership Percentage</td><td>COD</td><td>PPA Contract Period</td></tr><tr><td>Asset Acquisitions During 2021</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Deuel Harvest \( ^{(a)} \)</td><td>Wind</td><td>Inverency Renewables LLC</td><td>300</td><td>Deuel County, SD</td><td>100% of Class B</td><td>February 2021</td><td>25 years and 15 years</td></tr><tr><td>Asset Acquisitions During 2020</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Beech Ridge II</td><td>Wind</td><td>Inverency Renewables LLC</td><td>56</td><td>Greenbrier County, WV</td><td>100% of Class A \( ^{(b)} \)</td><td>May 2020</td><td>12 years</td></tr><tr><td>Asset Acquisitions During 2019</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>DSGP \( ^{(c)} \)</td><td>Fuel Cell</td><td>Bloom Energy</td><td>28</td><td>Delaware</td><td>100% of Class B</td><td>N/A \( ^{(d)} \)</td><td>15 years \( ^{(e)} \)</td></tr></table>

(a) On March 26, 2021, Southern Power acquired a controlling interest in the project from Inverency Renewables LLC and, on March 30, 2021, Southern Power completed a tax equity transaction whereby it sold the Class A membership interests in the project. Southern Power consolidates the project's operating results in its financial statements and the tax equity partner and Inverency Renewables LLC each own a noncontrolling interest.

(b) In May 2020, Southern Power purchased a controlling interest and now consolidates the project’s operating results in its financial statements. The Class B member owns the noncontrolling interest.

(c) During 2019, Southern Power purchased a controlling interest and now consolidates the project’s operating results in its financial statements. The Class A and Class C members each own a noncontrolling interest. Southern Power records net income attributable to noncontrolling interests for approximately 10 MWs of the facility.

(d) Southern Power’s 18-MW share of the facility was repowered between June and August 2019. In December 2019, a Class C member joined the existing partnership between the Class A member and Southern Power and made an investment to repower the remaining 10 MWs.

(e) Remaining PPA contract period at the time of acquisition.

## Construction Projects

During 2021, Southern Power completed construction of and placed in service the Glass Sands wind facility, 73 MWs of the Garland battery energy storage facility, and 32 MWs of the Tranquility battery energy storage facility. At December 31, 2021, total costs of construction incurred for these projects were $383 million. Southern Power continues construction of the remainder of the Garland and Tranquility battery energy storage facilities and expects total aggregate construction costs to be between $230 million and $270 million. The ultimate outcome of these matters cannot be determined at this time. See Note 9 under “Lessor” for additional information.

<table><tr><td>Project Facility</td><td>Resource</td><td>Approximate Nameplate Capacity (MW)</td><td>Location</td><td>Actual/Expected COD</td><td>PPA Contract Period</td></tr><tr><td>Projects Under Construction at December 31, 2021</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Tranquility Solar Storage \( ^{(a)} \)</td><td>Battery energy storage system</td><td>72</td><td>Fresno County, CA</td><td>November 2021 and first quarter 2022 \( ^{(b)} \)</td><td>20 years</td></tr><tr><td>Garland Solar Storage \( ^{(a)} \)</td><td>Battery energy storage system</td><td>88</td><td>Kern County, CA</td><td>September 2021, December 2021, and first quarter 2022 \( ^{(c)} \)</td><td>20 years</td></tr><tr><td>Projects Completed During 2021</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Glass Sands \( ^{(d)} \)</td><td>Wind</td><td>118</td><td>Murray County, OK</td><td>November 2021</td><td>12 years</td></tr><tr><td>Projects Completed During 2020</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Skookumchuck \( ^{(e)} \)</td><td>Wind</td><td>136</td><td>Lewis and Thurston Counties, WA</td><td>November 2020</td><td>20 years</td></tr><tr><td>Reading \( ^{(f)} \)</td><td>Wind</td><td>200</td><td>Osage and Lyon Counties, KS</td><td>May 2020</td><td>12 years</td></tr></table>

(a) In December 2020, Southern Power restructured its ownership of the project, while retaining the controlling interests, by contributing the Class A membership interests to an existing partnership and selling 100% of the Class B membership interests. During the third quarter 2021, Southern Power further restructured its ownership in the battery energy storage projects and completed tax equity transactions whereby it sold the Class A membership interests in the projects. Southern Power consolidates each project's operating results in its financial statements and the tax equity partner and two other partners each own a noncontrolling interest.



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

(c) The facility has a total capacity of 88 MWs, of which 73 MWs were placed in service during 2021 and the remaining MWs are expected to be placed in service later in the first quarter 2022.

(d) In December 2020, Southern Power purchased 100% of the membership interests of the Glass Sands facility.

(e) In 2019, Southern Power purchased 100% of the membership interests of the Skookumchuck facility pursuant to a joint development arrangement. In November 2020, Southern Power completed a tax equity transaction whereby it received $121 million, resulting in 100% ownership of the Class B membership interests. Southern Power subsequently sold a noncontrolling interest in the Class B membership interests and now retains the controlling ownership interest in the facility.

(f) In 2018, Southern Power purchased 100% of the membership interests of the Reading facility pursuant to a joint development arrangement. In June 2020, Southern Power completed a tax equity transaction whereby it received $156 million and owns 100% of the Class B membership interests.

## Development Projects

Southern Power continues to evaluate and refine the deployment of the remaining wind turbine equipment purchased in 2016 and 2017 for development and construction projects. Wind projects utilizing equipment purchased in 2016 and 2017, and reaching commercial operation by the end of 2021 and 2022, are expected to qualify for 100% and 80% PTCs, respectively. The significant majority of this equipment either has been deployed to projects that have been completed, are under construction, or are probable of completion, or has been sold to third parties. Gains on wind turbine equipment contributed to various equity method investments totaled approximately $37 million in 2021. Gains on wind turbine equipment sales were immaterial in 2020 and totaled approximately $17 million in 2019.

## Sales of Natural Gas and Biomass Plants

In June 2019, Southern Power completed the sale of its equity interests in Plant Nacogdoches, a 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for a purchase price of approximately $461 million, including final working capital adjustments. Southern Power recorded a gain of $23 million ($88 million after tax) on the sale.

In January 2020, Southern Power completed the sale of its equity interests in Plant Mankato (including the 385-MW expansion unit completed in May 2019) to a subsidiary of Xcel Energy Inc. for a purchase price of approximately $663 million, including final working capital adjustments. The sale resulted in a gain of approximately $39 million ($23 million after tax).

Plant Nacogdoches and Plant Mankato represented individually significant components of Southern Power. Pre-tax income for these components for the years ended December 31, 2020 and 2019 are presented below:

<table><tr><td></td><td>2020</td><td>2019</td></tr><tr><td></td><td>(in millions)</td><td></td></tr><tr><td>Earnings before income taxes:</td><td></td><td></td></tr><tr><td>Plant Nacogdoches \( ^{(a)(b)} \)</td><td>N/A</td><td>$13</td></tr><tr><td>Plant Mankato \( ^{(a)(c)} \)</td><td>$2</td><td>$29</td></tr></table>

(a) Earnings before income taxes reflect the cessation of depreciation and amortization on the long-lived assets being sold upon classification as held for sale (November 2018 for Plant Mankato and April 2019 for Plant Nacogdoches).

(b) 2019 amount represents the period from January 1, 2019 to June 13, 2019 (the divestiture date).

(c) 2020 amount represents the period from January 1, 2020 to January 17, 2020 (the divestiture date).

## Southern Company Gas

## Sale of Sequent

On July 1, 2021, Southern Company Gas affiliates completed the sale of Sequent to Williams Field Services Group for a total cash purchase price of $159 million, including final working capital adjustments. The pre-tax gain associated with the transaction was approximately $121 million ($92 million after tax). As a result of the sale, changes in state apportionment rates resulted in $85 million of additional tax expense.

Prior to the sale, Southern Company Gas had existing agreements in place in which it guaranteed the payment performance of Sequent. Southern Company Gas will continue to guarantee Sequent's payment performance for a period of time as Williams Field Services Group obtains releases from these obligations. At December 31, 2021, the remaining obligations subject to the payment performance guarantee were immaterial. Changes in the price of natural gas, market conditions, and the number of open contracts may change the amount that Southern Company Gas is required to guarantee for Sequent each month.



## Sale of Pivotal LNG and Atlantic Coast Pipeline

In March 2020, Southern Company Gas completed the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline to Dominion Modular LNG Holdings, Inc. and Dominion Atlantic Coast Pipeline, LLC, respectively, with aggregate proceeds of $178 million, including final working capital adjustments. The loss associated with the transactions was immaterial. During 2019, based on the terms of these transactions, Southern Company Gas recorded an asset impairment charge, exclusive of the contingent payments, for Pivotal LNG of approximately $24 million ($17 million after tax) as of December 31, 2019. In connection with the sale, Southern Company Gas was entitled to two $5 million payments contingent upon Dominion Modular LNG Holdings, Inc. meeting certain milestones related to Pivotal LNG. Southern Company Gas received the first payment on April 22, 2021 and expects to receive the second payment in March 2022.

## Sale of Natural Gas Storage Facility

In December 2020, Southern Company Gas completed the sale of Jefferson Island to EnLink Midstream, LLC for a total purchase price of $33 million, including estimated working capital adjustments. The gain associated with the sale totaled $22 million pre-tax ($16 million after tax). In 2019, Southern Company Gas recorded a pre-tax impairment charge of $91 million ($69 million after-tax) related to Jefferson Island.

## Sale of Triton

In May 2019, Southern Company Gas sold its investment in Triton, a cargo container leasing company that was aggregated into Southern Company Gas' all other segment. This disposition resulted in a pre-tax loss of $6 million and a net after-tax gain of $7 million as a result of reversing a $13 million federal income tax valuation allowance.

## 16. SEGMENT AND RELATED INFORMATION

## Southern Company

Southern Company’s reportable business segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $515 million, $364 million, and $398 million in 2021, 2020, and 2019, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies and Southern Power were immaterial and $18 million, respectively, in 2021 (which represented sales from Sequent through June 30, 2021), immaterial and $26 million, respectively, in 2020, and $14 million and $64 million, respectively, in 2019. The “All Other” column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing distributed energy and resilience solutions and deploying microgrids for commercial, industrial, governmental, and utility customers, as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.



Financial data for business segments and products and services for the years ended December 31, 2021, 2020, and 2019 was as follows:

<table><tr><td rowspan="2"></td><td colspan="5">Electric Utilities</td><td rowspan="2">Southern Company Gas</td><td rowspan="2">All Other</td><td rowspan="2">Eliminations</td><td rowspan="2">Consolidated</td></tr><tr><td>Traditional Electric Operating Companies</td><td>Southern Power</td><td>Eliminations</td><td>Total</td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td><td></td></tr><tr><td>2021</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$16,614</td><td>$ 2,216</td><td>$ (530)</td><td>$ 18,300</td><td>$ 4,380</td><td>$ 582</td><td>$ (149)</td><td>$ 23,113</td><td></td></tr><tr><td>Depreciation and amortization</td><td>2,436</td><td>517</td><td>—</td><td>2,953</td><td>536</td><td>76</td><td>—</td><td>3,565</td><td></td></tr><tr><td>Interest income</td><td>20</td><td>1</td><td>—</td><td>21</td><td>—</td><td>4</td><td>(3)</td><td>22</td><td></td></tr><tr><td>Earnings from equity method investments</td><td>1</td><td>—</td><td>—</td><td>1</td><td>50</td><td>24</td><td>1</td><td>76</td><td></td></tr><tr><td>Interest expense</td><td>821</td><td>147</td><td>—</td><td>968</td><td>238</td><td>631</td><td>—</td><td>1,837</td><td></td></tr><tr><td>Income taxes (benefit)</td><td>232</td><td>(13)</td><td>—</td><td>219</td><td>275</td><td>(227)</td><td>—</td><td>267</td><td></td></tr><tr><td>Segment net income (loss) \( ^{(a)(b)(c)(d)(e)(f)} \)</td><td>1,981</td><td>266</td><td>—</td><td>2,247</td><td>539</td><td>(384)</td><td>(9)</td><td>2,393</td><td></td></tr><tr><td>Goodwill</td><td>—</td><td>2</td><td>—</td><td>2</td><td>5,015</td><td>263</td><td>—</td><td>5,280</td><td></td></tr><tr><td>Assets held for sale</td><td>39</td><td>—</td><td>—</td><td>39</td><td>—</td><td>3</td><td>—</td><td>42</td><td></td></tr><tr><td>Total assets</td><td>89,051</td><td>13,390</td><td>(667)</td><td>101,774</td><td>23,560</td><td>2,975</td><td>(775)</td><td>127,534</td><td></td></tr><tr><td>2020</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$15,135</td><td>$ 1,733</td><td>$ (371)</td><td>$ 16,497</td><td>$ 3,434</td><td>$ 596</td><td>$ (152)</td><td>$ 20,375</td><td></td></tr><tr><td>Depreciation and amortization</td><td>2,447</td><td>494</td><td>—</td><td>2,941</td><td>500</td><td>77</td><td>—</td><td>3,518</td><td></td></tr><tr><td>Interest income</td><td>26</td><td>4</td><td>—</td><td>30</td><td>5</td><td>6</td><td>(4)</td><td>37</td><td></td></tr><tr><td>Earnings from equity method investments</td><td>—</td><td>—</td><td>—</td><td>—</td><td>141</td><td>12</td><td>—</td><td>153</td><td></td></tr><tr><td>Interest expense</td><td>825</td><td>151</td><td>—</td><td>976</td><td>231</td><td>614</td><td>—</td><td>1,821</td><td></td></tr><tr><td>Income taxes (benefit)</td><td>514</td><td>3</td><td>—</td><td>517</td><td>173</td><td>(297)</td><td>—</td><td>393</td><td></td></tr><tr><td>Segment net income (loss) \( ^{(a)(b)(f)(g)(h)} \)</td><td>2,877</td><td>238</td><td>—</td><td>3,115</td><td>590</td><td>(592)</td><td>6</td><td>3,119</td><td></td></tr><tr><td>Goodwill</td><td>—</td><td>2</td><td>—</td><td>2</td><td>5,015</td><td>263</td><td>—</td><td>5,280</td><td></td></tr><tr><td>Assets held for sale</td><td>5</td><td>—</td><td>—</td><td>5</td><td>—</td><td>55</td><td>—</td><td>60</td><td></td></tr><tr><td>Total assets</td><td>85,486</td><td>13,235</td><td>(680)</td><td>98,041</td><td>22,630</td><td>3,168</td><td>(904)</td><td>122,935</td><td></td></tr><tr><td>2019</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$15,569</td><td>$ 1,938</td><td>$ (412)</td><td>$ 17,095</td><td>$ 3,792</td><td>$ 690</td><td>$ (158)</td><td>$ 21,419</td><td></td></tr><tr><td>Depreciation and amortization</td><td>1,993</td><td>479</td><td>—</td><td>2,472</td><td>487</td><td>79</td><td>—</td><td>3,038</td><td></td></tr><tr><td>Interest income</td><td>38</td><td>9</td><td>—</td><td>47</td><td>3</td><td>16</td><td>(6)</td><td>60</td><td></td></tr><tr><td>Earnings from equity method investments</td><td>2</td><td>3</td><td>—</td><td>5</td><td>157</td><td>—</td><td>—</td><td>162</td><td></td></tr><tr><td>Interest expense</td><td>818</td><td>169</td><td>—</td><td>987</td><td>232</td><td>517</td><td>—</td><td>1,736</td><td></td></tr><tr><td>Income taxes (benefit)</td><td>764</td><td>(56)</td><td>—</td><td>708</td><td>130</td><td>960</td><td>—</td><td>1,798</td><td></td></tr><tr><td>Segment net income (loss) \( ^{(a)(b)(f)(g)(h)(i)} \)</td><td>2,929</td><td>339</td><td>—</td><td>3,268</td><td>585</td><td>908</td><td>(22)</td><td>4,739</td><td></td></tr><tr><td>Goodwill</td><td>—</td><td>2</td><td>—</td><td>2</td><td>5,015</td><td>263</td><td>—</td><td>5,280</td><td></td></tr><tr><td>Assets held for sale</td><td>—</td><td>618</td><td>—</td><td>618</td><td>171</td><td>—</td><td>—</td><td>789</td><td></td></tr><tr><td>Total assets</td><td>81,063</td><td>14,300</td><td>(713)</td><td>94,650</td><td>21,687</td><td>3,511</td><td>(1,148)</td><td>118,700</td><td></td></tr></table>

(a) Attributable to Southern Company.

(b) For the traditional electric operating companies, includes pre-tax charges at Georgia Power for estimated losses associated with the construction of Plant Vogtle Units 3 and 4 of $1.7 billion ($1.3 billion after tax) in 2021 and $325 million ($242 million after tax) in 2020. See Note 2 under “Georgia Power – Nuclear Construction” for additional information.

(c) For Southern Power, includes gains on wind turbine equipment contributed to various equity method investments totaling approximately $37 million pre-tax ($28 million after tax). See Notes 7 and 15 under "Southern Power" for additional information.



(d) For Southern Company Gas, includes a pre-tax gain of $121 million ($92 million after tax) related to its sale of Sequent, as well as the resulting $85 million of additional tax expense due to changes in state apportionment rates, and pre-tax impairment charges totaling $84 million ($67 million after tax) related to its equity method investment in the PennEast Pipeline project. See Notes 7 and 15 under "Southern Company Gas" for additional information.

(e) For the "All Other" column, includes a pre-tax gain of $93 million ($99 million gain after tax) associated with the termination of two leveraged leases projects. See Note 15 under "Southern Company" for additional information.

(f) For the "All Other" column, includes pre-tax impairment charges totaling $67 million ($6 million after tax) in 2021, $206 million ($105 million after tax) in 2020, and $17 million ($13 million after tax) in 2019 related to leveraged lease investments. See Notes 9 and 15 under "Southern Company Leveraged Lease" and "Southern Company," respectively, for additional information.

(g) For Southern Power, includes a $39 million pre-tax gain ($23 million gain after tax) on the sale of Plant Mankato. See Note 15 under "Southern Power" for additional information.

(h) For Southern Company Gas, includes a $22 million pre-tax gain ($16 million gain after tax) on the sale of Jefferson Island. See Note 15 under "Southern Company Gas" for additional information.

(i) For Southern Power, includes a $23 million pre-tax gain ($88 million gain after tax) on the sale of Plant Nacogdoches. See Note 15 under "Southern Power" for additional information.

(j) For Southern Company Gas, includes pre-tax impairment charges totaling $115 million ($86 million after tax). See Note 15 under "Southern Company Gas" for additional information.

(k) For the "All Other" column, includes the pre-tax gain associated with the sale of Gulf Power of $2.6 billion ($1.4 billion after tax) and the pre-tax loss, including related impairment charges, on the sales of certain PowerSecure business units totaling $58 million ($52 million after tax). See Note 15 under "Southern Company" for additional information.

## Products and Services

<table><tr><td rowspan="2">Year</td><td colspan="4">Electric Utilities’ Revenues</td></tr><tr><td>Retail</td><td>Wholesale</td><td>Other</td><td>Total</td></tr><tr><td></td><td colspan="4">(in millions)</td></tr><tr><td>2021</td><td>$14,852</td><td>$2,455</td><td>$993</td><td>$18,300</td></tr><tr><td>2020</td><td>13,643</td><td>1,945</td><td>909</td><td>16,497</td></tr><tr><td>2019</td><td>14,084</td><td>2,152</td><td>859</td><td>17,095</td></tr></table>

<table><tr><td rowspan="2">Year</td><td colspan="4">Southern Company Gas’ Revenues</td></tr><tr><td>Gas Distribution Operations</td><td>Gas Marketing Services</td><td>All Other</td><td>Total</td></tr><tr><td></td><td colspan="4">(in millions)</td></tr><tr><td>2021</td><td>$3,656</td><td>$475</td><td>$249</td><td>$4,380</td></tr><tr><td>2020</td><td>2,902</td><td>408</td><td>124</td><td>3,434</td></tr><tr><td>2019</td><td>3,001</td><td>456</td><td>335</td><td>3,792</td></tr></table>

## Southern Company Gas

Southern Company Gas manages its business through three reportable segments – gas distribution operations, gas pipeline investments, and gas marketing services. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' reportable segments also included wholesale gas services. The non-reportable segments are combined and presented as all other. See Note 15 under "Southern Company Gas" for additional information on the disposition activities described herein.

Gas distribution operations is the largest component of Southern Company Gas' business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in four states.

Gas pipeline investments consist of joint ventures in natural gas pipeline investments including a 50% interest in SNG and a 50% joint ownership interest in the Dalton Pipeline. These natural gas pipelines enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas. Gas pipeline investments also includes a 20% ownership interest in the PennEast Pipeline project, which was cancelled in September 2021, and through its March 24, 2020 sale, included a 5% ownership interest in the Atlantic Coast Pipeline construction project. See Notes 5 and 7 for additional information.

Through July 1, 2021, wholesale gas services provided natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services engaged in natural gas storage and gas pipeline arbitrage and related activities.

Gas marketing services provides natural gas marketing to end-use customers primarily in Georgia and Illinois through SouthStar.

The all other column includes segments and subsidiaries that fall below the quantitative threshold for separate disclosure, including storage and fuels operations. The all other column included Jefferson Island through its sale on December 1, 2020, Pivotal LNG through its sale on March 24, 2020, and the investment in Triton through its sale on May 29, 2019.



Financial data for business segments for the years ended December 31, 2021, 2020, and 2019 was as follows:

<table><tr><td></td><td>Gas Distribution Operations</td><td>Gas Pipeline Investments</td><td>Wholesale Gas Services(a)</td><td>Gas Marketing Services</td><td>Total</td><td>All Other</td><td>Eliminations</td><td>Consolidated</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td><td></td></tr><tr><td>2021</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$ 3,679</td><td>$ 32</td><td>$188</td><td>$ 475</td><td>$ 4,374</td><td>$ 38</td><td>$ (32)</td><td>$ 4,380</td></tr><tr><td>Depreciation and amortization</td><td>482</td><td>5</td><td>—</td><td>18</td><td>505</td><td>31</td><td>—</td><td>536</td></tr><tr><td>Operating income (loss)</td><td>708</td><td>21</td><td>241</td><td>125</td><td>1,095</td><td>(40)</td><td>—</td><td>1,055</td></tr><tr><td>Earnings from equity method investments</td><td>—</td><td>50</td><td>—</td><td>—</td><td>50</td><td>—</td><td>—</td><td>50</td></tr><tr><td>Interest expense</td><td>207</td><td>25</td><td>2</td><td>3</td><td>237</td><td>1</td><td>—</td><td>238</td></tr><tr><td>Income taxes (benefit)</td><td>120</td><td>27</td><td>32</td><td>34</td><td>213</td><td>62</td><td>—</td><td>275</td></tr><tr><td>Segment net income (loss)(b)(c)(d)</td><td>412</td><td>19</td><td>107</td><td>88</td><td>626</td><td>(87)</td><td>—</td><td>539</td></tr><tr><td>Total assets</td><td>20,917</td><td>1,467</td><td>31</td><td>1,556</td><td>23,971</td><td>12,114</td><td>(12,525)</td><td>23,560</td></tr><tr><td>2020</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$ 2,952</td><td>$ 32</td><td>$ 74</td><td>$ 408</td><td>$ 3,466</td><td>$ 36</td><td>$ (68)</td><td>$ 3,434</td></tr><tr><td>Depreciation and amortization</td><td>442</td><td>5</td><td>1</td><td>22</td><td>470</td><td>30</td><td>—</td><td>500</td></tr><tr><td>Operating income (loss)</td><td>655</td><td>20</td><td>20</td><td>119</td><td>814</td><td>(7)</td><td>5</td><td>812</td></tr><tr><td>Earnings from equity method investments</td><td>—</td><td>141</td><td>—</td><td>—</td><td>141</td><td>—</td><td>—</td><td>141</td></tr><tr><td>Interest expense</td><td>192</td><td>29</td><td>4</td><td>3</td><td>228</td><td>3</td><td>—</td><td>231</td></tr><tr><td>Income taxes (benefit)</td><td>114</td><td>33</td><td>3</td><td>28</td><td>178</td><td>(5)</td><td>—</td><td>173</td></tr><tr><td>Segment net income (loss)(e)</td><td>390</td><td>99</td><td>14</td><td>89</td><td>592</td><td>(2)</td><td>—</td><td>590</td></tr><tr><td>Total assets</td><td>19,090</td><td>1,597</td><td>850</td><td>1,503</td><td>23,040</td><td>11,336</td><td>(11,746)</td><td>22,630</td></tr><tr><td>2019</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$ 3,028</td><td>$ 32</td><td>$ 294</td><td>$ 456</td><td>$ 3,810</td><td>$ 44</td><td>$ (62)</td><td>$ 3,792</td></tr><tr><td>Depreciation and amortization</td><td>422</td><td>5</td><td>1</td><td>26</td><td>454</td><td>33</td><td>—</td><td>487</td></tr><tr><td>Operating income (loss)</td><td>573</td><td>20</td><td>219</td><td>112</td><td>924</td><td>(154)</td><td>—</td><td>770</td></tr><tr><td>Earnings from equity method investments</td><td>—</td><td>162</td><td>—</td><td>—</td><td>162</td><td>(5)</td><td>—</td><td>157</td></tr><tr><td>Interest expense</td><td>187</td><td>30</td><td>5</td><td>3</td><td>225</td><td>7</td><td>—</td><td>232</td></tr><tr><td>Income taxes (benefit)</td><td>63</td><td>58</td><td>52</td><td>27</td><td>200</td><td>(70)</td><td>—</td><td>130</td></tr><tr><td>Segment net income (loss)(f)</td><td>337</td><td>94</td><td>163</td><td>83</td><td>677</td><td>(92)</td><td>—</td><td>585</td></tr><tr><td>Total assets</td><td>18,204</td><td>1,678</td><td>850</td><td>1,496</td><td>22,228</td><td>10,759</td><td>(11,300)</td><td>21,687</td></tr></table>

(a) The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.

<table><tr><td></td><td>Third Party Gross Revenues</td><td>Inter-company Revenues</td><td>Total Gross Revenues</td><td>Less Gross Gas Costs</td><td>Operating Revenues</td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>2021</td><td>$3,881</td><td>$ 90</td><td>$3,971</td><td>$3,783</td><td>$188</td></tr><tr><td>2020</td><td>4,544</td><td>115</td><td>4,659</td><td>4,585</td><td>74</td></tr><tr><td>2019</td><td>5,703</td><td>275</td><td>5,978</td><td>5,684</td><td>294</td></tr></table>

(b) For gas pipeline investments, includes pre-tax impairment charges totaling $84 million ($67 million after tax) related to the equity method investment in the PennEast Pipeline project. See Note 7 under "Southern Company Gas" for additional information.

(c) For wholesale gas services, includes a pre-tax gain of $121 million ($92 million after tax) related to the sale of Sequent.

(d) For the "All Other" column, includes $85 million of additional tax expense due to changes in state apportionment rates as a result of the sale of Sequent.

(e) For the "All Other" column includes a $22 million pre-tax gain ($16 million gain after tax) on the sale of Jefferson Island.

(f) For the "All Other" column, includes pre-tax impairment charges totaling $115 million ($86 million after tax). See Note 15 under "Southern Company Gas" for additional information.



## Shareholder Information

## Transfer Agent

EQ Shareowner Services is Southern Company’s transfer agent, dividend-paying agent, investment plan administrator and registrar. If you have questions concerning your registered Southern Company shareowner account, please contact:

EQ Shareowner Services
1110 Centre Pointe Curve, Suite 101
Mendota Heights, Minnesota 55120

Telephone: 1.800.554.7626
Website: shareowneronline.com

Southern Company Shareholder Relations
Telephone: 404.506.0965
Email: shareholderservices@southernco.com

## Southern Investment Plan

The Southern Investment Plan is a convenient way to become a Southern Company shareholder. Participants in the Plan can purchase additional shares in Southern Company through optional cash purchases and reinvestment of dividends. The Southern Investment Plan prospectus can be found at investor.southerncompany.com/shareowner-services.

## Dividend Payments

Southern Company has paid dividends since 1948. Historically, dividends are declared and paid quarterly at the discretion of the Board of Directors.

## Auditors

Deloitte & Touche LLP
191 Peachtree St. NE
Suite 2000
Atlanta, GA 30303

## Investor Information

For information about earnings and dividends, stock quotes and current news releases, please visit us at investor.southerncompany.com.

## Institutional Investor Inquiries

Southern Company maintains an investor relations office in Atlanta, Georgia, 404.506.0901, to meet the information needs of institutional investors and securities analysts.
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Environmental, Social and Governance (ESG) Information
Southern Company publishes ESG information at
www.southerncompany.com/sustainability.

## Common Stock

Southern Company common stock is listed on the NYSE under the ticker symbol SO. On January 31, 2022, Southern Company had 103,154 shareholders of record.

The 2021 annual report is submitted for shareholders' information. It is not intended for use in connection with any sale or purchase of, or any solicitation of, offers to buy or sell securities.

Southern Company is a holding company that conducts business through its subsidiaries. Unless the context otherwise requires, references to Southern Company’s customers, communities and operations in this 2021 annual report refer to the customers, communities and operations of its subsidiaries.

Pages 16-198 of this 2021 annual report contain excerpts from Southern Company’s Annual Report on Form 10-K for the year ended December 31, 2021, which was filed with the SEC on February 16, 2022. Information in these pages is provided as of the February 16, 2022 filing date and has not been updated for any subsequent events or developments.

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