SOUTHERN CO - Annual Report: 2018 (Form 10-K)

Table of Contents Index to Financial Statements

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Fiscal Year Ended December 31, 2018 OR
¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Transition Period from to



Commission File Number	Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification No.
1-3526	The Southern Company	58-0690070
	(A Delaware Corporation)
	30 Ivan Allen Jr. Boulevard, N.W.
	Atlanta, Georgia 30308
	(404) 506-5000

1-3164	Alabama Power Company	63-0004250
	(An Alabama Corporation)
	600 North 18th Street
	Birmingham, Alabama 35291
	(205) 257-1000

1-6468	Georgia Power Company	58-0257110
	(A Georgia Corporation)
	241 Ralph McGill Boulevard, N.E.
	Atlanta, Georgia 30308
	(404) 506-6526

001-11229	Mississippi Power Company	64-0205820
	(A Mississippi Corporation)
	2992 West Beach Boulevard
	Gulfport, Mississippi 39501
	(228) 864-1211

001-37803	Southern Power Company	58-2598670
	(A Delaware Corporation)
	30 Ivan Allen Jr. Boulevard, N.W.
	Atlanta, Georgia 30308
	(404) 506-5000

1-14174	Southern Company Gas	58-2210952
	(A Georgia Corporation)
	Ten Peachtree Place, N.E.
	Atlanta, Georgia 30309
	(404) 584-4000

Table of Contents Index to Financial Statements

Securities registered pursuant to Section 12(b) of the Act:⁽¹⁾

Each of the following classes or series of securities registered pursuant to Section 12(b) of the Act is listed on the New York Stock Exchange.



Title of each class		Registrant
Common Stock, $5 par value		The Southern Company

Junior Subordinated Notes, $25 denominations
6.25% Series 2015A due 2075
5.25% Series 2016A due 2076
5.25% Series 2017B due 2077


Class A preferred stock, cumulative, $25 stated capital		Alabama Power Company
5.00% Series


Junior Subordinated Notes, $25 denominations		Georgia Power Company
5.00% Series 2017A due 2077


Senior Notes		Southern Power Company
1.000% Series 2016A due 2022
1.850% Series 2016B due 2026


	Securities registered pursuant to Section 12(g) of the Act:⁽¹⁾

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



(1)	At December 31, 2018.

Table of Contents Index to Financial Statements

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



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

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

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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



Registrant	Large Accelerated Filer	Accelerated Filer	Non-accelerated Filer	Smaller Reporting Company	Emerging Growth Company
The Southern Company	X
Alabama Power Company			X
Georgia Power Company			X
Mississippi Power Company			X
Southern Power Company			X
Southern Company Gas			X

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

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

Table of Contents Index to Financial Statements

Aggregate market value of The Southern Company's common stock held by non-affiliates of The Southern Company at June 29, 2018: $47.0 billion. All of the common stock of the other registrants is held by The Southern Company. A description of each registrant's common stock follows:



Registrant	Description of Common Stock	Shares Outstanding at January 31, 2019
The Southern Company	Par Value $5 Per Share	1,034,564,279
Alabama Power Company	Par Value $40 Per Share	30,537,500
Georgia Power Company	Without Par Value	9,261,500
Mississippi Power Company	Without Par Value	1,121,000
Southern Power Company	Par Value $0.01 Per Share	1,000
Southern Company Gas	Par Value $0.01 Per Share	100

Documents incorporated by reference: specified portions of The Southern Company's Definitive Proxy Statement on Schedule 14A relating to the 2019 Annual Meeting of Stockholders are incorporated by reference into PART III. In addition, specified portions of the Definitive Information Statement on Schedule 14C of Alabama Power Company relating to its 2019 Annual Meeting of Shareholders are incorporated by reference into PART III.

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

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

Table of Contents Index to Financial Statements

Table of Contents



		Page
	PART I
Item 1	Business	I-1
	The Southern Company System	I-2
	Construction Programs	I-8
	Financing Programs	I-9
	Fuel Supply	I-9
	Territory Served by the Southern Company System	I-10
	Competition	I-12
	Seasonality	I-13
	Regulation	I-13
	Rate Matters	I-15
	Employee Relations	I-17
Item 1A	Risk Factors	I-19
Item 1B	Unresolved Staff Comments	I-37
Item 2	Properties	I-38
Item 3	Legal Proceedings	I-46
Item 4	Mine Safety Disclosures	I-46
	Executive Officers of Southern Company	I-47
	Executive Officers of Alabama Power	I-49
	PART II
Item 5	Market for Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	II-1
Item 6	Selected Financial Data	II-2
Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	II-15
Item 7A	Quantitative and Qualitative Disclosures about Market Risk	II-213
Item 8	Financial Statements and Supplementary Data	II-214
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	II-433
Item 9A	Controls and Procedures	II-433
Item 9B	Other Information	II-440
	PART III
Item 10	Directors, Executive Officers and Corporate Governance	III-1
Item 11	Executive Compensation	III-1
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	III-1
Item 13	Certain Relationships and Related Transactions, and Director Independence	III-1
Item 14	Principal Accountant Fees and Services	III-2
	PART IV
Item 15	Exhibits and Financial Statement Schedules	IV-1
Item 16	Form 10-K Summary	IV-1
	Signatures

Table of Contents Index to Financial Statements

DEFINITIONS

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



Term	Meaning
2013 ARP	Alternative Rate Plan approved by the Georgia PSC in 2013 for Georgia Power for the years 2014 through 2016 and subsequently extended through 2019
AFUDC	Allowance for funds used during construction
Alabama Power	Alabama Power Company
AMEA	Alabama Municipal Electric Authority
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 has a 5% ownership interest
Bcf	Billion cubic feet
Bechtel	Bechtel Power Corporation, the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4
Bechtel Agreement	The October 23, 2017 construction completion agreement between the Vogtle Owners and Bechtel
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 cooperative in Mississippi
CPCN	Certificate of public convenience and necessity
Customer Refunds	Refunds issued to Georgia Power customers in 2018 as ordered by the Georgia PSC related to the Guarantee Settlement Agreement
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
Duke Energy Florida	Duke Energy Florida, LLC
EBIT	Earnings before interest and taxes
ECM	Mississippi Power's energy cost management clause
ECO Plan	Mississippi Power's environmental compliance overview plan
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

Table of Contents Index to Financial Statements

DEFINITIONS

(continued)



Term	Meaning
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FFB	Federal Financing Bank
Fitch	Fitch Ratings, Inc.
FMPA	Florida Municipal Power Agency
GAAP	U.S. generally accepted accounting principles
Georgia Power	Georgia Power Company
Georgia Power 2019 Base Rate Case	Georgia Power's base rate case scheduled to be filed by July 1, 2019
Georgia Power Tax Reform Settlement Agreement	A settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation, as approved by the Georgia PSC on April 3, 2018
GHG	Greenhouse gas
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
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
Horizon Pipeline	Horizon Pipeline Company, LLC
IBEW	International Brotherhood of Electrical Workers
IGCC	Integrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility (Plant Ratcliffe)
IIC	Intercompany Interchange Contract
Illinois Commission	Illinois Commerce Commission
Interim Assessment Agreement	Agreement entered into by the Vogtle Owners and the EPC Contractor to allow construction to continue after the EPC Contractor's bankruptcy filing
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
KUA	Kissimmee Utility Authority
KW	Kilowatt
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
LIFO	Last-in, first-out
LNG	Liquefied natural gas
Loan Guarantee Agreement	Loan guarantee agreement entered into by Georgia Power with the DOE in 2014, 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
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

iii

Table of Contents Index to Financial Statements

DEFINITIONS

(continued)



Term	Meaning
MEAG	Municipal Electric Authority of Georgia
Merger	The merger, effective July 1, 2016, of a wholly-owned, direct subsidiary of Southern Company with and into Southern Company Gas, with Southern Company Gas continuing as the surviving corporation
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
MWH	Megawatt hour
natural gas distribution utilities	Southern Company Gas' natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, Elizabethtown Gas, Florida City Gas, Chattanooga Gas, and Elkton Gas as of June 30, 2018) (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas as of July 29, 2018)
NCCR	Georgia Power's Nuclear Construction Cost Recovery
NDR	Alabama Power's Natural Disaster Reserve
NextEra Energy	NextEra Energy, Inc.
Nicor Gas	Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas
NO_X	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 Electric Membership Corporation)
OTC	Over-the-counter
OUC	Orlando Utilities Commission
PATH Act	Protecting Americans from Tax Hikes Act
PennEast Pipeline	PennEast Pipeline Company, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas has a 20% ownership interest
PEP	Mississippi Power's Performance Evaluation Plan
Piedmont	Piedmont Natural Gas Company, Inc.
Pivotal Home Solutions	Nicor Energy Services Company, until June 4, 2018 a wholly-owned subsidiary of Southern Company Gas, doing business as Pivotal Home Solutions
Pivotal Utility Holdings	Pivotal Utility Holdings, Inc., until July 29, 2018 a wholly-owned subsidiary of Southern Company Gas, doing business as Elizabethtown Gas (until July 1, 2018), Elkton Gas (until July 1, 2018), and Florida City Gas
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
PowerSecure	PowerSecure Inc.
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
PRP	Pipeline Replacement Program, Atlanta Gas Light's 15-year infrastructure replacement program, which ended in December 2013
PSC	Public Service Commission
PTC	Production tax credit

Table of Contents Index to Financial Statements

DEFINITIONS

(continued)



Term	Meaning
Rate CNP	Alabama Power's Rate Certificated New Plant
Rate CNP Compliance	Alabama Power's Rate Certificated New Plant Compliance
Rate CNP PPA	Alabama Power's Rate Certificated New Plant Power Purchase Agreement
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
revenue from contracts with customers	Revenue from contracts accounted for under the guidance of ASC 606, Revenue from Contracts with Customers
ROE	Return on equity
RUS	Rural Utilities Service
S&P	S&P Global Ratings, a division of S&P Global Inc.
SCS	Southern Company Services, Inc. (the Southern Company system service company)
SEC	U.S. Securities and Exchange Commission
SEGCO	Southern Electric Generating Company
SEPA	Southeastern Power Administration
Sequent	Sequent Energy Management, L.P.
SERC	Southeastern Electric Reliability Council
SNG	Southern Natural Gas Company, L.L.C.
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 Gas Dispositions	Southern Company Gas' disposition of Pivotal Home Solutions, Pivotal Utility Holdings' disposition of Elizabethtown Gas and Elkton Gas, and NUI Corporation's disposition of Pivotal Utility Holdings, which primarily consisted of Florida City Gas
Southern Company system	Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), SEGCO, Southern Nuclear, SCS, Southern Linc, PowerSecure (as of May 9, 2016), and other subsidiaries
Southern Holdings	Southern Company Holdings, Inc.
Southern Linc	Southern Communications Services, Inc.
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company and its subsidiaries
SouthStar	SouthStar Energy Services, LLC
SP Solar	SP Solar Holdings I, LP
SP Wind	SP Wind Holdings II, LLC
SRR	Mississippi Power's System Restoration Rider, a tariff for retail property damage reserve
STRIDE	Atlanta Gas Light's Strategic Infrastructure Development and Enhancement program
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, parent company of Westinghouse
traditional electric operating companies	Alabama Power, Georgia Power, Gulf Power, and Mississippi Power through December 31, 2018; Alabama Power, Georgia Power, and Mississippi Power as of January 1, 2019
Triton	Triton Container Investments, LLC

Table of Contents Index to Financial Statements

DEFINITIONS

(continued)



Term	Meaning
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, and Dalton
Vogtle Services Agreement	The June 9, 2017 services agreement between the Vogtle Owners and the EPC Contractor, as amended and restated on July 20, 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

Table of Contents Index to Financial Statements

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Annual Report on Form 10-K contains forward-looking statements. Forward-looking statements include, among other things, statements concerning regulated rates, the strategic goals for the business, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, projected equity ratios, current and proposed environmental regulations and related compliance plans and estimated expenditures, 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 of construction projects, completion of announced dispositions, 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 environmental laws and regulations, and also changes in tax (including the Tax Reform Legislation) 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 extent and timing of costs and liabilities to comply with federal and state laws, regulations, and legal requirements related to CCR, including amounts for required closure of ash ponds and ground water monitoring;


•	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, including Plant Vogtle Units 3 and 4 which includes components based on new technology that only recently began initial operation in the global nuclear industry at this scale, including changes in labor costs, availability, and productivity; challenges with management of contractors, subcontractors, or vendors; adverse weather conditions; shortages, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; non-performance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance matters, including the timely resolution of ITAAC and the related approvals by the NRC; challenges with start-up activities, including major equipment failure and system integration; and/or operational performance;


•	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;


•	the ability to control operating and maintenance costs;


•	ongoing renewable energy partnerships and development agreements;


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

vii

Table of Contents Index to Financial Statements

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)


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


•	legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals 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 with respect to the portion of MEAG's ownership interest in Plant Vogtle Units 3 and 4 involving JEA, any inability of Georgia Power to receive repayment of such funding;


•	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, including the proposed disposition of Plant Mankato, 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 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, or other similar occurrences;


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


•	impairments of goodwill or long-lived assets;


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


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

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

viii

Table of Contents Index to Financial Statements

PART I


Item 1.	BUSINESS

Southern Company was incorporated under the laws of Delaware on November 9, 1945. Southern Company owns all of the outstanding common stock of Alabama Power, Georgia Power, and Mississippi Power, each of which is an operating public utility company. The traditional electric operating companies supply electric service in the states of Alabama, Georgia, and Mississippi. More particular information relating to each of the traditional electric operating companies is as follows:

Alabama Power is a corporation organized under the laws of the State of Alabama on November 10, 1927, by the consolidation of a predecessor Alabama Power Company, Gulf Electric Company, and Houston Power Company. The predecessor Alabama Power Company had been in continuous existence since its incorporation in 1906.

Georgia Power was incorporated under the laws of the State of Georgia on June 26, 1930.

Mississippi Power was incorporated under the laws of the State of Mississippi on July 12, 1972 and effective December 21, 1972, by the merger into it of the predecessor Mississippi Power Company, succeeded to the business and properties of the latter company. The predecessor Mississippi Power Company was incorporated under the laws of the State of Maine on November 24, 1924.

On January 1, 2019, Southern Company completed its sale of Gulf Power to NextEra Energy for an aggregate cash purchase price of approximately $5.8 billion (less $1.3 billion of indebtedness assumed), subject to customary working capital adjustments. Gulf Power is an electric utility serving retail customers in the northwestern portion of Florida. See Note 15 to the financial statements under "Southern Company's Sale of Gulf Power" in Item 8 herein for additional information.

In addition, Southern Company owns all of the common stock of Southern Power Company, which is also an operating public utility company. The term "Southern Power" when used herein refers to Southern Power Company and its subsidiaries, while the term "Southern Power Company" when used herein refers only to the Southern Power parent company. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power Company is a corporation organized under the laws of Delaware on January 8, 2001. On May 22, 2018, Southern Power sold a noncontrolling 33% equity interest in SP Solar, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, for approximately $1.2 billion and, on December 11, 2018, Southern Power sold a noncontrolling tax equity interest in SP Wind, a holding company owning a portfolio of eight operating wind facilities, for approximately $1.2 billion. Southern Power also sold all of its equity interests in Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) to NextEra Energy on December 4, 2018 for $203 million. On November 5, 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for approximately $650 million. The transaction is subject to FERC and state commission approvals and is expected to close mid-2019. The ultimate outcome of this matter cannot be determined at this time. See "The Southern Company System – Southern Power" herein and Note 15 to the financial statements in Item 8 herein for additional information.

Southern Company acquired all of the common stock of Southern Company Gas in July 2016. 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 Gas was incorporated under the laws of the State of Georgia on November 27, 1995 for the primary purpose of becoming the holding company for Atlanta Gas Light, which was founded in 1856. In July 2018, Southern Company Gas completed sales of three of its natural gas distribution utilities (Elizabethtown Gas, Florida City Gas, and Elkton Gas). In June 2018, Southern Company Gas also completed the sale of Pivotal Home Solutions, which provided home equipment protection products and services. See "The Southern Company System – Southern Company Gas" herein and Note 15 to the financial statements in Item 8 herein for additional information.

Southern Company also owns all of the outstanding common stock or membership interests of 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 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 within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases and energy-related funds and companies, and for other electric and natural gas products and

I-1

Table of Contents Index to Financial Statements

services. 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 is a provider of energy solutions, including distributed energy infrastructure, energy efficiency products and services, and utility infrastructure services, to customers.

Alabama Power and Georgia Power each own 50% of the outstanding common stock of SEGCO. SEGCO is an operating public utility company that owns electric generating units with an aggregate capacity of 1,020 MWs at Plant Gaston on the Coosa River near Wilsonville, Alabama. Alabama Power and Georgia Power are each entitled to one-half of SEGCO's capacity and energy. Alabama Power acts as SEGCO's agent in the operation of SEGCO's units and furnishes fuel to SEGCO for its units. See Note 7 to the financial statements in Item 8 herein for additional information.

Segment information for Southern Company and Southern Company Gas is included in Note 16 to the financial statements in Item 8 herein.

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

The Southern Company System

Traditional Electric Operating Companies

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

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

The utility assets of the traditional electric operating companies and certain utility assets of Southern Power Company are operated as a single integrated electric system, or power pool, pursuant to the IIC. Activities under the IIC are administered by SCS, which acts as agent for the traditional electric operating companies and Southern Power Company. The fundamental purpose of the power pool is to provide for the coordinated operation of the electric facilities in an effort to achieve the maximum possible economies consistent with the highest practicable reliability of service. Subject to service requirements and other operating limitations, system resources are committed and controlled through the application of centralized economic dispatch. Under the IIC, each traditional electric operating company and Southern Power Company retains its lowest cost energy resources for the benefit of its own customers and delivers any excess energy to the power pool for use in serving customers of other traditional electric operating companies or Southern Power Company or for sale by the power pool to third parties. The IIC provides for the recovery of specified costs associated with the affiliated operations thereunder, as well as the proportionate sharing of costs and revenues resulting from power pool transactions with third parties. In connection with the sale of Gulf Power, an appendix was added to the IIC setting forth terms and conditions governing Gulf Power's continued participation in the IIC for a defined transition period that, subject to certain potential adjustments, is scheduled to end on January 1, 2024.

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

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

I-2

Table of Contents Index to Financial Statements

Southern Power

Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy facilities, and sells electricity at market-based rates (under authority from the FERC) 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. Southern Power's business activities are not subject to traditional state regulation like the traditional electric operating companies, but the majority of its business activities are subject to regulation by the FERC. Southern Power has attempted to insulate itself from significant fuel supply, fuel transportation, and electric transmission risks by generally making such risks the responsibility of the counterparties to its PPAs. However, Southern Power's future earnings will depend on the parameters of the wholesale market and the efficient operation of its wholesale generating assets, as well as Southern Power's ability to execute its growth strategy and to develop and construct generating facilities. For additional information on Southern Power's business activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Business Activities" of Southern Power in Item 7 herein.

Southern Power Company directly owns and manages generation assets primarily in the Southeast, which are included in the power pool, and has various subsidiaries, which were created to own and operate natural gas and renewable generation facilities either wholly or in partnership with various third parties. At December 31, 2018, Southern Power's generation fleet, which is owned in part with its various partners, totaled 11,888 MWs of nameplate capacity in commercial operation (including 4,508 MWs of nameplate capacity owned by its subsidiaries and including Plant Mankato, which is classified as held for sale in the financial statements). In addition, Southern Power Company has other subsidiaries that are pursuing additional natural gas generation and other renewable generation development opportunities. The generation assets of Southern Power Company's subsidiaries are not included in the power pool.

In addition, on December 4, 2018, Southern Power sold all of its equity interests in the Florida Plants and, in November 2018, entered into an agreement to sell Plant Mankato. The completion of the disposition of Plant Mankato is subject to the expansion unit reaching commercial operation as well as various other customary conditions to closing, including FERC and state commission approvals, and is expected to close mid-2019. The ultimate outcome of this matter cannot be determined at this time.

A majority of Southern Power's partnerships in renewable facilities allow for the sharing of cash distributions and tax benefits at differing percentages, with Southern Power being the controlling member and thus consolidating the assets and operations of the partnerships. At December 31, 2018, Southern Power has three tax-equity partnership arrangements where the tax-equity investors receive substantially all of the tax benefits, including ITCs and PTCs. In addition, Southern Power holds controlling interests in eight partnerships in solar facilities through SP Solar. For seven of these solar partnerships, Southern Power and its new 33% partner, Global Atlantic, are entitled to 51% of all cash distributions and the respective partner that holds the Class B membership interests is entitled to 49% of all cash distributions. For the Desert Stateline partnership, Southern Power and Global Atlantic are entitled to 66% of all cash distributions and the Class B member is entitled to 34% of all cash distributions. In addition, Southern Power and Global Atlantic are entitled to substantially all of the federal tax benefits with respect to these eight partnership entities. Finally, for the Roserock partnership, Southern Power is entitled to 51% of all cash distributions and substantially all of the federal tax benefits, with the Class B member entitled to 49% of all cash distributions.

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

Southern Power calculates an investment coverage ratio for its generating assets based on the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction or being acquired) as the investment amount. With the inclusion of investments associated with the wind and natural gas facilities currently under construction, as well as other capacity and energy contracts, Southern Power has an average investment coverage ratio, at December 31, 2018, of 93% through 2023 and 91% through 2028, with an average remaining contract duration of approximately 14 years (including Plant Mankato, which is classified as held for sale in the financial statements).

Southern Power's natural gas and biomass sales are primarily through long-term PPAs that consist of two types of agreements. The first type, referred to as a unit or block sale, is a customer purchase from a dedicated plant unit where all or a portion of the generation from that unit is reserved for that customer. Southern Power typically has the ability to serve the unit or block sale customer from an alternate resource. The second type, referred to as requirements service, provides that Southern Power serves

I-3

Table of Contents Index to Financial Statements

the customer's capacity and energy requirements from a combination of the customer's own generating units and from Southern Power resources not dedicated to serve unit or block sales. Southern Power has rights to purchase power provided by the requirements customers' resources when economically viable. Capacity charges that form part of the PPA payments are designed to recover fixed and variable operations and maintenance costs based on dollars-per-kilowatt year and to provide a return on investment.

Southern Power's electricity sales from solar and wind generating facilities are predominantly 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.

The following tables set forth Southern Power's PPAs as of December 31, 2018:

Block Sales PPAs



Facility/Source	Counterparty	MWs⁽¹⁾	Contract Term
Addison Units 1 and 3	Georgia Power	297	through May 2030
Addison Unit 2	MEAG Power	149	through April 2029
Addison Unit 4	Georgia Energy Cooperative	146	through May 2030
Cleveland County Unit 1	North Carolina EMC (NCEMC)	90-180	through Dec. 2036
Cleveland County Unit 2	NCEMC	183	through Dec. 2036
Cleveland County Unit 3	North Carolina Municipal Power Agency 1	183	through Dec. 2031
Dahlberg Units 1, 3, and 5	Cobb EMC	224	through Dec. 2027
Dahlberg Units 2, 6, 8, and 10	Georgia Power	298	through May 2025
Dahlberg Unit 4	Georgia Power	74	through May 2030
Franklin Unit 1	Duke Energy Florida	434	through May 2021
Franklin Unit 2	Morgan Stanley Capital Group	250	through Dec. 2025
Franklin Unit 2	Jackson EMC	60-65	through Dec. 2035
Franklin Unit 2	GreyStone Power Corporation	35	through Dec. 2035
Franklin Unit 2	Cobb EMC	100	through Dec. 2027
Franklin Unit 3	Morgan Stanley Capital Group	200-300	through Dec. 2033
Franklin Unit 3	Dalton	70	through Dec. 2027
Franklin Unit 3	Dalton	16	through Dec. 2019
Harris Unit 1	Georgia Power	640	through May 2030
Harris Unit 2	Georgia Power	657	through May 2019
Harris Unit 2	AMEA⁽²⁾	25	through Dec. 2025
Mankato⁽³⁾	Northern States Power Company	375	through July 2026
Mankato⁽³⁾	Northern States Power Company	345	June 2019 – May 2039⁽⁴⁾
Nacogdoches	City of Austin, Texas	100	through May 2032
NCEMC PPA⁽⁵⁾	EnergyUnited	100	through Dec. 2021
Rowan CT Unit 1	North Carolina Municipal Power Agency 1	150	through Dec. 2030
Rowan CT Units 2 and 3	EnergyUnited	100-175	Jan. 2022 – Dec. 2025
Rowan CT Unit 3	EnergyUnited	113	through Dec. 2023
Rowan CC Unit 4	EnergyUnited	23-328	through Dec. 2025

I-4

Table of Contents Index to Financial Statements

Block Sales PPAs (continued)



Facility/Source	Counterparty	MWs⁽¹⁾	Contract Term
Rowan CC Unit 4	Duke Energy Progress, LLC	150	through Dec. 2019
Rowan CC Unit 4	Macquarie	150-250	Jan. 2019 – Nov. 2020
Wansley Unit 6	Century Aluminum	158	Jan. 2019 – Dec. 2020
Wansley Unit 7	JEA⁽⁶⁾	200	through Dec. 2019


(1)	The MWs and related facility units may change due to unit rating changes or assignment of units to contracts.


(2)	AMEA will also be served by Plant Franklin Unit 1 through December 2019.

(3)

On November 5, 2018, Southern Power entered into an agreement with Northern States Power to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction). The ultimate outcome of this matter cannot be determined at this time. See Note 15 to the financial statements under "Southern Power – Sales of Natural Gas Plants" in Item 8 herein for additional information.


(4)	Subject to commercial operation of the 385-MW expansion project.


(5)	Represents sale of power purchased from NCEMC under a PPA.


(6)	JEA will also be served by Plant Wansley Unit 6 during 2019.

Requirements Services PPAs



Counterparty	MWs⁽¹⁾	Contract Term
Nine Georgia EMCs	294-376	through Dec. 2024
Sawnee EMC	267-639	through Dec. 2027
Cobb EMC	0-145	through Dec. 2027
Flint EMC	135-194	through Dec. 2024
Dalton	53-92	through Dec. 2027
EnergyUnited	78-159	through Dec. 2025
City of Blountstown, Florida	10	through April 2022


(1)	Represents forecasted incremental capacity needs over the contract term.

Solar/Wind PPAs



Facility	Counterparty	MWs⁽¹⁾	Contract Term
Solar⁽²⁾
Adobe	Southern California Edison Company	20	through June 2034
Apex	Nevada Power Company	20	through Dec. 2037
Boulder 1	Nevada Power Company	100	through Dec. 2036
Butler	Georgia Power	100	through Dec. 2046
Butler Solar Farm	Georgia Power	20	through Feb. 2036
Calipatria	San Diego Gas & Electric Company	20	through Feb. 2036
Campo Verde	San Diego Gas & Electric Company	139	through Oct. 2033
Cimarron	Tri-State Generation and Transmission Association, Inc.	30	through Dec. 2035
Decatur County	Georgia Power	19	through Dec. 2035
Decatur Parkway	Georgia Power	80	through Dec. 2040
Desert Stateline	Southern California Edison Company	300	through Sept. 2036
East Pecos	Austin Energy	119	through April 2032
Garland A	Southern California Edison Company	20	through Sept. 2036
Garland	Southern California Edison Company	180	through Oct. 2031
Gaskell West 1	Southern California Edison Company	20	through March 2038
Granville	Duke Energy Progress, LLC	3	through Oct. 2032
Henrietta	Pacific Gas & Electric Company⁽³⁾	100	through Sept. 2036
Imperial Valley	San Diego Gas & Electric Company	150	through Nov. 2039

I-5

Table of Contents Index to Financial Statements

Solar/Wind PPAs (continued)



Facility	Counterparty	MWs⁽¹⁾	Contract Term
Lamesa	City of Garland, Texas	102	through April 2032
Lost Hills Blackwell	99% to Pacific Gas & Electric Company⁽³⁾ and 1% to City of Roseville, California	32	through Dec. 2043
Macho Springs	El Paso Electric Company	50	through May 2034
Morelos	Pacific Gas & Electric Company⁽³⁾	15	through Feb. 2036
North Star	Pacific Gas & Electric Company⁽³⁾	60	through June 2035
Pawpaw	Georgia Power	30	through March 2046
Roserock	Austin Energy	157	through Nov. 2036
Rutherford	Duke Energy Carolinas, LLC	75	through Dec. 2031
Sandhills	Cobb EMC	111	through Oct. 2041
Sandhills	Flint EMC	15	through Oct. 2041
Sandhills	Sawnee EMC	15	through Oct. 2041
Sandhills	Middle Georgia and Irwin EMC	2	through Oct. 2041
Spectrum	Nevada Power Company	30	through Dec. 2038
Tranquillity	Shell Energy North America (US), LP	204	through Nov. 2019
Tranquillity	Southern California Edison Company	204	Dec. 2019 – Nov. 2034
Wind⁽⁴⁾
Bethel	Google Inc.	225	through Jan. 2029
Cactus Flats	General Mills, Inc.	98	through July 2033
Cactus Flats	General Motors Company	50	through July 2030
Grant Plains	Oklahoma Municipal Power Authority	41	Jan. 2020 – Dec. 2039
Grant Plains	Steelcase Inc.	25	through Dec. 2028
Grant Plains	Allianz Risk Transfer (Bermuda) Ltd.	81-122	through March 2027
Grant Wind	East Texas Electric Cooperative	50	through April 2036
Grant Wind	Northeast Texas Electric Cooperative	50	through April 2036
Grant Wind	Western Farmers Electric Cooperative	50	through April 2036
Kay Wind	Westar Energy Inc.	200	through Dec. 2035
Kay Wind	Grand River Dam Authority	99	through Dec. 2035
Passadumkeag	Western Massachusetts Electric Company	40	through June 2031
Reading⁽⁵⁾	Royal Caribbean Cruises Ltd.	200	April 2020 – March 2032
Salt Fork Wind	City of Garland, Texas	150	through Nov. 2030
Salt Fork Wind	Salesforce.com, Inc.	24	through Nov. 2028
Tyler Bluff Wind	The Proctor & Gamble Company	96	through Dec. 2028
Wake Wind	Equinix Enterprises, Inc.	100	through Oct. 2028
Wake Wind	Owens Corning	125	through Oct. 2028
Wildhorse⁽⁵⁾	Arkansas Electric Cooperative Corporation	100	Oct. 2019 – Sept. 2039

(1) MWs shown are for 100% of the PPA, which is based on demonstrated capacity of the facility.

(2) In May 2018, Southern Power sold a noncontrolling 33% equity interest in SP Solar (a limited partnership indirectly owning all of Southern Power's solar facilities, except the Roserock and Gaskell West facilities). SP Solar is the 51% majority owner of Boulder 1, Garland, Henrietta, Imperial Valley, Lost Hills Blackwell, North Star, and Tranquillity; the 66% majority owner of Desert Stateline; and the sole owner of the remaining SP Solar facilities. Southern Power is the 51% majority owner of Roserock and also the controlling partner in a tax equity partnership owning Gaskell West. All of these entities are consolidated subsidiaries of Southern Power.

(3) See Note 1 to the financial statements under "Revenues – Concentration of Revenue" in Item 8 herein for additional information on Pacific Gas & Electric Company's bankruptcy filing.

(4) In December 2018, Southern Power sold a noncontrolling tax equity interest in SP Wind (which owns all of Southern Power's wind facilities, except Cactus Flats and the two wind projects under construction, Reading and Wildhorse). SP Wind is the 90.1% majority owner of Wake Wind and owns 100% of the remaining SP Wind facilities. Southern Power owns 100% of Reading and Wildhorse and is the controlling partner in a tax equity partnership owning Cactus Flats. All of these entities are consolidated subsidiaries of Southern Power.

(5) Subject to commercial operation.

I-6

Table of Contents Index to Financial Statements

For the year ended December 31, 2018, approximately 9.8% of Southern Power's revenues were derived from Georgia Power. Southern Power actively pursues replacement PPAs prior to the expiration of its current PPAs and anticipates that the revenues attributable to one customer may be replaced by revenues from a new customer; however, the expiration of any of Southern Power's current PPAs without the successful remarketing of a replacement PPA could have a material negative impact on Southern Power's earnings but is not expected to have a material impact on Southern Company's earnings.

Southern Company Gas

Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. Southern Company Gas is also involved in several other businesses that are complementary to the distribution of natural gas, including gas pipeline investments, wholesale gas services, and gas marketing services. During the fourth quarter 2018, Southern Company Gas changed its reportable segments to further align with the way its new Chief Operating Decision Maker reviews operating results and has reclassified prior years' data to conform to the new reportable segment presentation. This change resulted in a new reportable segment, gas pipeline investments, which was formerly included in gas midstream operations. Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including a 50% interest in SNG, two significant pipeline construction projects, and a 50% joint ownership interest in the Dalton Pipeline. Gas distribution operations, wholesale gas services, and gas marketing services continue to remain as separate reportable segments and reflect the impact of the Southern Company Gas Dispositions. The all other non-reportable segment includes segments below the quantitative threshold for separate disclosure, including the storage and fuels operations that were formerly included in gas midstream operations, and other subsidiaries that fall below the quantitative threshold for separate disclosure.

Gas distribution operations, the largest segment of Southern Company Gas' business, operates, constructs, and maintains approximately 75,200 miles of natural gas pipelines and 14 storage facilities, with total capacity of 158 Bcf, to provide natural gas to residential, commercial, and industrial customers. Gas distribution operations serves approximately 4.2 million customers across four states.

On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which then primarily consisted of Florida City Gas, to NextEra Energy. The transactions raised approximately $2.3 billion in proceeds. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 herein for additional information.

Gas pipeline investments includes joint ventures in natural gas pipeline investments that enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas. SNG, the largest natural gas pipeline investment, is the owner of a 7,000-mile pipeline connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee.

Wholesale gas services consists of Sequent and engages in natural gas storage and gas pipeline arbitrage and provides natural gas asset management and related logistical services to most of the natural gas distribution utilities as well as non-affiliate companies.

Gas marketing services is comprised of SouthStar and provides natural gas commodity and related services to customers in competitive markets or markets that provide for customer choice. SouthStar, serving approximately 697,000 natural gas commodity customers, markets gas to residential, commercial, and industrial customers and offers energy-related products that provide natural gas price stability and utility bill management.

On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for $365 million. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 herein for additional information.

Other Businesses

PowerSecure, which was acquired by Southern Company in 2016, provides energy solutions, including distributed energy infrastructure, energy efficiency products and services, and utility infrastructure services, to customers.

Southern Holdings is an intermediate holding subsidiary, primarily for Southern Company's investments in leveraged leases and energy-related funds and companies, and also for other electric and natural gas products and services.

Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public. Southern Linc delivers multiple wireless communication options including push to talk, cellular service, text messaging, wireless internet access, and wireless data. Its system covers approximately 127,000 square

I-7

Table of Contents Index to Financial Statements

miles in the Southeast. Southern Linc also provides fiber optics services within the Southeast through its subsidiary, Southern Telecom, Inc.

These efforts to invest in and develop new business opportunities may offer potential returns exceeding those of rate-regulated operations. However, these activities often involve a higher degree of risk.

Construction Programs

The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. For estimated construction and environmental expenditures for the periods 2019 through 2023, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of each registrant in Item 7 herein. The Southern Company system's construction program consists of capital investment and capital expenditures to comply with environmental laws and regulations. In 2019, the construction program is expected to be apportioned approximately as follows:



	Southern Company system^(a)(b)		Alabama Power^(a)		Georgia Power^(a)		Mississippi Power
	(in billions)
New generation	$	1.6	$	—	$	1.6	$	—
Environmental compliance^(c)	0.5		0.2		0.2		—
Generation maintenance	0.9		0.4		0.4		0.1
Transmission	1.0		0.3		0.6		—
Distribution	1.1		0.5		0.5		0.1
Nuclear fuel	0.2		0.1		0.1		—
General plant	0.5		0.2		0.2		—
	5.8		1.8		3.7		0.2
Southern Power^(d)	0.3
Southern Company Gas^(e)	1.6
Other subsidiaries	0.3
Total^(a)	$	8.0	$	1.8	$	3.7	$	0.2


(a)	Totals may not add due to rounding.


(b)	Includes the Subsidiary Registrants, as well as the other subsidiaries. See "Other Businesses" herein for additional information.

(c)

Reflects cost estimates for environmental regulations. These estimated expenditures do not include any potential compliance costs associated with pending regulation of CO₂ emissions from fossil-fuel-fired electric generating units or costs associated with ash pond closure and groundwater monitoring under the CCR Rule and the related state rules. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company and each traditional electric operating company in Item 7 herein for additional information.


(d)	Excludes up to approximately $0.5 billion for planned expenditures for plant acquisitions and placeholder growth, which may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy.

(e)

Includes costs for ongoing capital projects associated with infrastructure improvement programs for certain natural gas distribution utilities that have been previously approved by their applicable state regulatory agencies. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Infrastructure Replacement Programs and Capital Projects" of Southern Company Gas in Item 7 herein for additional information.

I-8

Table of Contents Index to Financial Statements

be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy.

The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only recently began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. The ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs, availability, and productivity; challenges with management of contractors, subcontractors, or vendors; adverse weather conditions; shortages, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; non-performance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance matters, including the timely resolution of ITAAC and the related approvals by the NRC; challenges with start-up activities, including major equipment failure and system integration; and/or operational performance. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 herein for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4.

Also see "Regulation – Environmental Laws and Regulations" herein for additional information with respect to certain existing and proposed environmental requirements and PROPERTIES – "Electric – Jointly-Owned Facilities" and – "Natural Gas – Jointly-Owned Facilities" in Item 2 herein and Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information concerning Alabama Power's, Georgia Power's, and Southern Power's joint ownership of certain generating units and related facilities with certain non-affiliated utilities and Southern Company Gas' joint ownership of a pipeline facility.

Financing Programs

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

Fuel Supply

Electric

The traditional electric operating companies' and SEGCO's supply of electricity is primarily fueled by natural gas and coal. Southern Power's supply of electricity is primarily fueled by natural gas. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATION – "Electricity Business – Fuel and Purchased Power Expenses" of Southern Company and MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATION – "Fuel and Purchased Power Expenses" of each traditional electric operating company in Item 7 herein for information regarding the electricity generated and the average cost of fuel in cents per net KWH generated for the years 2016 through 2018.

The traditional electric operating companies have agreements in place from which they expect to receive substantially all of their 2019 coal burn requirements. These agreements have terms ranging between one and four years. In 2018, the weighted average sulfur content of all coal burned by the traditional electric operating companies was 1.06%. This sulfur level, along with banked SO₂ allowances, allowed the traditional electric operating companies to remain within limits set by Phase I of the Cross-State Air Pollution Rule (CSAPR) under the Clean Air Act. In 2018, the Southern Company system did not purchase any SO₂ allowances, annual NOx emission allowances, or seasonal NOx emission allowances from the market. As any additional environmental regulations are proposed that impact the utilization of coal, the traditional electric operating companies' fuel mix will be monitored to help ensure that the traditional electric operating companies remain in compliance with applicable laws and regulations. Additionally, Southern Company and the traditional electric operating companies will continue to evaluate the need to purchase additional emissions allowances, the timing of capital expenditures for emissions control equipment, and potential unit retirements and replacements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company, each traditional electric operating company, and Southern Power in Item 7 herein for additional information on environmental matters.

SCS, acting on behalf of the traditional electric operating companies and Southern Power Company, has agreements in place for the natural gas burn requirements of the Southern Company system. For 2019, SCS has contracted for 557 Bcf of natural gas supply under agreements with remaining terms up to 15 years. In addition to natural gas supply, SCS has contracts in place for both firm natural gas transportation and storage. Management believes these contracts provide sufficient natural gas supplies, transportation, and storage to ensure normal operations of the Southern Company system's natural gas generating units.

Alabama Power and Georgia Power have multiple contracts covering their nuclear fuel needs for uranium, conversion services, enrichment services, and fuel fabrication. The uranium, conversion services, and fuel fabrication contracts have remaining

I-9

Table of Contents Index to Financial Statements

terms ranging from one to 17 years. The remaining term lengths for the enrichment services contracts range from five to 10 years. Management believes suppliers have sufficient nuclear fuel production capability to permit the normal operation of the Southern Company system's nuclear generating units.

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

Alabama Power and Georgia Power have contracts with the United States, acting through the DOE, that provide for the permanent disposal of spent nuclear fuel. The DOE failed to begin disposing of spent fuel in 1998, as required by the contracts, and Alabama Power and Georgia Power have pursued and are pursuing legal remedies against the government for breach of contract. See Note 3 to the financial statements under "Nuclear Fuel Disposal Costs" in Item 8 herein for additional information.

Natural Gas

Advances in natural gas drilling in shale producing regions of the United States have resulted in historically high supplies of natural gas and relatively low prices for natural gas. Procurement plans for natural gas supply and transportation to serve regulated utility customers are reviewed and approved by the regulatory agencies in the states where Southern Company Gas operates. Southern Company Gas purchases natural gas supplies in the open market by contracting with producers and marketers and, for the natural gas distribution utilities except Nicor Gas, from its wholly-owned subsidiary, Sequent, under asset management agreements approved by the applicable state regulatory agency. Southern Company Gas also contracts for transportation and storage services from interstate pipelines that are regulated by the FERC. When firm pipeline services are temporarily not needed, Southern Company Gas may release the services in the secondary market under FERC-approved capacity release provisions or utilize asset management arrangements, thereby reducing the net cost of natural gas charged to customers for most of the natural gas distribution utilities. Peak-use requirements are met through utilization of company-owned storage facilities, pipeline transportation capacity, purchased storage services, peaking facilities, and other supply sources, arranged by either transportation customers or Southern Company Gas.

Territory Served by the Southern Company System

Traditional Electric Operating Companies and Southern Power

As of January 1, 2019, the territory in which the traditional electric operating companies provide retail electric service comprises most of the states of Alabama and Georgia, together with southeastern Mississippi. See Note 15 to the financial statements under "Southern Company's Sale of Gulf Power" in Item 8 herein for information on the sale of Gulf Power. In this territory there are non-affiliated electric distribution systems that obtain some or all of their power requirements either directly or indirectly from the traditional electric operating companies. As of January 1, 2019, the territory had an area of approximately 114,000 square miles and an estimated population of approximately 16 million. Southern Power sells electricity at market-based rates in the wholesale market, primarily to investor-owned utilities, IPPs, municipalities, and other load-serving entities, as well as commercial and industrial customers.

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

Georgia Power is engaged in the generation, transmission, distribution, and purchase of electricity and the sale of electric service within the State of Georgia, at retail in over 600 communities (including Athens, Atlanta, Augusta, Columbus, Macon, Rome, and Savannah), as well as in rural areas, and at wholesale to OPC, MEAG Power, Dalton, various EMCs, and non-affiliated utilities. Georgia Power also markets and sells outdoor lighting services.

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

I-10

Table of Contents Index to Financial Statements

For information relating to KWH sales by customer classification for the traditional electric operating companies, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS of Southern Company and each traditional electric operating company in Item 7 herein. For information relating to the number of retail customers served by customer classification for the traditional electric operating companies, see SELECTED FINANCIAL DATA of Southern Company and each traditional electric operating company in Item 6 herein. Also, for information relating to the sources of revenues for Southern Company, each traditional electric operating company, and Southern Power, reference is made to Item 7 herein.

The RUS has authority to make loans to cooperative associations or corporations to enable them to provide electric service to customers in rural sections of the country. As of January 1, 2019, there were approximately 58 electric cooperative distribution systems operating in the territory in which the traditional electric operating companies provide electric service at retail or wholesale.

One of these organizations, PowerSouth, is a generating and transmitting cooperative selling power to several distributing cooperatives, municipal systems, and other customers in south Alabama. As of December 31, 2018, PowerSouth owned generating units with approximately 2,100 MWs of nameplate capacity, including an undivided 8.16% ownership interest in Alabama Power's Plant Miller Units 1 and 2. PowerSouth's facilities were financed with RUS loans secured by long-term contracts requiring distributing cooperatives to take their requirements from PowerSouth to the extent such energy is available. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein and Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for details of Alabama Power's joint-ownership with PowerSouth of a portion of Plant Miller. Alabama Power has a system supply agreement with PowerSouth to provide 200 MWs of capacity service through December 31, 2030 with an option to extend and renegotiate in the event Alabama Power builds new generation or contracts for new capacity.

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

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

Mississippi Power has an interchange agreement with Cooperative Energy, a generating and transmitting cooperative, pursuant to which various services are provided.

As of January 1, 2019, there were approximately 71 municipally-owned electric distribution systems operating in the territory in which the traditional electric operating companies provide electric service at retail or wholesale.

As of December 31, 2018, 48 municipally-owned electric distribution systems and one county-owned system received their requirements through MEAG Power, which was established by a Georgia state statute in 1975. MEAG Power serves these requirements from self-owned generation facilities, some of which are jointly-owned with Georgia Power, and purchases from other resources. MEAG Power also has a pseudo scheduling and services agreement with Georgia Power. Dalton serves its requirements from self-owned generation facilities, some of which are jointly-owned with Georgia Power, and through purchases from Southern Power through a service agreement. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein and Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information.

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

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

SCS, acting on behalf of the traditional electric operating companies, also has a contract with SEPA providing for the use of the traditional electric operating companies' facilities at government expense to deliver to certain cooperatives and municipalities,

I-11

Table of Contents Index to Financial Statements

entitled by federal statute to preference in the purchase of power from SEPA, quantities of power equivalent to the amounts of power allocated to them by SEPA from certain U.S. government hydroelectric projects.

Southern Company Gas

Southern Company Gas is engaged in the distribution of natural gas in four states through the natural gas distribution utilities. The natural gas distribution utilities construct, manage, and maintain intrastate natural gas pipelines and distribution facilities. Details of the natural gas distribution utilities at December 31, 2018 are as follows:



Utility	State	Number of customers	Approximate miles of pipe
		(in thousands)
Nicor Gas	Illinois	2,237	34,285
Atlanta Gas Light	Georgia	1,643	33,610
Virginia Natural Gas	Virginia	301	5,650
Chattanooga Gas	Tennessee	67	1,655
Total		4,248	75,200

For information relating to the sources of revenue for Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS and – FUTURE EARNINGS POTENTIAL of Southern Company Gas in Item 7 herein.

Competition

Electric

The electric utility industry in the U.S. is continuing to evolve as a result of regulatory and competitive factors. Among the early primary agents of change was the Energy Policy Act of 1992, which allowed IPPs to access a utility's transmission network in order to sell electricity to other utilities.

The competition for retail energy sales among competing suppliers of energy is influenced by various factors, including price, availability, technological advancements, service, and reliability. These factors are, in turn, affected by, among other influences, regulatory, political, and environmental considerations, taxation, and supply.

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

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

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

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

I-12

Table of Contents Index to Financial Statements

As of December 31, 2018, Alabama Power had cogeneration contracts in effect with nine industrial customers. Under the terms of these contracts, Alabama Power purchases excess energy generated by such companies. During 2018, Alabama Power purchased approximately 99 million KWHs from such companies at a cost of $3 million.

As of December 31, 2018, Georgia Power had contracts in effect with 28 small power producers whereby Georgia Power purchases their excess generation. During 2018, Georgia Power purchased 2.1 billion KWHs from such companies at a cost of $140 million. Georgia Power also has PPAs for electricity with four cogeneration facilities. Payments are subject to reductions for failure to meet minimum capacity output. During 2018, Georgia Power purchased 26 million KWHs at a cost of $0.8 million from these facilities.

Also during 2018, Georgia Power purchased energy from three customer-owned generating facilities. These customers provide energy with no capacity commitment and are not dispatched by Georgia Power. During 2018, Georgia Power purchased a total of 341 million KWHs from the three customers at a cost of approximately $28 million.

As of December 31, 2018, Mississippi Power had a cogeneration agreement in effect with one of its industrial customers. Under the terms of this contract, Mississippi Power purchases any excess generation. During 2018, Mississippi Power did not purchase any excess generation from this customer.

Natural Gas

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

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

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


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


•	general economic conditions;


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


•	legislation and regulations;


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


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

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

The availability and affordability of natural gas have provided cost advantages and further opportunity for growth of the businesses.

Seasonality

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

Regulation

States

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

I-13

Table of Contents Index to Financial Statements

Federal Power Act

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

Alabama Power and Georgia Power are also subject to the provisions of the Federal Power Act or the earlier Federal Water Power Act applicable to licensees with respect to their hydroelectric developments. As of December 31, 2018, among the hydroelectric projects subject to licensing by the FERC are 14 existing Alabama Power generating stations having an aggregate installed capacity of 1,670,000 KWs and 17 existing Georgia Power generating stations and one generating station partially owned by Georgia Power, with a combined aggregate installed capacity of 1,101,402 KWs.

In 2013, the FERC issued a new 30-year license to Alabama Power for Alabama Power's seven hydroelectric developments on the Coosa River (Weiss, Henry, Logan Martin, Lay, Mitchell, Jordan, and Bouldin). Alabama Power filed a petition requesting rehearing of the FERC order granting the relicense seeking revisions to several conditions of the license. Alabama Rivers Alliance, American Rivers, the Georgia Environmental Protection Division, and the Atlanta Regional Commission also filed petitions for rehearing of the FERC order. In 2016, the FERC issued an order granting in part and denying in part Alabama Power's rehearing request. The order also denied all of the other rehearing requests. Also in 2016, Alabama Rivers Alliance and American Rivers filed a second rehearing request and also filed a petition with the U.S. Court of Appeals for the District of Columbia Circuit for review of the license and the rehearing denial order. The FERC issued an order in 2016 denying the second rehearing request, and American Rivers and Alabama Rivers Alliance subsequently filed an appeal of that order at the U.S. Court of Appeals for the District of Columbia Circuit. The U.S. Court of Appeals for the District of Columbia Circuit consolidated the two appeals into one proceeding and, on July 6, 2018, vacated the FERC's 2013 order for the new 30-year license and remanded the proceeding to the FERC. Alabama Power continues to operate the Coosa River developments under annual licenses issued by the FERC. The ultimate outcome of this matter cannot be determined at this time.

In 2018, Alabama Power continued the process of developing an application to relicense the Harris Dam project on the Tallapoosa River, which is expected to be filed with the FERC by November 30, 2021. The current Harris Dam project license will expire on November 30, 2023.

On May 31, 2018, Georgia Power filed an application to relicense the Wallace Dam project on the Oconee River. The current Wallace Dam project license will expire on June 1, 2020. On July 3, 2018, Georgia Power filed a Notice of Intent to relicense the Lloyd Shoals project on the Ocmulgee River. The application to relicense the Lloyd Shoals project is expected to be filed with the FERC by December 31, 2021. The current Lloyd Shoals project license will expire on December 31, 2023. On December 18, 2018, Georgia Power filed applications to surrender the Langdale and Riverview hydroelectric projects on the Chattahoochee River upon their license expirations on December 31, 2023. Both projects together represent 1,520 KWs of Georgia Power's hydro fleet capacity.

Georgia Power and OPC also have a license, expiring in 2027, for the Rocky Mountain project, a pure pumped storage facility of 903,000 KW installed capacity. See PROPERTIES – "Jointly-Owned Facilities" in Item 2 herein for additional information.

Licenses for all projects, excluding those discussed above, expire in the years 2034-2066 in the case of Alabama Power's projects and in the years 2035-2044 in the case of Georgia Power's projects.

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

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

Nuclear Regulation

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

I-14

Table of Contents Index to Financial Statements

environment, protecting and safeguarding nuclear materials and nuclear power plants in the interest of national security, and assuring conformity with antitrust laws.

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

In 2012, the NRC issued combined construction and operating licenses (COLs) for Plant Vogtle Units 3 and 4. Receipt of the COLs allowed full construction to begin. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" of Georgia Power in Item 7 herein and Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 herein for additional information.

See Notes 3 and 6 to the financial statements under "Nuclear Insurance" and "Nuclear Decommissioning," respectively, in Item 8 herein for information on nuclear insurance and nuclear decommissioning costs.

Environmental Laws and Regulations

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, and protection of other natural resources. Compliance with these existing environmental requirements involves significant capital and operating costs, a major portion of which is expected to be recovered through existing ratemaking provisions or through market-based contracts. There is no assurance, however, that all such costs will be recovered.

For Southern Company Gas, substantially all of these costs are related to former MGP sites, which are generally recovered through existing ratemaking provisions. See Note 3 to the financial statements under "Environmental Matters" in Item 8 herein for additional information.

Compliance with environmental laws and resulting regulations, including, but not limited to, proposed and existing regulations related to air quality, water quality, CCR, and global climate issues, has been, and will continue to be, a significant focus for each of the registrants and SEGCO. Compliance with any new or revised environmental laws and regulations could affect many areas of the traditional electric operating companies', Southern Power's, SEGCO's, and Southern Company Gas' operations. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of each of the registrants in Item 7 herein for additional information about environmental issues.

The Southern Company system's ultimate environmental compliance strategy and future environmental expenditures will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, fuel prices, and the outcome of pending and/or future legal challenges. Compliance costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as well as related upgrades to the transmission and distribution (electric and natural gas) systems. Environmental compliance spending over the next several years may differ materially from the amounts estimated. Such expenditures could affect results of operations, cash flows, and/or financial condition if such costs are not recovered on a timely basis through regulated 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. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for energy, which could negatively affect results of operations, cash flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity and natural gas. See "Construction Program" herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of each of the registrants in Item 7 herein for additional information. The ultimate outcome of these matters cannot be determined at this time.

Rate Matters

Rate Structure and Cost Recovery Plans

Electric

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

I-15

Table of Contents Index to Financial Statements

their respective state PSCs to negotiate the terms and cost of service to large customers. Such terms and cost of service, however, are subject to final state PSC approval.

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

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters" of Southern Company and each of the traditional electric operating companies in Item 7 herein and Note 2 to the financial statements in Item 8 herein for a discussion of rate matters and certain cost recovery mechanisms. Also, see Note 1 to the financial statements in Item 8 herein for a discussion of recovery of fuel costs, storm damage costs, and compliance costs through rate mechanisms.

See "Integrated Resource Planning" herein and Note 2 to the financial statements under "Georgia Power – Integrated Resource Plan" in Item 8 herein for a discussion of Georgia PSC certification of new demand-side or supply-side resources for Georgia Power. In addition, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" of Georgia Power in Item 7 herein and Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 herein for a discussion of the Georgia Nuclear Energy Financing Act and the Georgia PSC certification of Plant Vogtle Units 3 and 4, which have allowed Georgia Power to recover financing costs for construction of Plant Vogtle Units 3 and 4 since 2011.

See Note 2 to the financial statements under "Kemper County Energy Facility" in Item 8 herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility – Rate Recovery" of Mississippi Power in Item 7 herein for information on cost recovery plans for the Kemper County energy facility.

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

Mississippi Power serves long-term contracts with rural electric cooperative associations and a municipality located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 17.3% of Mississippi Power's total operating revenues in 2018 and are generally subject to 10-year rolling cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers.

Natural Gas

Southern Company Gas' natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies. Rates charged to these customers vary according to customer class (residential, commercial, or industrial) and rate jurisdiction. These agencies approve rates designed to provide each natural gas distribution utility 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 return.

With the exception of Atlanta Gas Light, which operates in a deregulated environment in which Marketers rather than a traditional utility sell natural gas to end-use customers and earns revenue by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are largely a function of weather conditions and price levels for natural gas.

The natural gas distribution utilities, excluding Atlanta Gas Light, are authorized 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. In addition to natural gas cost recovery mechanisms, the natural gas distribution utilities have other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs as well as environmental remediation and energy efficiency plans.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Utility Regulation and Rate Design" of Southern Company Gas in Item 7 herein and Note 2 to the financial statements under "Southern Company Gas" in Item 8 herein for a discussion of rate matters and certain cost recovery mechanisms.

I-16

Table of Contents Index to Financial Statements

Integrated Resource Planning

Each of the traditional electric operating companies continually evaluates its electric generating resources in order to ensure that it maintains a cost-effective and reliable mix of resources to meet the existing and future demand requirements of its customers. See "Environmental Laws and Regulations" above for a discussion of existing and potential environmental regulations that may impact the future generating resource needs of the traditional electric operating companies.

Alabama Power

Triennially, Alabama Power provides an IRP report to the Alabama PSC. This report overviews Alabama Power's resource planning process and contains information that serves as the foundation for certain decisions affecting Alabama Power's portfolio of supply-side and demand-side resources. The IRP report facilitates Alabama Power's ability to provide reliable and cost-effective electric service to customers, while accounting for the risks and uncertainties inherent in planning for resources sufficient to meet expected customer demand. Under State of Alabama law, a CPCN must be obtained from the Alabama PSC before Alabama Power constructs any new generating facility, unless such construction is deemed an ordinary extension in the usual course of business.

Georgia Power

Triennially, Georgia Power must file an IRP with the Georgia PSC that specifies how it intends to meet the future electric service needs of its customers through a combination of demand-side and supply-side resources. The Georgia PSC, under state law, must certify any new demand-side or supply-side resources for Georgia Power to receive cost recovery. Once certified, the lesser of actual or certified construction costs and purchased power costs is recoverable through rates. Certified costs may be excluded from recovery only on the basis of fraud, concealment, failure to disclose a material fact, imprudence, or criminal misconduct. See Note 2 to the financial statements under "Georgia Power – Rate Plans," " – Integrated Resource Plan," and " – Nuclear Construction" in Item 8 herein for additional information.

Mississippi Power

On February 6, 2018, the Mississippi PSC approved a settlement agreement related to cost recovery for the Kemper County energy facility, pursuant to which Mississippi Power filed a Reserve Margin Plan (RMP) on August 6, 2018. The RMP includes many of the same aspects of a traditional IRP, but the RMP also contains alternatives proposed by Mississippi Power to address its existing reserve capacity, which is greater than the level required to meet Mississippi Power's projected summer peak demand. Mississippi Power developed the alternatives by evaluating the economics of each unit in Mississippi Power's fleet, the opportunities currently available in the wholesale market, and the operational constraints of the Southern Company system. The ultimate outcome of this matter cannot be determined at this time. For additional information, see Note 2 to the financial statements under "Kemper County Energy Facility" in Item 8 herein.

Employee Relations

The Southern Company system had a total of 29,192 employees on its payroll at January 1, 2019.



	Employees at January 1, 2019
Alabama Power	6,650
Georgia Power	6,967
Mississippi Power	1,053
PowerSecure	1,743
SCS	3,799
Southern Company Gas	4,389
Southern Nuclear	3,870
Southern Power	491
Other	230
Total	29,192

The traditional electric operating companies and the natural gas distribution utilities have separate agreements with local unions of the IBEW and the Utilities Workers Union of America generally covering wages, working conditions, and procedures for handling grievances and arbitration. These agreements apply with certain exceptions to operating, maintenance, and construction employees.

I-17

Table of Contents Index to Financial Statements

Alabama Power has agreements with the IBEW in effect through August 15, 2019. Upon notice given at least 60 days prior to that date, negotiations may be initiated with respect to agreement terms to be effective after such date.

Georgia Power has an agreement with the IBEW covering wages and working conditions, which is in effect through June 30, 2021.

Mississippi Power has an agreement with the IBEW covering wages and working conditions, which is in effect through May 1, 2019. In 2015, Mississippi Power signed a separate agreement with the IBEW related solely to the Kemper County energy facility; that current agreement is in effect through March 15, 2021. In August 2017, Mississippi Power signed an agreement with the IBEW that added several job classifications and provided guidelines related to the reorganization at the Kemper County energy facility.

Southern Nuclear has a five-year agreement with the IBEW covering certain employees at Plants Hatch and Plant Vogtle Units 1 and 2, which is in effect through June 30, 2021. A five-year agreement between Southern Nuclear and the IBEW representing certain employees at Plant Farley is in effect through August 15, 2019. Upon notice given at least 60 days prior to that date, negotiations may be initiated with respect to agreement terms to be effective after such date.

The agreements also make the terms of the pension plans for the companies discussed above subject to collective bargaining with the unions at either a five-year or a 10-year cycle, depending upon union and company actions.

The natural gas distribution utilities have separate agreements with local unions of the IBEW and Utilities Workers Union of America covering wages, working conditions, and procedures for handling grievances and arbitration. Nicor Gas' agreement with the IBEW is effective through February 29, 2020. Virginia Natural Gas' agreement with the IBEW is effective through May 15, 2020. The agreements also make the terms of the Southern Company Gas pension plan subject to collective bargaining with the unions when significant changes to the benefit accruals are considered by Southern Company Gas.

I-18

Table of Contents Index to Financial Statements

Item 1A. RISK FACTORS

In addition to the other information in this Form 10-K, including MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL in Item 7 of each registrant, and other documents filed by Southern Company and/or its subsidiaries with the SEC from time to time, the following factors should be carefully considered in evaluating Southern Company and its subsidiaries. Such factors could affect actual results and cause results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, Southern Company and/or its subsidiaries.

UTILITY REGULATORY, LEGISLATIVE, AND LITIGATION RISKS

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

Southern Company and its subsidiaries are subject to substantial regulation from federal, state, and local regulatory agencies and are required to comply with numerous laws and regulations and to obtain numerous permits, approvals, and certificates from governmental agencies. The traditional electric operating companies and the natural gas distribution utilities seek to recover their costs (including a reasonable return on invested capital) through their retail rates, which must be approved by the applicable state PSC or other applicable state regulatory agency. A state PSC or other applicable state regulatory agency, in a future rate proceeding, may alter the timing or amount of certain costs for which recovery is allowed or modify the current authorized rate of return. Rate refunds may also be required. Additionally, the rates charged to wholesale customers by the traditional electric operating companies and by Southern Power and the rates charged to natural gas transportation customers by Southern Company Gas' pipeline investments and for some of its storage assets must be approved by the FERC. These wholesale rates could be affected by changes to Southern Power's and the traditional electric operating companies' ability to conduct business pursuant to FERC market-based rate authority. Retaining this authority from the FERC is important to the traditional electric operating companies' and Southern Power's ability to remain competitive in the wholesale electric markets.

The impact of any future revision or changes in interpretations of existing regulations or the adoption of new laws and regulations applicable to Southern Company or any of its subsidiaries is uncertain. Changes in regulation or the imposition of additional regulations could influence the operating environment of Southern Company and its subsidiaries and may result in substantial costs or otherwise negatively affect their results of operations.

The Southern Company system's costs of compliance with environmental laws and satisfying related AROs are significant. The costs of compliance with current and future environmental laws and related AROs and the incurrence of environmental liabilities could negatively impact the net income, cash flows, and financial condition of the registrants.

The Southern Company system's operations are subject to extensive regulation by state and federal environmental agencies through a variety of laws and regulations. Compliance with existing environmental requirements involves significant capital and operating costs including the settlement of AROs, a major portion of which is expected to be recovered through existing ratemaking provisions or through market-based contracts. There is no assurance, however, that all such costs will be recovered. The registrants expect future compliance expenditures will continue to be significant.

The EPA has adopted and is implementing regulations governing air and water quality under the Clean Air Act and regulations governing cooling water intake structures and effluent guidelines for steam electric generating plants under the Clean Water Act. The EPA has also adopted regulations governing the disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments at active generating power plants. 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. The traditional electric operating companies will continue to periodically update their ARO cost estimates.

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

Existing environmental laws and regulations may be revised or new environmental laws and regulations may be adopted or become applicable to the Southern Company system. In addition, existing environmental laws and regulations may be impacted by related legal challenges.

Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂and other emissions, CCR, releases of regulated substances, and alleged exposure to regulated substances, and/or requests for injunctive relief in connection with such matters.

I-19

Table of Contents Index to Financial Statements

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

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

The EPA has published rules limiting CO₂ emissions from new, modified, and reconstructed fossil fuel-fired electric generating units and guidelines for states to develop plans to meet EPA-mandated CO₂emission performance standards for existing units (known as the Clean Power Plan or CPP). On August 31, 2018, the EPA published a proposed rule known as the Affordable Clean Energy (ACE) Rule, which is intended to replace a regulation enacted in 2015 known as the Clean Power Plan (CPP), that would limit CO₂emissions from existing fossil fuel-fired electric generating units. The CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule would require states to develop GHG unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of January 1, 2019, the Southern Company system has ownership interests in 40 fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to the Southern Company system is currently unknown and will depend on changes between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal challenges.

The EPA also has proposed a review of final rules adopted in 2015 to establish performance standards for new, modified, and reconstructed electric utility generating units. The impact of any changes will depend on the content of any final rule adopted by the EPA and the outcome of any related legal challenges.

In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, complete ongoing construction projects, including Georgia Power's interest in Plant Vogtle Units 3 and 4, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies.

Costs associated with GHG legislation, regulation, and emission reduction goals could be significant. However, the ultimate impact will depend on various factors, such as state adoption and implementation of requirements, low natural gas prices, the development, deployment, and advancement of relevant energy technologies, the ability to recover costs through existing ratemaking provisions, and the outcome of pending and/or future legal challenges.

Because natural gas is a fossil fuel with lower carbon content relative to other fossil fuels, future GHG constraints, including, but not limited to, the imposition of a carbon tax, may create additional demand for natural gas, both for production of electricity and direct use in homes and businesses. Future GHG constraints designed to minimize emissions from natural gas could likewise result in increased costs to the Southern Company system and affect the demand for natural gas as well as the prices charged to customers and the competitive position of natural gas.

I-20

Table of Contents Index to Financial Statements

The net income of Southern Company, the traditional electric operating companies, and Southern Power could be negatively impacted by changes in regulations related to transmission planning processes and competition in the wholesale electric markets.

The traditional electric operating companies currently own and operate transmission facilities as part of a vertically integrated utility. A small percentage of transmission revenues are collected through the wholesale electric tariff but the majority are collected through retail rates. FERC rules pertaining to regional transmission planning and cost allocation present challenges to transmission planning and the wholesale market structure. The key impacts of these rules include:


•	possible disruption of the integrated resource planning processes within the states in the Southern Company system's service territory;


•	delays and additional processes for developing transmission plans; and


•	possible impacts on state jurisdiction of approving, certifying, and pricing new transmission facilities.

The FERC rules related to transmission are intended to spur the development of new transmission infrastructure to promote and encourage the integration of renewable sources of supply as well as facilitate competition in the wholesale market by providing more choices to wholesale power customers. Technology changes in the power and fuel industries continue to create significant impacts to wholesale transaction cost structures. The impact of these and other such developments and the effect of changes in levels of wholesale supply and demand are uncertain. The financial condition, net income, and cash flows of Southern Company, the traditional electric operating companies, and Southern Power could be adversely affected by these and other changes.

The traditional electric operating companies and Southern Power could be subject to higher costs as a result of implementing and maintaining compliance with the North American Electric Reliability Corporation mandatory reliability standards along with possible associated penalties for non-compliance.

Owners and operators of bulk power systems, including the traditional electric operating companies, are subject to mandatory reliability standards enacted by the North American Electric Reliability Corporation and enforced by the FERC. Compliance with or changes in the mandatory reliability standards may subject the traditional electric operating companies and Southern Power to higher operating costs and/or increased capital expenditures. If any traditional electric operating company or Southern Power is found to be in noncompliance with these standards, such traditional electric operating company or Southern Power could be subject to sanctions, including substantial monetary penalties.

OPERATIONAL RISKS

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

The financial performance of Southern Company and its subsidiaries depends on the successful operation of the electric generation, transmission, and distribution facilities and natural gas distribution and storage facilities and the successful performance of necessary corporate functions. There are many risks that could affect these operations and performance of corporate functions, including:


•	operator error or failure of equipment or processes;


•	accidents;


•	operating limitations that may be imposed by environmental or other regulatory requirements or in connection with joint owner arrangements;


•	labor disputes;


•	physical attacks;


•	fuel or material supply interruptions and/or shortages;


•	transmission disruption or capacity constraints, including with respect to the Southern Company system's and third parties' transmission, storage, and transportation facilities;


•	compliance with mandatory reliability standards, including mandatory cyber security standards;


•	implementation of new technologies;


•	information technology system failures;


•	cyber intrusions;


•	environmental events, such as spills or releases; and


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

A decrease or elimination of revenues from the electric generation, transmission, or distribution facilities or natural gas distribution or storage facilities or an increase in the cost of operating the facilities would reduce the net income and cash flows and could adversely impact the financial condition of the affected registrant.

I-21

Table of Contents Index to Financial Statements

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

Alabama Power owns, and contracts for the operation of, two nuclear units and Georgia Power holds undivided interests in, and contracts for the operation of, four existing nuclear units. The six existing units are operated by Southern Nuclear and represent approximately 3,680 MWs, or 8% of the Southern Company system's electric generation capacity at January 1, 2019. In addition, these units generated approximately 25% of the total KWHs generated by each of Alabama Power and Georgia Power in the year ended December 31, 2018. In addition, Southern Nuclear, on behalf of Georgia Power and the other Vogtle Owners, is managing the construction of Plant Vogtle Units 3 and 4. Due solely to the increase in nuclear generating capacity, the below risks are expected to increase incrementally once Plant Vogtle Units 3 and 4 are operational. Nuclear facilities are subject to environmental, safety, health, operational, and financial risks such as:


•	the potential harmful effects on the environment and human health and safety resulting from a release of radioactive materials in connection with the operation of nuclear facilities and the storage, handling, and disposal of radioactive material, including spent nuclear fuel;


•	uncertainties with respect to the ability to dispose of spent nuclear fuel and the need for longer term on-site storage;


•	uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of licensed lives and the ability to maintain and anticipate adequate capital reserves for decommissioning;


•	limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with the nuclear operations of Alabama Power and Georgia Power or those of other commercial nuclear facility owners in the U.S.;


•	potential liabilities arising out of the operation of these facilities;


•	significant capital expenditures relating to maintenance, operation, security, and repair of these facilities, including repairs and upgrades required by the NRC;


•	actual or threatened cyber intrusions or physical attacks; and


•	the potential impact of an accident or natural disaster.

It is possible that damages, decommissioning, or other costs could exceed the amount of decommissioning trusts or external insurance coverage, including statutorily required nuclear incident insurance.

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

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

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

Southern Company Gas' natural gas distribution and storage activities involve a variety of inherent hazards and operating risks, such as leaks, accidents, explosions, and mechanical problems, which could result in serious injury to employees and non-employees, loss of life, significant damage to property, environmental pollution, and impairment of its operations. The location of pipelines and storage facilities near populated areas could increase the level of damage resulting from these risks. Additionally, these pipeline and storage facilities are subject to various state and other regulatory requirements. Failure to comply with these regulatory requirements could result in substantial monetary penalties or potential early retirement of storage facilities, which could trigger an associated impairment. The occurrence of any of these events not fully covered by insurance or otherwise could adversely affect Southern Company Gas' and Southern Company's financial condition and results of operations.

Physical attacks, both threatened and actual, could impact the ability of the Subsidiary Registrants to operate and could adversely affect financial results and liquidity.

The Subsidiary Registrants face the risk of physical attacks, both threatened and actual, against their respective generation and storage facilities and the transmission and distribution infrastructure used to transport energy, which could negatively impact

I-22

Table of Contents Index to Financial Statements

their ability to generate, transport, and deliver power, or otherwise operate their respective facilities, or, with respect to Southern Company Gas, its ability to distribute or store natural gas, or otherwise operate its facilities, in the most efficient manner or at all. In addition, physical attacks against third-party providers could have a similar effect on Southern Company and its subsidiaries.

These events could harm the reputation of and negatively affect the financial results of the registrants through lost revenues and costs to repair damage, if such costs cannot be recovered.

An information security incident, including a cybersecurity breach, or the failure of one or more key information technology systems, networks, or processes could impact the ability of the registrants to operate and could adversely affect financial results and liquidity.

Information security risks have generally increased in recent years as a result of the proliferation of new technology and increased sophistication and frequency of cyber attacks and data security breaches. The Subsidiary Registrants operate in highly regulated industries that require the continued operation of sophisticated information technology systems and network infrastructure, which are part of interconnected distribution systems. Because of the critical nature of the infrastructure, increased connectivity to the internet, and technology systems' inherent vulnerability to disability or failures due to hacking, viruses, acts of war or terrorism, or other types of data security breaches, Southern Company and its subsidiaries face a heightened risk of cyberattack. Parties that wish to disrupt the U.S. bulk power system or Southern Company system operations could view these computer systems, software, or networks as targets. The registrants and their third-party vendors have been subject, and will likely continue to be subject, to attempts to gain unauthorized access to their information technology systems and confidential data or to attempts to disrupt utility operations. As a result, Southern Company and its subsidiaries face on-going threats to their assets, including assets deemed critical infrastructure, where databases and systems have been, and will likely continue to be, subject to advanced computer viruses or other malicious codes, unauthorized access attempts, phishing, and other cyber attacks. While there have been immaterial incidents of phishing and attempted financial fraud across the Southern Company system, there has been no material impact on business or operations from these attacks. However, the registrants cannot guarantee that security efforts will prevent breaches, operational incidents, or other breakdowns of information technology systems and network infrastructure and cannot provide any assurance that such incidents will not have a material adverse effect in the future.

In addition, in the ordinary course of business, Southern Company and its subsidiaries collect and retain sensitive information, including personally identifiable information about customers, employees, and stockholders, and other confidential information. In some cases, administration of certain functions may be outsourced to third-party service providers that could also be targets of cyber attacks. Generally, Southern Company and its subsidiaries enter certain contractual security guarantees and assurances with these third parties to help ensure the security and safety of this information.

Despite the implementation of robust security measures, all assets are potentially vulnerable to disability, failures, or unauthorized access due to human error, natural disasters, technological failure, or internal or external cyber attacks. If assets were to fail or be breached and were not restored in a timely manner, the affected registrant may be unable to fulfill critical business functions, and sensitive and other data could be compromised. Any cyber breach or theft, damage, or improper disclosure of sensitive electronic data may also subject the affected registrant to penalties and claims from regulators or other third parties. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result. In addition, as cybercriminals become more sophisticated, the cost of proactive defensive measures may increase.

These events could negatively affect the financial results of the registrants through lost revenues, costs to recover and repair damage, costs associated with governmental actions in response to such attacks, and litigation costs if such costs cannot be recovered through insurance or otherwise.

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

The traditional electric operating companies and Southern Power purchase fuel, including coal, natural gas, uranium, fuel oil, and biomass, as applicable, from a number of suppliers. Additionally, the traditional electric operating companies and Southern

I-23

Table of Contents Index to Financial Statements

Power need adequate access to water, which is drawn from nearby sources to aid in the production of electricity and, once it is used, returned to its source. Disruption in the delivery of fuel, including disruptions as a result of, among other things, transportation delays, weather, labor relations, force majeure events, or environmental regulations affecting any of these fuel suppliers, or the availability of water, could limit the ability of the traditional electric operating companies and Southern Power to operate certain facilities, which could result in higher fuel and operating costs and potentially reduce the net income of the affected traditional electric operating company or Southern Power and Southern Company.

Southern Company Gas' primary business is the distribution and sale of natural gas through its regulated and unregulated subsidiaries. Natural gas supplies can be subject to disruption in the event production or distribution is curtailed, such as in the event of a hurricane or a pipeline failure. Southern Company Gas also relies on natural gas pipelines and other storage and transportation facilities owned and operated by third parties to deliver natural gas to wholesale markets and to Southern Company Gas' distribution systems. The availability of shale gas and potential regulations affecting its accessibility may have a material impact on the supply and cost of natural gas. Disruption in natural gas supplies could limit the ability to fulfill these contractual obligations.

The traditional electric operating companies and Southern Power have become more dependent on natural gas for a portion of their electric generating capacity and expect to continue to increase such dependence. In many instances, the cost of purchased power for the traditional electric operating companies and Southern Power is influenced by natural gas prices. Historically, natural gas prices have been more volatile than prices of other fuels. In recent years, domestic natural gas prices have been depressed by robust supplies, including production from shale gas. These market conditions, together with additional regulation of coal-fired generating units, have increased the traditional electric operating companies' reliance on natural gas-fired generating units.

The traditional electric operating companies are also dependent on coal for a portion of their electric generating capacity. The traditional electric operating companies depend on coal supply contracts, and the counterparties to these agreements may not fulfill their obligations to supply coal to the traditional electric operating companies. The suppliers may experience financial or technical problems that inhibit their ability to fulfill their obligations. In addition, the suppliers may not be required to supply coal under certain circumstances, such as in the event of a natural disaster. If the traditional electric operating companies are unable to obtain their coal requirements under these contracts, they may be required to purchase their coal requirements at higher prices, which may not be recoverable through rates.

The revenues of Southern Company, the traditional electric operating companies, and Southern Power depend in part on sales under PPAs. The failure of a counterparty to one of these PPAs to perform its obligations, the failure of the traditional electric operating companies or Southern Power to satisfy minimum requirements under the PPAs, or the failure to renew the PPAs or successfully remarket the related generating capacity could have a negative impact on the net income and cash flows of the affected traditional electric operating company or Southern Power and of Southern Company.

Most of Southern Power's generating capacity has been sold to purchasers under PPAs. Southern Power's top three customers, Georgia Power, Duke Energy Corporation, and Southern California Edison accounted for 9.8%, 6.8%, and 6.2%, respectively, of Southern Power's total revenues for the year ended December 31, 2018. In addition, the traditional electric operating companies enter into PPAs with non-affiliated parties. Revenues are dependent on the continued performance by the purchasers of their obligations under these PPAs. The failure of one of the purchasers to perform its obligations, including as a result of a general default or bankruptcy, could have a negative impact on the net income and cash flows of the affected traditional electric operating company or Southern Power and of Southern Company. Although the credit evaluations undertaken and contractual protections implemented by Southern Power and the traditional electric operating companies take into account the possibility of default by a purchaser, actual exposure to a default by a purchaser may be greater than predicted or specified in the applicable contract. See Note 1 to the financial statements under "Revenues – Concentration of Revenue" in Item 8 herein for additional information on Pacific Gas & Electric Company's bankruptcy filing.

Additionally, neither Southern Power nor any traditional electric operating company can predict whether the PPAs will be renewed at the end of their respective terms or on what terms any renewals may be made. The failure of the traditional electric operating companies or Southern Power to satisfy minimum operational or availability requirements under these PPAs could result in payment of damages or termination of the PPAs.

The asset management arrangements between Southern Company Gas' wholesale gas services and its customers, including the natural gas distribution utilities, may not be renewed or may be renewed at lower levels, which could have a significant impact on Southern Company Gas' financial results.

Southern Company Gas' wholesale gas services currently manages the storage and transportation assets of the natural gas distribution utilities (except Nicor Gas) as well as certain non-affiliated customers. Southern Company Gas' wholesale gas

I-24

Table of Contents Index to Financial Statements

services has a concentration of credit risk for services it provides to its counterparties, which is generally concentrated in 20 of its counterparties.

The profits earned from the management of affiliate assets are shared with the respective affiliate's customers (and for Atlanta Gas Light with the Georgia PSC's Universal Service Fund), except for Chattanooga Gas where wholesale gas services are provided under annual fixed-fee agreements. These asset management agreements are subject to regulatory approval and such agreements may not be renewed or may be renewed with less favorable terms.

The financial results of Southern Company Gas' wholesale gas services could be significantly impacted if any of its agreements with its affiliated or non-affiliated customers are not renewed or are amended or renewed with less favorable terms. Sustained low natural gas prices could reduce the demand for these types of asset management arrangements.

Increased competition could negatively impact Southern Company's and its subsidiaries' revenues, results of operations, and financial condition.

The Southern Company system faces increasing competition from other companies that supply energy or generation and storage technologies. Changes in technology may make the Southern Company system's electric generating facilities owned by the traditional electric operating companies and Southern Power less competitive. Southern Company Gas' business is dependent on natural gas prices remaining competitive as compared to other forms of energy. Southern Company Gas also faces competition in its unregulated markets.

A key element of the business models of the traditional electric operating companies and Southern Power is that generating power at central station power plants achieves economies of scale and produces power at a competitive cost. There are distributed generation and storage technologies that produce and store power, including fuel cells, microturbines, wind turbines, solar cells, and batteries. Advances in technology or changes in laws or regulations could reduce the cost of these or other alternative methods of producing power to a level that is competitive with that of most central station power electric production or result in smaller-scale, more fuel efficient, and/or more cost effective distributed generation that allows for increased self-generation by customers. Broader use of distributed generation by retail energy customers may also result from customers' changing perceptions of the merits of utilizing existing generation technology or tax or other economic incentives. Additionally, a state PSC or legislature may modify certain aspects of the traditional electric operating companies' business as a result of these advances in technology.

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

Southern Company Gas' gas marketing services is affected by competition from other energy marketers providing similar services in Southern Company Gas' service territories, most notably in Illinois and Georgia. Southern Company Gas' wholesale gas services competes for sales with national and regional full-service energy providers, energy merchants and producers, and pipelines based on the ability to aggregate competitively-priced commodities with transportation and storage capacity. Southern Company Gas competes with natural gas facilities in the Gulf Coast region of the U.S., as the majority of the existing and proposed high deliverability salt-dome natural gas storage facilities in North America are located in the Gulf Coast region.

If new technologies become cost competitive and achieve sufficient scale, the market share of the Subsidiary Registrants could be eroded, and the value of their respective electric generating facilities or natural gas distribution and storage facilities could be reduced. Additionally, Southern Company Gas' market share could be reduced if Southern Company Gas cannot remain price competitive in its unregulated markets. If state PSCs or other applicable state regulatory agencies fail to adjust rates to reflect the impact of any changes in loads, increasing self-generation, and the growth of distributed generation, the financial condition, results of operations, and cash flows of Southern Company and the affected traditional electric operating company or Southern Company Gas could be materially adversely affected.

Failure to attract and retain an appropriately qualified workforce could negatively impact Southern Company's and its subsidiaries' results of operations.

Events such as an aging workforce without appropriate replacements, mismatch of skill sets to future needs, or unavailability of contract resources may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development, including with the workforce needs associated with major construction projects and ongoing operations. The Southern Company system's costs, including costs for contractors to replace employees, productivity costs, and safety costs, may rise. Failure to hire and adequately obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect Southern Company and its subsidiaries' ability to manage and operate their businesses. If Southern Company

I-25

Table of Contents Index to Financial Statements

and its subsidiaries are unable to successfully attract and retain an appropriately qualified workforce, results of operations could be negatively impacted.

CONSTRUCTION RISKS

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

General

The businesses of the registrants require substantial expenditures for investments in new facilities and, for the traditional electric operating companies, capital improvements to transmission, distribution, and generation facilities, for Southern Power, capital improvements to generation facilities, and, for Southern Company Gas, capital improvements to natural gas distribution and storage facilities. These expenditures also include those to meet AROs and environmental standards and goals. Certain of the traditional electric operating companies and Southern Power are in the process of constructing new generating facilities and adding environmental controls equipment at existing generating facilities. Southern Company Gas is replacing certain pipelines in its natural gas distribution system and is involved in two new gas pipeline construction projects. The Southern Company system intends to continue its strategy of developing and constructing other new facilities, expanding or updating existing facilities, and adding environmental control equipment. These types of projects are long term in nature and in some cases may include the development and construction of facilities with designs that have not been finalized or previously constructed. The completion of these types of projects without delays or significant cost overruns is subject to substantial risks, including:


•	shortages, increased costs, or inconsistent quality of equipment, materials, and labor;


•	changes in labor costs, availability, and productivity;


•	challenges related to management of contractors, subcontractors, or vendors;


•	work stoppages;


•	contractor or supplier delay;


•	non-performance under construction, operating, or other agreements;


•	delays in or failure to receive necessary permits, approvals, tax credits, and other regulatory authorizations;


•	delays in start-up activities (including major equipment failure and system integration) and/or operational performance;


•	operational readiness, including specialized operator training and required site safety programs;


•	impacts of new and existing laws and regulations, including environmental laws and regulations;


•	the outcome of any legal challenges to projects, including legal challenges to regulatory approvals;


•	failure to construct in accordance with permitting and licensing requirements (including satisfaction of NRC requirements);


•	failure to satisfy any environmental performance standards and the requirements of tax credits and other incentives;


•	continued public and policymaker support for projects;


•	adverse weather conditions or natural disasters;


•	engineering or design problems;


•	changes in project design or scope;


•	environmental and geological conditions;


•	delays or increased costs to interconnect facilities to transmission grids; and


•	increased financing costs as a result of changes in market interest rates or as a result of project delays.

If a Subsidiary Registrant is unable to complete the development or construction of a project or decides to delay or cancel construction of a project, it may not be able to recover its investment in that project and may incur substantial cancellation payments under equipment purchase orders or construction contracts, as well as other costs associated with the closure and/or abandonment of the construction project. See Note 2 to the financial statements under "Kemper County Energy Facility" for information related to the abandonment of and related closure activities and costs for the mine and gasifier-related assets at the Kemper County energy facility.

Additionally, each Southern Company Gas pipeline construction project involves separate joint venture participants, Southern Power participates in partnership agreements with respect to renewable energy projects, and Georgia Power jointly owns Plant Vogtle Units 3 and 4 with other co-owners. Any failure by a partner or co-owner to perform its obligations under the applicable agreements could have a material negative impact on the applicable project under construction. In addition, partnership and joint ownership agreements may provide partners or co-owners with certain decision-making authority in connection with projects under construction, including rights to cause the cancellation of a construction project under certain circumstances.

Even if a construction project (including a joint venture construction project) is completed, the total costs may be higher than estimated and may not be recoverable through regulated rates, if applicable. In addition, construction delays and contractor

I-26

Table of Contents Index to Financial Statements

performance shortfalls can result in the loss of revenues and may, in turn, adversely affect the net income and financial position of the affected registrant. See Note 2 to the financial statements under "FERC Matters – Southern Company Gas" for information regarding the Atlantic Coast Pipeline construction delays and the associated cost increase.

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

Once facilities become operational, ongoing capital expenditures are required to maintain reliable levels of operation. Significant portions of the traditional electric operating companies' existing facilities were constructed many years ago. Older equipment, even if maintained in accordance with good engineering practices, may require significant expenditures to maintain efficiency, to comply with changing environmental requirements, to provide safe and reliable operations, and/or to meet related retirement obligations.

The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4.

Plant Vogtle Units 3 and 4 construction and rate recovery

Background

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. 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 March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.

Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:



	(in billions)
Base project capital cost forecast^(a)(b)	$	8.0
Construction contingency estimate	0.4
Total project capital cost forecast^(a)(b)	8.4
Net investment as of December 31, 2018^(b)	(4.6		)
Remaining estimate to complete^(a)	$	3.8


(a)	Excludes financing costs expected to be capitalized through AFUDC of approximately $315 million.


(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 $3.1 billion, of which $1.9 billion had been incurred through December 31, 2018.

As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation and testing, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers must be retained and deployed.

I-27

Table of Contents Index to Financial Statements

Georgia Power and Southern Nuclear believe it is a leading practice in connection with a construction project of this size and complexity to periodically validate recent construction progress in comparison to the projected schedule and to verify and update quantities of commodities remaining to install, labor productivity, and forecasted staffing needs. This verification process, led by Southern Nuclear, was underway as of December 31, 2018 and is expected to be completed during the second quarter 2019. Georgia Power currently does not anticipate any material changes to the total estimated project capital cost forecast for Plant Vogtle Units 3 and 4 or the expected in-service dates of November 2021 and November 2022, respectively, resulting from this verification process. However, the ultimate impact on cost and schedule, if any, will not be known until the verification process is completed. Georgia Power is required to report the results and any project impacts to the Georgia PSC by May 15, 2019.

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 assure 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. As a result of such compliance processes, 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 resolution of ITAAC and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues 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 project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, 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

As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs as described below, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. On September 26, 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.

Amendments to the Vogtle Joint Ownership Agreements

In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG'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, and (ii) a term sheet (MEAG Term Sheet) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 (Project J) under certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet (MEAG Funding Agreement). On February 18, 2019, Georgia Power, the other Vogtle Owners, and MEAG'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, and consistent with the Vogtle Owner Term Sheet, the Vogtle Joint Ownership Agreements were modified as follows: (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

I-28

Table of Contents Index to Financial Statements

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 this event, Georgia Power will have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Vogtle Owner. If Georgia Power accepts the offer to purchase a portion of another Vogtle Owner's ownership interest in Plant Vogtle Units 3 and 4, the ownership interest(s) to be conveyed from the tendering Vogtle Owner(s) to Georgia Power will be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Vogtle Owner(s) and by Georgia Power as of the COD of Plant Vogtle Unit 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Vogtle Owner in accordance with the second and third items described in the paragraph above will be treated as payments made by the applicable Vogtle Owner.

In the event the actual costs of construction at completion of a Unit are less than the EAC reflected in the nineteenth VCM report and such Unit is placed in service in accordance with the schedule projected in the nineteenth VCM report (i.e., Plant Vogtle Unit 3 is placed in service by November 2021 or Plant Vogtle Unit 4 is placed in service by November 2022), Georgia Power will be entitled to 60.7% of the cost savings with respect to the relevant Unit and the remaining Vogtle Owners will be entitled to 39.3% of such savings on a pro rata basis in accordance with their respective ownership interests.

For purposes of the foregoing provisions, qualifying construction costs will not include costs (i) resulting from force majeure events, including governmental actions or inactions (or significant delays associated with issuance of such actions) that affect the licensing, completion, start-up, operations, or financing of Plant Vogtle Units 3 and 4, administrative proceedings or litigation regarding ITAAC or other regulatory challenges to commencement of operation of Plant Vogtle Units 3 and 4, and changes in laws or regulations governing Plant Vogtle Units 3 and 4, (ii) legal fees and legal expenses incurred due to litigation with contractors or subcontractors that are not subsidiaries or affiliates of Southern Company, and (iii) additional costs caused by requests from the Vogtle Owners other than Georgia Power, except for the exercise of a right to vote granted under the Vogtle Joint Ownership Agreements, that increase costs by $100,000 or more.

Pursuant to the Global Amendments, and consistent with the Vogtle Owner Term Sheet, the provisions of the Vogtle Joint Ownership Agreements requiring that Vogtle Owners holding 90% of the ownership interests in Plant Vogtle Units 3 and 4 vote to continue construction following certain adverse events (Project Adverse Events) were modified. 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 Project Adverse Events occur, including: (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 publicly announces 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 over the most recently approved schedule. Under the Global Amendments, Georgia Power may cancel the project at any time in its sole discretion.

In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.

The Global Amendments provide that if the holders of at least 90% of the ownership interests fail to vote in favor of continuing the project following any future Project Adverse Event, work on Plant Vogtle Units 3 and 4 will continue for a period of 30 days if the holders of more than 50% of the ownership interests vote in favor of continuing construction (Majority Voting Owners). In such a case, the Vogtle Owners (i) have agreed to negotiate in good faith towards the resumption of the project, (ii) if no agreement is reached during such 30-day period, the project will be cancelled, and (iii) in the event of such a cancellation, the Majority Voting Owners will be obligated to reimburse any other Vogtle Owner for the incremental costs it incurred during such 30-day negotiation period.

I-29

Table of Contents Index to Financial Statements

Purchase of PTCs During Commercial Operation

Pursuant to the Global Amendments, and consistent with the Vogtle Owner Term Sheet, Georgia Power has agreed to purchase additional PTCs from OPC, Dalton, MEAG SPVM, MEAG SPVP, and MEAG SPVJ (to the extent any MEAG SPVJ PTC rights remain after any purchases required under the MEAG Funding Agreement as described below) at varying purchase prices dependent upon the actual cost to complete construction of Plant Vogtle Units 3 and 4 as compared to the EAC reflected in the nineteenth VCM report. The purchases are at the option of the applicable Vogtle Owner.

Potential Funding to MEAG Project J

Pursuant to the MEAG Funding Agreement, and consistent with the MEAG Term Sheet, if MEAG SPVJ is unable to make its payments due under the Vogtle Joint Ownership Agreements solely as a result of the occurrence of one of the following situations that materially impedes access to capital markets for MEAG for Project J: (i) the conduct of JEA or the City of Jacksonville, such as JEA's legal challenges of its obligations under a PPA with MEAG (PPA-J), or (ii) PPA-J is declared void by a court of competent jurisdiction or rejected by JEA under the applicable provisions of the U.S. Bankruptcy Code (each of (i) and (ii), a JEA Default), at MEAG's request, Georgia Power will purchase from MEAG SPVJ the rights to PTCs attributable to MEAG SPVJ's share of Plant Vogtle Units 3 and 4 (approximately 206 MWs) within 30 days of such request at varying prices dependent upon the stage of construction of Plant Vogtle Units 3 and 4. The aggregate purchase price of the PTCs, together with any advances made as described in the next paragraph, shall not exceed $300 million.

At the option of MEAG, as an alternative or supplement to Georgia Power's purchase of PTCs as described above, Georgia Power has agreed to provide up to $250 million in funding to MEAG for Project J in the form of advances (either advances under the Vogtle Joint Ownership Agreements or the purchase of MEAG Project J bonds, at the discretion of Georgia Power), subject to any required approvals of the Georgia PSC and the DOE.

In the event MEAG SPVJ certifies to Georgia Power that it is unable to fund its obligations under the Vogtle Joint Ownership Agreements as a result of a JEA Default and Georgia Power becomes obligated to provide funding as described above, MEAG is required to (i) assign to Georgia Power its right to vote on any future Project Adverse Event and (ii) diligently pursue JEA for its breach of PPA-J. In addition, Georgia Power agreed that it will not sue MEAG for any amounts due from MEAG SPVJ under MEAG's guarantee of MEAG SPVJ's obligations so long as MEAG SPVJ complies with the terms of the MEAG Funding Agreement as to its payment obligations and the other non-payment provisions of the Vogtle Joint Ownership Agreements.

Under the terms of the MEAG Funding Agreement, Georgia Power may cancel the project in lieu of providing funding in the form of advances or PTC purchases.

Regulatory Matters

In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's recommendation to continue construction and 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 amounts 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 prudence decisions on cost recovery will be made at a later date, 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 upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. 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 $100 million, $25 million, and $20 million in 2018, 2017, and 2016, respectively, and are estimated to have negative earnings impacts of approximately $75 million in 2019 and an aggregate of approximately $615 million from 2020 to 2022.

I-30

Table of Contents Index to Financial Statements

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.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. (GIPL) and Partnership for Southern Equity, Inc. (PSE) filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. On March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's decision and denial of Georgia Watch's motion for reconsideration. On December 21, 2018, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. On January 9, 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. Georgia Power believes the appeal has no merit; however, an adverse outcome in the appeal combined with subsequent adverse action by the Georgia PSC could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.

In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. This reforecast, performed prior to the nineteenth VCM filing, resulted in a $0.7 billion increase to the base capital cost forecast reported in the second quarter 2018. This base cost increase primarily resulted from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.

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 did not seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs) in the nineteenth VCM report. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate 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 a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018, which includes the total increase in the base capital cost forecast and construction contingency estimate.

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

See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 herein for additional information regarding Plant Vogtle Units 3 and 4.

Southern Company Gas' significant investments in pipelines and pipeline development projects involve financial and execution risks.

Southern Company Gas has made significant investments in existing pipelines and pipeline development projects. Many of the existing pipelines are, and when completed many of the pipeline development projects will be, operated by third parties. If one of these agents fails to perform in a proper manner, the value of the investment could decline and Southern Company Gas could lose part or all of its investment. In addition, from time to time, Southern Company Gas may be required to contribute additional capital to a pipeline joint venture or guarantee the obligations of such joint venture.

With respect to certain pipeline development projects, Southern Company Gas will rely on its joint venture partners for construction management and will not exercise direct control over the process. All of the pipeline development projects are dependent on contractors for the successful and timely completion of the projects. Further, the development of pipeline projects involves numerous regulatory, environmental, construction, safety, political, and legal uncertainties and may require the expenditure of significant amounts of capital. These projects may not be completed on schedule, at the budgeted cost, or at all. There may be cost overruns and construction difficulties that cause Southern Company Gas' capital expenditures to exceed its initial expectations. Moreover, Southern Company Gas' income will not increase immediately upon the expenditure of funds on a pipeline project. Pipeline construction occurs over an extended period of time and Southern Company Gas will not receive material increases in income until the project is placed in service.

Work continues with state and federal agencies to obtain the required permits to begin construction on the PennEast Pipeline. Any material delays may impact forecasted capital expenditures and the expected in-service date.

I-31

Table of Contents Index to Financial Statements

key segments of the Atlantic Coast Pipeline, while the remainder may extend into early 2021. Abnormal weather, work delays (including due to judicial or regulatory action), and other conditions may result in additional cost or schedule modifications, which could result in an impairment of Southern Company Gas' investment and could have a material impact on Southern Company's and Southern Company Gas' financial statements.

The ultimate outcome of these matters cannot be determined at this time and the occurrence of these or any other of the foregoing events could adversely affect the results of operations, cash flows, and financial condition of Southern Company Gas and Southern Company.

FINANCIAL, ECONOMIC, AND MARKET RISKS

The electric generation and energy marketing operations of the traditional electric operating companies and Southern Power and the natural gas operations of Southern Company Gas are subject to risks, many of which are beyond their control, including changes in energy prices and fuel costs, which may reduce revenues and increase costs.

The generation, energy marketing, and natural gas operations of the Southern Company system are subject to changes in energy prices and fuel costs, which could increase the cost of producing power, decrease the amount received from the sale of energy, and/or make electric generating facilities less competitive. The market prices for these commodities may fluctuate significantly over relatively short periods of time. Among the factors that could influence energy prices and fuel costs are:


•	prevailing market prices for coal, natural gas, uranium, fuel oil, biomass, and other fuels, as applicable, used in the generation facilities of the traditional electric operating companies and Southern Power and, in the case of natural gas, distributed by Southern Company Gas, including associated transportation costs, and supplies of such commodities;


•	demand for energy and the extent of additional supplies of energy available from current or new competitors;


•	liquidity in the general wholesale electricity and natural gas markets;


•	weather conditions impacting demand for electricity and natural gas;


•	seasonality;


•	transmission or transportation constraints, disruptions, or inefficiencies;


•	availability of competitively priced alternative energy sources;


•	forced or unscheduled plant outages for the Southern Company system, its competitors, or third party providers;


•	the financial condition of market participants;


•	the economy in the Southern Company system's service territory, the nation, and worldwide, including the impact of economic conditions on demand for electricity and the demand for fuels, including natural gas;


•	natural disasters, wars, embargos, physical or cyber attacks, and other catastrophic events; and


•	federal, state, and foreign energy and environmental regulation and legislation.

These factors could increase the expenses and/or reduce the revenues of the registrants. For the traditional electric operating companies and Southern Company Gas' regulated gas distribution operations, such impacts may not be fully recoverable through rates.

Historically, the traditional electric operating companies and Southern Company Gas from time to time have experienced underrecovered fuel and/or purchased gas cost balances and may experience such balances in the future. While the traditional electric operating companies and Southern Company Gas are generally authorized to recover fuel and/or purchased gas costs through cost recovery clauses, recovery may be denied if costs are deemed to be imprudently incurred, and delays in the authorization of such recovery, both of which could negatively impact the cash flows of the affected traditional electric operating company or Southern Company Gas and of Southern Company.

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

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

Outside of economic disruptions, changes in customer behaviors in response to energy efficiency programs, changing conditions and preferences, or changes in the adoption of technologies could affect the relationship of economic activity to the consumption of energy.

Both federal and state programs exist to influence how customers use energy, and several of the traditional electric operating companies and Southern Company Gas have PSC or other applicable state regulatory agency mandates to promote energy efficiency. Conservation programs could impact the financial results of the registrants in different ways. For example, if any traditional electric operating company or Southern Company Gas is required to invest in conservation measures that result in

I-32

Table of Contents Index to Financial Statements

reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact on such traditional electric operating company or Southern Company Gas and Southern Company. Customers could also voluntarily reduce their consumption of energy in response to decreases in their disposable income, increases in energy prices, or individual conservation efforts.

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

All of the factors discussed above could adversely affect a registrant's results of operations, financial condition, and liquidity.

The operating results of the registrants are affected by weather conditions and may fluctuate on a seasonal and quarterly basis. In addition, catastrophic events, such as fires, earthquakes, hurricanes, tornadoes, floods, droughts, and storms, could result in substantial damage to or limit the operation of the properties of a Subsidiary Registrant and could negatively impact results of operation, financial condition, and liquidity.

Electric power and natural gas supply are generally seasonal businesses. In many parts of the country, demand for power peaks during the summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter months. While the electric power sales of some of the traditional electric operating companies peak in the summer, others peak in the winter. In the aggregate, electric power sales peak during the summer with a smaller peak during the winter. Additionally, Southern Power has variability in its revenues from renewable generation facilities due to seasonal weather patterns primarily from wind and sun. In most of the areas Southern Company Gas serves, natural gas demand peaks during the winter. As a result, the overall operating results of the registrants may fluctuate substantially on a seasonal basis. In addition, the Subsidiary Registrants have historically sold less power and natural gas when weather conditions are milder. Unusually mild weather in the future could reduce the revenues, net income, and available cash of the affected registrant.

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

In the event a traditional electric operating company or Southern Company Gas experiences any of these weather events or any natural disaster or other catastrophic event, recovery of costs in excess of reserves and insurance coverage is subject to the approval of its state PSC or other applicable state regulatory agency. Historically, the traditional electric operating companies from time to time have experienced deficits in their storm cost recovery reserve balances and may experience such deficits in the future. For example, at December 31, 2018, Georgia Power had a substantial underrecovered balance in its storm cost recovery balance as a result of multiple recent significant hurricanes in its service territory. Any denial by the applicable state PSC or other applicable state regulatory agency or delay in recovery of any portion of such costs could have a material negative impact on a traditional electric operating company's or Southern Company Gas' and on Southern Company's results of operations, financial condition, and liquidity.

In addition, damages resulting from significant weather events within the service territory of any traditional electric operating company or Southern Company Gas or affecting Southern Power's customers may result in the loss of customers and reduced demand for energy for extended periods and may impact customers' ability to perform under existing PPAs. See Note 1 to the financial statements under "Revenues – Concentration of Revenue" in Item 8 herein for additional information on Pacific Gas & Electric Company's bankruptcy filing. Any significant loss of customers or reduction in demand for energy could have a material negative impact on a registrant's results of operations, financial condition, and liquidity.

Acquisitions, dispositions, or other strategic ventures or investments may not result in anticipated benefits and may present risks not originally contemplated, which may have a material adverse effect on the liquidity, results of operations, and financial condition of Southern Company and its subsidiaries.

Southern Company and its subsidiaries have made significant acquisitions and investments in the past, as well as recent dispositions, and may in the future make additional acquisitions, dispositions, or other strategic ventures or investments, including the pending disposition by Southern Power of Plant Mankato, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries. Southern Company and its subsidiaries continually seek opportunities to create value

I-33

Table of Contents Index to Financial Statements

through various transactions, including acquisitions or sales of assets. Specifically, Southern Power continually seeks opportunities to execute its strategy to create value through various transactions, including acquisitions, dispositions, and sales of partnership interests, development and construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, IPPs, municipalities, and other load-serving entities, as well as commercial and industrial customers.

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

These transactions also involve risks, including:


•	they may not result in an increase in income or provide adequate or expected funds or return on capital or other anticipated benefits;


•	they may result in Southern Company or its subsidiaries entering into new or additional lines of business, which may have new or different business or operational risks;


•	they may not be successfully integrated into the acquiring company's operations and/or internal control processes;


•	the due diligence conducted prior to a transaction may not uncover situations that could result in financial or legal exposure or may not appropriately evaluate the likelihood or quantify the exposure from identified risks;


•	they may result in decreased earnings, revenues, or cash flow;


•	Southern Company, Southern Company Gas, and certain of their subsidiaries have retained obligations in connection with transitional agreements related to dispositions that subject these companies to additional risk;


•	Southern Company or the applicable subsidiary may not be able to achieve the expected financial benefits from the use of funds generated by any dispositions;


•	expected benefits of a transaction may be dependent on the cooperation or performance of a counterparty; or


•	for the traditional electric operating companies and Southern Company Gas, costs associated with such investments that were expected to be recovered through regulated rates may not be recoverable.

Southern Company and Southern Company Gas are holding companies and Southern Power owns many of its assets indirectly through subsidiaries. Each of these companies is dependent on cash flows from their respective subsidiaries to meet their ongoing and future financial obligations, including making interest and principal payments on outstanding indebtedness and, for Southern Company, to pay dividends on its common stock.

Southern Company and Southern Company Gas are holding companies and, as such, they have no operations of their own. Substantially all of Southern Company's and Southern Company Gas' and many of Southern Power's respective consolidated assets are held by subsidiaries. A significant portion of Southern Company Gas' debt is issued by its 100%-owned subsidiary, Southern Company Gas Capital, and is fully and unconditionally guaranteed by Southern Company Gas. Southern Company's, Southern Company Gas' and, to a certain extent, Southern Power's ability to meet their respective financial obligations, including making interest and principal payments on outstanding indebtedness, and, for Southern Company, to pay dividends on its common stock, is dependent on the net income and cash flows of their respective subsidiaries and the ability of those subsidiaries to pay upstream dividends or to repay borrowed funds. Prior to funding Southern Company, Southern Company Gas, or Southern Power, the respective subsidiaries have financial obligations and, with respect to Southern Company and Southern Company Gas, regulatory restrictions that must be satisfied, including among others, debt service and preferred stock dividends. These subsidiaries are separate legal entities and, except as described below, have no obligation to provide Southern Company, Southern Company Gas, or Southern Power with funds. Certain of Southern Power's assets are held through controlling interests in subsidiaries. In certain cases, distributions without partner consent are limited to available cash, and the subsidiaries are obligated to distribute all available cash to their owners each quarter. In addition, Southern Company, Southern Company Gas, and Southern Power may provide capital contributions or debt financing to subsidiaries under certain circumstances, which would reduce the funds available to meet their respective financial obligations, including making interest and principal payments on outstanding indebtedness, and to pay dividends on Southern Company's common stock.

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

There are a number of factors that rating agencies evaluate to arrive at credit ratings for the registrants, Southern Company Gas Capital, and Nicor Gas, including capital structure, regulatory environment, the ability to cover liquidity requirements, and other commitments for capital. The registrants, Southern Company Gas Capital, and Nicor Gas could experience a downgrade in their ratings if any rating agency concludes that the level of business or financial risk of the industry or the applicable company has deteriorated. Changes in ratings methodologies by the agencies could also have a negative impact on credit ratings. If one or more rating agencies downgrade any registrant, Southern Company Gas Capital, or Nicor Gas, borrowing

I-34

Table of Contents Index to Financial Statements

costs likely would increase, including automatic increases in interest rates under applicable term loans and credit facilities, the pool of investors and funding sources would likely decrease, and, particularly for any downgrade to below investment grade, significant collateral requirements may be triggered in a number of contracts. Any credit rating downgrades could require altering the mix of debt financing currently used, and could require the issuance of secured indebtedness and/or indebtedness with additional restrictive covenants binding the applicable company.

Uncertainty in demand for energy can result in lower earnings or higher costs. If demand for energy falls short of expectations, it could result in potentially stranded assets. If demand for energy exceeds expectations, it could result in increased costs for purchasing capacity in the open market or building additional electric generation and transmission facilities or natural gas distribution and storage facilities.

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

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

The businesses of the registrants, SEGCO, and Nicor Gas are dependent on their ability to successfully access funds through capital markets and financial institutions. The inability of any of the registrants, SEGCO, or Nicor Gas to access funds may limit its ability to execute its business plan by impacting its ability to fund capital investments or acquisitions that it may otherwise rely on to achieve future earnings and cash flows.

The registrants, SEGCO, and Nicor Gas rely on access to both short-term money markets and longer-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flow from their respective operations. If any of the registrants, SEGCO, or Nicor Gas is not able to access capital at competitive rates or on favorable terms, its ability to implement its business plan will be limited by impacting its ability to fund capital investments or acquisitions that it may otherwise rely on to achieve future earnings and cash flows. In addition, the registrants, SEGCO, and Nicor Gas rely on committed bank lending agreements as back-up liquidity which allows them to access low cost money markets. Each of the registrants, SEGCO, and Nicor Gas believes that it will maintain sufficient access to these financial markets based upon current credit ratings. However, certain events or market disruptions may increase the cost of borrowing or adversely affect the ability to raise capital through the issuance of securities or other borrowing arrangements or the ability to secure committed bank lending agreements used as back-up sources of capital. Such disruptions could include:


•	an economic downturn or uncertainty;


•	bankruptcy or financial distress at an unrelated energy company, financial institution, or sovereign entity;


•	capital markets volatility and disruption, either nationally or internationally;


•	changes in tax policy, including further interpretation and guidance on tax reform;

I-35

Table of Contents Index to Financial Statements


•	volatility in market prices for electricity and natural gas;


•	actual or threatened cyber or physical attacks on the Southern Company system's facilities or unrelated energy companies' facilities;


•	war or threat of war; or


•	the overall health of the utility and financial institution industries.

Georgia Power's ability to make future borrowings through its term loan credit facility with the FFB is subject to the satisfaction of customary conditions, as well as certification of compliance with the requirements of the loan guarantee program under Title XVII of the Energy Policy Act of 2005, including accuracy of project-related representations and warranties, delivery of updated project-related information and evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program. Prior to obtaining any further advances under Georgia Power's loan guarantee agreement with the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement.

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

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

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

The costs of providing pension and other postretirement benefit plans are dependent on a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plan, changes in actuarial assumptions, government regulations, and/or life expectancy, and the frequency and amount of the Southern Company system's required or voluntary contributions made to the plans. Changes in actuarial assumptions and differences between the assumptions and actual values, as well as a significant decline in the value of investments that fund the pension and other postretirement plans, if not offset or mitigated by a decline in plan liabilities, could increase pension and other postretirement expense, and the Southern Company system could be required from time to time to fund the pension plans with significant amounts of cash. Such cash funding obligations could have a material impact on liquidity by reducing cash flows and could negatively affect results of operations. Additionally, Alabama Power and Georgia Power each hold significant assets in their nuclear decommissioning trusts to satisfy obligations to decommission Alabama Power's and Georgia Power's nuclear plants. The rate of return on assets held in those trusts can significantly impact both the funding available for decommissioning and the funding requirements for the trusts.

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

The financial condition of some insurance companies, actual or threatened physical or cyber attacks, and natural disasters, among other things, could have disruptive effects on insurance markets. The availability of insurance covering risks that the registrants and their respective competitors typically insure against may decrease, and the insurance that the registrants are able to obtain may have higher deductibles, higher premiums, and more restrictive policy terms. Further, the insurance policies may not cover all of the potential exposures or the actual amount of loss incurred.

Any losses not covered by insurance, or any increases in the cost of applicable insurance, could adversely affect the results of operations, cash flows, or financial condition of the affected registrant.

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

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

I-36

Table of Contents Index to Financial Statements

future. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

In addition, Southern Company Gas utilizes derivative instruments to lock in economic value in wholesale gas services, which may not qualify as, or may not be designated as, hedges for accounting purposes. The difference in accounting treatment for the underlying position and the financial instrument used to hedge the value of the contract can cause volatility in reported net income of Southern Company and Southern Company Gas while the positions are open due to mark-to-market accounting.

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

Goodwill is assessed for impairment at least annually and more frequently if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value and long-lived assets are assessed for impairment whenever events or circumstances indicate that an asset's carrying amount may not be recoverable. In connection with the completion of the Merger, the application of the acquisition method of accounting was pushed down to Southern Company Gas. The excess of the purchase price over the fair values of Southern Company Gas' assets and liabilities was recorded as goodwill. This resulted in a significant increase in the goodwill recorded on Southern Company's and Southern Company Gas' consolidated balance sheets. At December 31, 2018, goodwill was $5.3 billion and $5.0 billion for Southern Company and Southern Company Gas, respectively.

In addition, Southern Company and its subsidiaries have long-lived assets recorded on their balance sheets. To the extent the value of goodwill or long-lived assets become impaired, the affected registrant may be required to incur impairment charges that could have a material impact on their results of operations. For example, a wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns where recent seismic mapping indicates that proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. Early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. In addition, a subsidiary of Southern Company has several leveraged lease agreements, with terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. With respect to Southern Company's subsidiary's investments in leveraged leases, the recovery of its investment is dependent on the profitable operation of the leased assets by the respective lessees. A significant deterioration in the performance of the leased asset could result in the impairment of the related lease receivable.


Item 1B.	UNRESOLVED STAFF COMMENTS.

None.

I-37

Table of Contents Index to Financial Statements

Item 2. PROPERTIES

Electric

Electric Properties

The traditional electric operating companies, Southern Power, and SEGCO, at January 1, 2019, owned and/or operated 33 hydroelectric generating stations, 26 fossil fuel generating stations, three nuclear generating stations, 13 combined cycle/cogeneration stations, 40 solar facilities, nine wind facilities, and one biomass facility. The amounts of capacity for each company, at January 1, 2019, are shown in the table below.



Generating Station	Location	Nameplate Capacity (1)
		(KWs)
FOSSIL STEAM
Gadsden	Gadsden, AL	120,000
Gorgas	Jasper, AL	1,021,250	(2	)
Barry	Mobile, AL	1,300,000
Greene County	Demopolis, AL	300,000	(3	)
Gaston Unit 5	Wilsonville, AL	880,000
Miller	Birmingham, AL	2,532,288	(4	)
Alabama Power Total		6,153,538
Bowen	Cartersville, GA	3,160,000
Hammond	Rome, GA	800,000	(5	)
McIntosh	Effingham County, GA	163,117	(5	)
Scherer	Macon, GA	750,924	(6	)
Wansley	Carrollton, GA	925,550	(7	)
Yates	Newnan, GA	700,000
Georgia Power Total		6,499,591
Daniel	Pascagoula, MS	500,000	(8	)
Greene County	Demopolis, AL	200,000	(3	)
Watson	Gulfport, MS	750,000
Mississippi Power Total		1,450,000
Gaston Units 1-4	Wilsonville, AL
SEGCO Total		1,000,000	(9	)
Total Fossil Steam		15,103,129
NUCLEAR STEAM
Farley	Dothan, AL
Alabama Power Total		1,720,000
Hatch	Baxley, GA	899,612	(10	)
Vogtle Units 1 and 2	Augusta, GA	1,060,240	(11	)
Georgia Power Total		1,959,852
Total Nuclear Steam		3,679,852

I-38

Table of Contents Index to Financial Statements



Generating Station	Location	Nameplate Capacity (1)
COMBUSTION TURBINES
Greene County	Demopolis, AL
Alabama Power Total		720,000
Boulevard	Savannah, GA	19,700
McDonough Unit 3	Atlanta, GA	78,800
McIntosh Units 1 through 8	Effingham County, GA	640,000
McManus	Brunswick, GA	481,700
Robins	Warner Robins, GA	158,400
Wansley	Carrollton, GA	26,322	(7	)
Wilson	Augusta, GA	354,100
Georgia Power Total		1,759,022
Chevron Cogenerating Station	Pascagoula, MS	147,292	(12	)
Sweatt	Meridian, MS	39,400
Watson	Gulfport, MS	39,360
Mississippi Power Total		226,052
Addison	Thomaston, GA	668,800
Cleveland County	Cleveland County, NC	720,000
Dahlberg	Jackson County, GA	756,000
Rowan	Salisbury, NC	455,250
Southern Power Total		2,600,050
Gaston (SEGCO)	Wilsonville, AL	19,680	(9	)
Total Combustion Turbines		5,324,804
COGENERATION
Washington County	Washington County, AL	123,428
Lowndes County	Burkeville, AL	104,800
Theodore	Theodore, AL	236,418
Alabama Power Total		464,646
COMBINED CYCLE
Barry	Mobile, AL
Alabama Power Total		1,070,424
McIntosh Units 10 and 11	Effingham County, GA	1,318,920
McDonough-Atkinson Units 4 through 6	Atlanta, GA	2,520,000
Georgia Power Total		3,838,920
Daniel	Pascagoula, MS	1,070,424
Ratcliffe	Kemper County, MS	769,898	(13)
Mississippi Power Total		1,840,322
Franklin	Smiths, AL	1,857,820
Harris	Autaugaville, AL	1,318,920
Mankato	Mankato, MN	375,000	(14)
Rowan	Salisbury, NC	530,550
Wansley Units 6 and 7	Carrollton, GA	1,073,000
Southern Power Total		5,155,290
Total Combined Cycle		11,904,956

I-39

Table of Contents Index to Financial Statements



Generating Station	Location	Nameplate Capacity (1)
HYDROELECTRIC FACILITIES
Bankhead	Holt, AL	53,985
Bouldin	Wetumpka, AL	225,000
Harris	Wedowee, AL	132,000
Henry	Ohatchee, AL	72,900
Holt	Holt, AL	46,944
Jordan	Wetumpka, AL	100,000
Lay	Clanton, AL	177,000
Lewis Smith	Jasper, AL	157,500
Logan Martin	Vincent, AL	135,000
Martin	Dadeville, AL	182,000
Mitchell	Verbena, AL	170,000
Thurlow	Tallassee, AL	81,000
Weiss	Leesburg, AL	87,750
Yates	Tallassee, AL	47,000
Alabama Power Total		1,668,079
Bartletts Ferry	Columbus, GA	173,000
Goat Rock	Columbus, GA	38,600
Lloyd Shoals	Jackson, GA	14,400
Morgan Falls	Atlanta, GA	16,800
North Highlands	Columbus, GA	29,600
Oliver Dam	Columbus, GA	60,000
Rocky Mountain	Rome, GA	215,256	(15	)
Sinclair Dam	Milledgeville, GA	45,000
Tallulah Falls	Clayton, GA	72,000
Terrora	Clayton, GA	16,000
Tugalo	Clayton, GA	45,000
Wallace Dam	Eatonton, GA	321,300
Yonah	Toccoa, GA	22,500
6 Other Plants	Various Georgia locations	18,080
Georgia Power Total		1,087,536
Total Hydroelectric Facilities		2,755,615

I-40

Table of Contents Index to Financial Statements



Generating Station	Location	Nameplate Capacity (1)
RENEWABLE SOURCES:
SOLAR FACILITIES
Fort Rucker	Calhoun County, AL	10,560
Anniston Army Depot	Dale County, AL	7,380
Alabama Power Total		17,940
Fort Benning	Columbus, GA	30,005
Fort Gordon	Augusta, GA	30,000
Fort Stewart	Fort Stewart, GA	30,000
Kings Bay	Camden County, GA	30,161
Dalton	Dalton, GA	6,508
Marine Corps Logistics Base	Albany, GA	31,161
4 Other Plants	Various Georgia locations	5,171
Georgia Power Total		163,006
Adobe	Kern County, CA	20,000
Apex	North Las Vegas, NV	20,000
Boulder I	Clark County, NV	100,000
Butler	Taylor County, GA	103,700
Butler Solar Farm	Taylor County, GA	22,000
Calipatria	Imperial County, CA	20,000
Campo Verde	Imperial County, CA	147,420
Cimarron	Springer, NM	30,640
Decatur County	Decatur County, GA	20,000
Decatur Parkway	Decatur County, GA	84,000
Desert Stateline	San Bernadino County, CA	299,900
East Pecos	Pecos County, TX	120,000
Garland	Kern County, CA	205,130
Gaskell West I	Kern County, CA	20,000
Granville	Oxford, NC	2,500
Henrietta	Kings County, CA	102,000
Imperial Valley	Imperial County, CA	163,200
Lamesa	Dawson County, TX	102,000
Lost Hills - Blackwell	Kern County, CA	33,440
Macho Springs	Luna County, NM	55,000
Morelos del Sol	Kern County, CA	15,000
North Star	Fresno County, CA	61,600
Pawpaw	Taylor County, GA	30,480
Roserock	Pecos County, TX	160,000
Rutherford	Rutherford County, NC	74,800
Sandhills	Taylor County, GA	146,890
Spectrum	Clark County, NV	30,240
Tranquillity	Fresno County, CA	205,300
Southern Power Total		2,395,240	(16	)
Total Solar		2,576,186

I-41

Table of Contents Index to Financial Statements



Generating Station	Location	Nameplate Capacity (1)
WIND FACILITIES
Bethel	Castro County, TX	276,000
Cactus Flats	Concho County, TX	148,350
Grant Plains	Grant County, OK	147,200
Grant Wind	Grant County, OK	151,800
Kay Wind	Kay County, OK	299,000
Passadumkeag	Penobscot County, ME	42,900
Salt Fork	Donley & Gray Counties TX	174,000
Tyler Bluff	Cooke County, TX	125,580
Wake Wind	Crosby & Floyd Counties, TX	257,250
Southern Power Total		1,622,080	(17)
BIOMASS FACILITY
Nacogdoches	Sacul, TX
Southern Power Total		115,500

Total Alabama Power Generating Capacity		11,814,627
Total Georgia Power Generating Capacity		15,307,927
Total Mississippi Power Generating Capacity		3,516,374
Total Southern Power Generating Capacity		11,888,160
Total Generating Capacity		43,546,768

Notes:



(1)	See "Jointly-Owned Facilities" herein and Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information.
(2)	As part of its environmental compliance strategy, Alabama Power plans to retire Plant Gorgas Units 8, 9, and 10 by April 15, 2019. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" in Item 8 herein for additional information.
(3)	Owned by Alabama Power and Mississippi Power as tenants in common in the proportions of 60% and 40%, respectively. Capacity shown for each company represents its portion of total plant capacity.
(4)	Capacity shown is Alabama Power's portion (95.92%) of total plant capacity.
(5)	Georgia Power has requested to decertify and retire Plant Hammond Units 1 through 4 and Plant McIntosh Unit 1 upon approval of its 2019 IRP filing. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plan" in Item 8 herein for additional information.
(6)	Capacity shown for Georgia Power is 8.4% of Units 1 and 2 and 75% of Unit 3.
(7)	Capacity shown is Georgia Power's portion (53.5%) of total plant capacity.
(8)	Capacity shown is Mississippi Power's portion (50%) of total plant capacity.
(9)	SEGCO is jointly-owned by Alabama Power and Georgia Power. See BUSINESS in Item 1 herein for additional information. Also see Note 7 to the financial statements under "SEGCO" in Item 8 herein.
(10)	Capacity shown is Georgia Power's portion (50.1%) of total plant capacity.
(11)	Capacity shown is Georgia Power's portion (45.7%) of total plant capacity.
(12)	Generation is dedicated to a single industrial customer. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" of Mississippi Power in Item 7 herein.
(13)	The capacity shown is the gross capacity using natural gas fuel without supplemental firing.
(14)	On November 5, 2018, Southern Power entered into an agreement with Northern States Power to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction). The ultimate outcome of this matter cannot be determined at this time. See Note 15 to the financial statements under "Southern Power – Sales of Natural Gas Plants" in Item 8 herein for additional information.
(15)	Capacity shown is Georgia Power's portion (25.4%) of total plant capacity. OPC operates the plant.
(16)	In May 2018, Southern Power sold a noncontrolling 33% equity interest in SP Solar (a limited partnership indirectly owning all of Southern Power's solar facilities, except the Roserock and Gaskell West facilities). SP Solar is the 51% majority owner of Boulder 1, Garland, Henrietta, Imperial Valley, Lost Hills Blackwell, North Star, and Tranquillity; the 66% majority owner of Desert Stateline; and the sole owner of the remaining SP Solar facilities. Southern Power is the 51% majority owner of Roserock and also the controlling partner in a tax equity partnership owning Gaskell West. All of these entities are consolidated subsidiaries of Southern Power and the capacity shown in the table is 100% of the nameplate capacity for the respective facility.
(17)	In December 2018, Southern Power sold a noncontrolling tax equity interest in SP Wind (which owns all of Southern Power's wind facilities, except Cactus Flats). SP Wind is the 90.1% majority owner of Wake Wind and owns 100% of the remaining SP Wind facilities. Southern Power is the controlling partner in a tax equity partnership owning Cactus Flats. All of these entities are consolidated subsidiaries of Southern Power and the capacity shown in the table is 100% of the nameplate capacity for the respective facility.

I-42

Table of Contents Index to Financial Statements

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

Mississippi Power owns a 79-mile length of 500-kilovolt transmission line which is leased to Entergy Gulf States Louisiana, LLC. The line extends from Plant Daniel to the Louisiana state line. Entergy Gulf States Louisiana, LLC is paying a use fee over a 40-year period through 2024 covering all expenses and the amortization of the original cost. At December 31, 2018, the unamortized portion was approximately $12 million.

Mississippi Power owns a lignite mine and equipment that were intended to provide fuel for the Kemper IGCC. Mississippi Power also has acquired mineral reserves located around the Kemper County energy facility. Liberty Fuels Company, LLC, the operator of the mine, has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018 and is expected to be substantially completed in 2020, with monitoring expected to continue through 2027. Mississippi Power is currently evaluating its options regarding the final disposition of the CO₂ pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. The ultimate outcome of these matters cannot be determined at this time. See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility – Lignite Mine and CO₂ Pipeline Facilities" in Item 8 herein for additional information on the lignite mine and CO₂ pipeline.

In August 2018, Mississippi Power filed a RMP which identified alternatives that, if implemented, could impact Mississippi Power's generating stations as well as Plant Greene County, jointly owned by Mississippi Power and Alabama Power. See BUSINESS in Item 1 herein under "Rate Matters – Integrated Resource Planning – Mississippi Power" for additional information.

In conjunction with Southern Company's sale of Gulf Power, Mississippi Power and Gulf Power have committed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On January 15, 2019, Gulf Power provided notice to Mississippi Power that Gulf Power will retire its share of the 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. The ultimate outcome of these matters remains subject to completion of Mississippi Power's evaluations and applicable regulatory approvals, including the FERC and the Mississippi PSC, and cannot now be determined. See Note 15 to the financial statements under "Southern Company's Sale of Gulf Power" in Item 8 herein for information regarding the sale of Gulf Power.

In 2018, the maximum demand on the traditional electric operating companies, Southern Power Company, and SEGCO was 36,429,000 KWs and occurred on January 18, 2018. The all-time maximum demand of 38,777,000 KWs on the traditional electric operating companies, Southern Power Company, and SEGCO occurred on August 22, 2007. These amounts exclude demand served by capacity retained by MEAG Power, OPC, and SEPA. The reserve margin for the traditional electric operating companies, Southern Power Company, and SEGCO in 2018 was 29.8%. See SELECTED FINANCIAL DATA in Item 6 herein for additional information.

Jointly-Owned Facilities

Alabama Power, Georgia Power, and Mississippi Power at January 1, 2019 had undivided interests in certain generating plants and other related facilities with non-affiliated parties. The percentages of ownership of the total plant or facility are as follows:



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

I-43

Table of Contents Index to Financial Statements

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

In addition, Georgia Power has commitments regarding a portion of a 5% interest in Plant Vogtle Units 1 and 2 owned by MEAG Power that are in effect until the later of 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 any capacity is available. The energy cost is a function of each unit's variable operating costs. Except for the portion of the capacity payments related to the Georgia PSC's disallowances of Plant Vogtle Units 1 and 2 costs, the cost of such capacity and energy is included in purchased power from non-affiliates in Georgia Power's statements of income in Item 8 herein. Also see Note 9 to the financial statements under "Fuel and Power Purchase Agreements" in Item 8 herein for additional information.

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

On December 4, 2018, Southern Power completed the sale of its 65% ownership interest in Plant Stanton Unit A, which Southern Power previously jointly-owned with OUC, FMPA, and KUA, to NextEra Energy. See Note 15 to the financial statements under "Southern Power – Sales of Natural Gas Plants" in Item 8 herein for additional information.

Titles to Property

The traditional electric operating companies', Southern Power's, and SEGCO's interests in the principal plants and other important units of the respective companies are owned in fee by such companies, subject to the following major encumbrances: (1) liens pursuant to the assumption of debt obligations by Mississippi Power in connection with the acquisition of Plant Daniel Units 3 and 4, (2) a leasehold interest granted by Mississippi Power's largest retail customer, Chevron Products Company (Chevron), at the Chevron refinery, on which five combustion turbines of Mississippi Power are located, (3) liens pursuant to the agreements entered into with Chevron in October 2017 on Mississippi Power's co-generation assets located at the Chevron refinery, (4) liens associated with Georgia Power's reimbursement obligations to the DOE under its loan guarantee, which are secured by a first priority lien on (a) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 and (b) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4, and (5) liens associated with two PPAs assumed as part of the acquisition of Plant Mankato in 2016 by Southern Power Company. See Note 5 to the financial statements under "Assets Subject to Lien," Note 8 to the financial statements under "Secured Debt" and "Long-term Debt – DOE Loan Guarantee Borrowings," and Note 15 to the financial statements under "Southern Power – Sales of Natural Gas Plants" in Item 8 herein for additional information. The traditional electric operating companies own the fee interests in certain of their principal plants as tenants in common. See "Jointly-Owned Facilities" herein and Note 5 to the financial statements under "Joint Ownership Agreements" in Item 8 herein for additional information. Properties such as electric transmission and distribution lines, steam heating mains, and gas pipelines are constructed principally on rights-of-way, which are maintained under franchise or are held by easement only. A substantial portion of lands submerged by reservoirs is held under flood right easements. In addition, certain of the renewable generating facilities occupy or use real property that is not owned, primarily through various leases, easements, rights-of-way, permits, or licenses from private landowners or governmental entities.

Natural Gas

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

Distribution and Transmission Mains – Southern Company Gas' distribution systems transport natural gas from its pipeline suppliers to customers in its service areas. These systems consist primarily of distribution and transmission mains, compressor stations, peak shaving/storage plants, service lines, meters, and regulators. At December 31, 2018, Southern Company Gas' gas distribution operations segment owned approximately 75,200 miles of underground distribution and transmission mains, which are located on easements or rights-of-way that generally provide for perpetual use.

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

I-44

Table of Contents Index to Financial Statements

Southern Company Gas also has four LNG plants located in Georgia and Tennessee with total LNG storage capacity of approximately 7.4 Bcf. In addition, Southern Company Gas owns two propane storage facilities in Virginia, each with storage capacity of approximately 0.3 Bcf. The LNG plants and propane storage facility are used by Southern Company Gas' gas distribution operations segment to supplement natural gas supply during peak usage periods.

Storage Assets – All Other – Southern Company Gas subsidiaries own three high-deliverability natural gas storage and hub facilities that are included in the all other segment. Jefferson Island Storage & Hub, LLC operates a storage facility in Louisiana consisting of two salt dome gas storage caverns. Golden Triangle Storage, Inc. operates a storage facility in Texas consisting of two salt dome caverns. Central Valley Gas Storage, LLC operates a depleted field storage facility in California. In addition, Southern Company Gas has a LNG facility in Alabama that produces LNG for Pivotal LNG, Inc. to support its business of selling LNG as a substitute fuel in various markets.

In August 2017, in connection with an ongoing integrity project into the salt dome gas storage caverns in Louisiana, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. See FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company Gas in Item 7 herein and Note 3 to the financial statements under "Other Matters – Southern Company Gas" in Item 8 herein for additional information.

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

Southern Company Gas owns a 50% interest in a LNG liquefaction and storage facility in Jacksonville, Florida, which was placed in service in October 2018 and is included in the all other segment. The facility is outfitted with a 2.0 million gallon storage tank with the capacity to produce in excess of 120,000 gallons of LNG per day.

I-45

Table of Contents Index to Financial Statements


Item 3.	LEGAL PROCEEDINGS

See Note 3 to the financial statements in Item 8 herein for descriptions of legal and administrative proceedings discussed therein.


Item 4.	MINE SAFETY DISCLOSURES

Not applicable.

I-46

Table of Contents Index to Financial Statements

EXECUTIVE OFFICERS OF SOUTHERN COMPANY

(Identification of executive officers of Southern Company is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2018.

Thomas A. Fanning

Chairman, President, and Chief Executive Officer

Age 61

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

Andrew W. Evans

Executive Vice President and Chief Financial Officer

Age 52

First elected in 2016. Executive Vice President since July 2016 and Chief Financial Officer since June 2018. Previously served as Chief Executive Officer and Chairman of Southern Company Gas' Board of Directors from January 2016 through June 2018, President of Southern Company Gas from May 2015 through June 2018, Chief Operating Officer of Southern Company Gas from May 2015 through December 2015, and Executive Vice President and Chief Financial Officer of Southern Company Gas from May 2006 through May 2015.

W. Paul Bowers

Chairman, President and Chief Executive Officer of Georgia Power

Age 62

First elected in 2001. Chief Executive Officer, President, and Director of Georgia Power since January 2011. Chairman of Georgia Power's Board of Directors since May 2014.

S. W. Connally, Jr.

Executive Vice President of SCS

Age 49

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

Mark A. Crosswhite

Chairman, President and Chief Executive Officer of Alabama Power

Age 56

First elected in 2010. President, Chief Executive Officer, and Director of Alabama Power since March 2014. Chairman of Alabama Power's Board of Directors since May 2014. Previously served as Executive Vice President and Chief Operating Officer of Southern Company from July 2012 through February 2014.

Kimberly S. Greene

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

Age 52

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

James Y. Kerr II

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

Age 54

First elected in 2014. Executive Vice President, Chief Legal Officer (formerly known as General Counsel), and Chief Compliance Officer since March 2014. Before joining Southern Company, Mr. Kerr was a partner with McGuireWoods LLP and a senior advisor at McGuireWoods Consulting LLC from 2008 through February 2014.

Stephen E. Kuczynski

Chairman, President, and Chief Executive Officer of Southern Nuclear

Age 56

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

I-47

Table of Contents Index to Financial Statements

Mark S. Lantrip

Executive Vice President

Age 64

First elected in 2014. Executive Vice President since February 2019. Chairman, President, and Chief Executive Officer of SCS since March 2014 and Chairman, President, and Chief Executive Officer of Southern Power since March 2018. Previously served as Treasurer of Southern Company from October 2007 to February 2014 and Executive Vice President of SCS from November 2010 to March 2014.

Anthony L. Wilson

Chairman, President, and Chief Executive Officer of Mississippi Power

Age 54

First elected in 2015. President of Mississippi Power since October 2015 and Chief Executive Officer and Director since January 2016. Chairman of Mississippi Power's Board of Directors since August 2016. Previously served as Executive Vice President of Mississippi Power from May 2015 to October 2015 and Executive Vice President of Georgia Power from January 2012 to May 2015.

Christopher C. Womack

Executive Vice President

Age 60

First elected in 2008. Executive Vice President and President of External Affairs since January 2009.

The officers of Southern Company were elected at the first meeting of the directors following the last annual meeting of stockholders held on May 23, 2018, for a term of one year or until their successors are elected and have qualified, except for Mr. Lantrip, whose election as Executive Vice President was effective February 11, 2019.

I-48

Table of Contents Index to Financial Statements

EXECUTIVE OFFICERS OF ALABAMA POWER

(Identification of executive officers of Alabama Power is inserted in Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages of the officers set forth below are as of December 31, 2018.

Mark A. Crosswhite

Chairman, President, and Chief Executive Officer

Age 56

First elected in 2014. President, Chief Executive Officer, and Director since March 1, 2014. Chairman since May 2014. Previously served as Executive Vice President and Chief Operating Officer of Southern Company from July 2012 through February 2014.

Greg J. Barker

Executive Vice President

Age 55

First elected in 2016. Executive Vice President for Customer Services since February 2016. Previously served as Senior Vice President of Marketing and Economic Development from April 2012 to February 2016.

Philip C. Raymond

Executive Vice President, Chief Financial Officer, and Treasurer

Age 59

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

Zeke W. Smith

Executive Vice President

Age 59

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

James P. Heilbron

Senior Vice President and Senior Production Officer

Age 47

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

R. Scott Moore

Senior Vice President

Age 51

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

The officers of Alabama Power were elected at the meeting of the directors held on April 27, 2018 for a term of one year or until their successors are elected and have qualified.

I-49

Table of Contents Index to Financial Statements

PART II


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

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

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

(a)(2) Number of Southern Company's common stockholders of record at January 31, 2019: 115,847

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

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

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

(b) Use of Proceeds

Not applicable.

None.

II-1

Table of Contents Index to Financial Statements


Item 6.	SELECTED FINANCIAL DATA



	Page
Southern Company	II-3
Alabama Power	II-6
Georgia Power	II-8
Mississippi Power	II-10
Southern Power	II-12
Southern Company Gas	II-13

II-2

Table of Contents Index to Financial Statements

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 2014-2018

Southern Company and Subsidiary Companies 2018 Annual Report



	2018		2017		2016^(d)		2015		2014
Operating Revenues (in millions)	$	23,495	$	23,031	$	19,896	$	17,489	$	18,467
Total Assets (in millions)^(a)	$	116,914	$	111,005	$	109,697	$	78,318	$	70,233
Gross Property Additions (in millions)	$	8,205	$	5,984	$	7,624	$	6,169	$	6,522
Return on Average Common Equity (percent)^(b)	9.11		3.44		10.80		11.68		10.08
Cash Dividends Paid Per Share of Common Stock	$	2.3800	$	2.3000	$	2.2225	$	2.1525	$	2.0825
Consolidated Net Income Attributable to Southern Company (in millions)^(b)	$	2,226	$	842	$	2,448	$	2,367	$	1,963
Earnings Per Share —
Basic	$	2.18	$	0.84	$	2.57	$	2.60	$	2.19
Diluted	2.17		0.84		2.55		2.59		2.18
Capitalization (in millions):
Common stockholders' equity	$	24,723	$	24,167	$	24,758	$	20,592	$	19,949
Preferred and preference stock of subsidiaries and noncontrolling interests	4,316		1,361		1,854		1,390		977
Redeemable preferred stock of subsidiaries	291		324		118		118		375
Redeemable noncontrolling interests	—		—		164		43		39
Long-term debt^(a)(c)	40,736		44,462		42,629		24,688		20,644
Total (excluding amounts due within one year)^(c)	$	70,066	$	70,314	$	69,523	$	46,831	$	41,984
Capitalization Ratios (percent):
Common stockholders' equity	35.3		34.4		35.6		44.0		47.5
Preferred and preference stock of subsidiaries and noncontrolling interests	6.2		1.9		2.7		3.0		2.3
Redeemable preferred stock of subsidiaries	0.4		0.5		0.2		0.3		0.9
Redeemable noncontrolling interests	—		—		0.2		0.1		0.1
Long-term debt^(a)(c)	58.1		63.2		61.3		52.6		49.2
Total (excluding amounts due within one year)^(c)	100.0		100.0		100.0		100.0		100.0
Other Common Stock Data:
Book value per share	$	23.91	$	23.99	$	25.00	$	22.59	$	21.98
Market price per share:
High	$	49.43	$	53.51	$	54.64	$	53.16	$	51.28
Low	42.38		46.71		46.00		41.40		40.27
Close (year-end)	43.92		48.09		49.19		46.79		49.11
Market-to-book ratio (year-end) (percent)	183.7		200.5		196.8		207.2		223.4
Price-earnings ratio (year-end) (times)	20.1		57.3		19.1		18.0		22.4
Dividends paid (in millions)	$	2,425	$	2,300	$	2,104	$	1,959	$	1,866
Dividend yield (year-end) (percent)	5.4		4.8		4.5		4.6		4.2
Dividend payout ratio (percent)	108.9		273.2		86.0		82.7		95.0
Shares outstanding (in thousands):
Average	1,020,247		1,000,336		951,332		910,024		897,194
Year-end	1,033,788		1,007,603		990,394		911,721		907,777
Stockholders of record (year-end)	116,135		120,803		126,338		131,771		137,369



(a)	A reclassification of debt issuance costs from Total Assets to Long-term debt of $202 million and a reclassification of deferred tax assets from Total Assets to Accumulated deferred income taxes of $488 million is reflected for 2014, in accordance with new accounting standards adopted in 2015 and applied retrospectively.
(b)	Georgia Power recorded a pre-tax estimated probable loss of $1.1 billion ($0.8 billion after tax) in the second quarter 2018 to reflect its revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4. In addition, a significant loss to income was recorded by Mississippi Power related to the suspension of the Kemper IGCC in June 2017. Earnings in all periods presented were impacted by losses related to the Kemper IGCC. See Note 2 to the financial statements in Item 8 herein for additional information.
(c)	Amounts related to Gulf Power have been reclassified to liabilities held for sale at December 31, 2018. See Note 15 to the financial statements under "Southern Company's Sale of Gulf Power" in Item 8 herein for additional information.
(d)	The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 15 to the financial statements under "Southern Company Merger with Southern Company Gas" in Item 8 herein for additional information.

II-3

Table of Contents Index to Financial Statements

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 2014-2018 (continued)

Southern Company and Subsidiary Companies 2018 Annual Report



	2018		2017		2016^(a)		2015		2014
Operating Revenues (in millions):
Residential	$	6,608	$	6,515	$	6,614	$	6,383	$	6,499
Commercial	5,266		5,439		5,394		5,317		5,469
Industrial	3,224		3,262		3,171		3,172		3,449
Other	124		114		55		115		133
Total retail	15,222		15,330		15,234		14,987		15,550
Wholesale	2,516		2,426		1,926		1,798		2,184
Total revenues from sales of electricity	17,738		17,756		17,160		16,785		17,734
Natural gas revenues	3,854		3,791		1,596		—		—
Other revenues	1,903		1,484		1,140		704		733
Total	$	23,495	$	23,031	$	19,896	$	17,489	$	18,467
Kilowatt-Hour Sales (in millions):
Residential	54,590		50,536		53,337		52,121		53,347
Commercial	53,451		52,340		53,733		53,525		53,243
Industrial	53,341		52,785		52,792		53,941		54,140
Other	799		846		883		897		909
Total retail	162,181		156,507		160,745		160,484		161,639
Wholesale sales	49,963		49,034		37,043		30,505		32,786
Total	212,144		205,541		197,788		190,989		194,425
Average Revenue Per Kilowatt-Hour (cents):
Residential	12.10		12.89		12.40		12.25		12.18
Commercial	9.85		10.39		10.04		9.93		10.27
Industrial	6.04		6.18		6.01		5.88		6.37
Total retail	9.39		9.80		9.48		9.34		9.62
Wholesale	5.04		4.95		5.20		5.89		6.66
Total sales	8.36		8.64		8.68		8.79		9.12
Average Annual Kilowatt-Hour
Use Per Residential Customer	12,514		11,618		12,387		13,318		13,765
Average Annual Revenue
Per Residential Customer	$	1,555	$	1,498	$	1,541	$	1,630	$	1,679
Plant Nameplate Capacity
Ratings (year-end) (megawatts)	45,824		46,936		46,291		44,223		46,549
Maximum Peak-Hour Demand (megawatts):
Winter	36,429		31,956		32,272		36,794		37,234
Summer	34,841		34,874		35,781		36,195		35,396
System Reserve Margin (at peak) (percent)	29.8		30.8		34.2		33.2		19.8
Annual Load Factor (percent)	61.2		61.4		61.5		59.9		59.6
Plant Availability (percent):
Fossil-steam	81.4		84.5		86.4		86.1		85.8
Nuclear	94.0		94.7		93.3		93.5		91.5



(a)	The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 15 to the financial statements under "Southern Company Merger with Southern Company Gas" in Item 8 herein for additional information.

II-4

Table of Contents Index to Financial Statements

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 2014-2018 (continued)

Southern Company and Subsidiary Companies 2018 Annual Report



	2018	2017	2016^(a)	2015	2014
Source of Energy Supply (percent):
Gas	41.6	41.9	41.7	42.7	37.0
Coal	27.0	27.0	30.3	32.3	39.3
Nuclear	13.8	14.5	14.5	15.2	14.8
Hydro	2.9	2.1	2.1	2.6	2.5
Other	5.4	5.4	2.4	0.8	0.4
Purchased power	9.3	9.1	9.0	6.4	6.0
Total	100.0	100.0	100.0	100.0	100.0
Gas Sales Volumes (mmBtu in millions):
Firm	791	729	296	—	—
Interruptible	109	109	53	—	—
Total	900	838	349	—	—
Traditional Electric Operating Company Customers (year-end) (in thousands):
Residential	4,053	4,011	3,970	3,928	3,890
Commercial^(b)	603	599	595	590	586
Industrial^(b)	17	18	17	17	17
Other	12	12	11	11	11
Total electric customers	4,685	4,640	4,593	4,546	4,504
Gas distribution operations customers	4,248	4,623	4,586	—	—
Total utility customers	8,933	9,263	9,179	4,546	4,504
Employees (year-end)	30,286	31,344	32,015	26,703	26,369



(a)	The 2016 selected financial and operating data includes the operations of Southern Company Gas from the date of the Merger, July 1, 2016, through December 31, 2016. See Note 15 to the financial statements under "Southern Company Merger with Southern Company Gas" in Item 8 herein for additional information.
(b)	A reclassification of customers from commercial to industrial is reflected for years 2014-2015 to be consistent with the rate structure approved by the Georgia PSC. The impact to operating revenues, kilowatt-hour sales, and average revenue per kilowatt-hour by class is not material.

II-5

Table of Contents Index to Financial Statements

SELECTED FINANCIAL AND OPERATING DATA 2014-2018

Alabama Power Company 2018 Annual Report



	2018		2017		2016		2015		2014
Operating Revenues (in millions)	$	6,032	$	6,039	$	5,889	$	5,768	$	5,942
Net Income After Dividends on Preferred and Preference Stock (in millions)	$	930	$	848	$	822	$	785	$	761
Cash Dividends on Common Stock (in millions)	$	801	$	714	$	765	$	571	$	550
Return on Average Common Equity (percent)	13.00		12.89		13.34		13.37		13.52
Total Assets (in millions)^(*)	$	26,730	$	23,864	$	22,516	$	21,721	$	20,493
Gross Property Additions (in millions)	$	2,273	$	1,949	$	1,338	$	1,492	$	1,543
Capitalization (in millions):
Common stockholder's equity	$	7,477	$	6,829	$	6,323	$	5,992	$	5,752
Preference stock	—		—		196		196		343
Redeemable preferred stock	291		291		85		85		342
Long-term debt^(*)	7,923		7,628		6,535		6,654		6,137
Total (excluding amounts due within one year)	$	15,691	$	14,748	$	13,139	$	12,927	$	12,574
Capitalization Ratios (percent):
Common stockholder's equity	47.7		46.3		48.1		46.4		45.8
Preference stock	—		—		1.5		1.5		2.7
Redeemable preferred stock	1.9		2.0		0.7		0.7		2.7
Long-term debt^(*)	50.4		51.7		49.7		51.4		48.8
Total (excluding amounts due within one year)	100.0		100.0		100.0		100.0		100.0
Customers (year-end):
Residential	1,273,526		1,268,271		1,262,752		1,253,875		1,247,061
Commercial	200,032		199,840		199,146		197,920		197,082
Industrial	6,158		6,171		6,090		6,056		6,032
Other	760		766		762		757		753
Total	1,480,476		1,475,048		1,468,750		1,458,608		1,450,928
Employees (year-end)	6,650		6,613		6,805		6,986		6,935



(*)	A reclassification of debt issuance costs from Total Assets to Long-term debt of $40 million and a reclassification of deferred tax assets from Total Assets to Accumulated deferred income taxes of $20 million is reflected for 2014, in accordance with new accounting standards adopted in 2015 and applied retrospectively.

II-6

Table of Contents Index to Financial Statements

SELECTED FINANCIAL AND OPERATING DATA 2014-2018 (continued)

Alabama Power Company 2018 Annual Report



	2018		2017		2016			2015		2014
Operating Revenues (in millions):
Residential	$	2,335	$	2,302	$	2,322		$	2,207	$	2,209
Commercial	1,578		1,649		1,627			1,564		1,533
Industrial	1,428		1,477		1,416			1,436		1,480
Other	26		30		(43		)	27		27
Total retail	5,367		5,458		5,322			5,234		5,249
Wholesale — non-affiliates	279		276		283			241		281
Wholesale — affiliates	119		97		69			84		189
Total revenues from sales of electricity	5,765		5,831		5,674			5,559		5,719
Other revenues	267		208		215			209		223
Total	$	6,032	$	6,039	$	5,889		$	5,768	$	5,942
Kilowatt-Hour Sales (in millions):
Residential	18,626		17,219		18,343			18,082		18,726
Commercial	13,868		13,606		14,091			14,102		14,118
Industrial	23,006		22,687		22,310			23,380		23,799
Other	187		198		208			201		211
Total retail	55,687		53,710		54,952			55,765		56,854
Wholesale — non-affiliates	5,018		5,415		5,744			3,567		3,588
Wholesale — affiliates	4,565		4,166		3,177			4,515		6,713
Total	65,270		63,291		63,873			63,847		67,155
Average Revenue Per Kilowatt-Hour (cents):
Residential	12.54		13.37		12.66			12.21		11.80
Commercial	11.38		12.12		11.55			11.09		10.86
Industrial	6.21		6.51		6.35			6.14		6.22
Total retail	9.64		10.16		9.68			9.39		9.23
Wholesale	4.15		3.89		3.95			4.02		4.56
Total sales	8.83		9.21		8.88			8.71		8.52
Residential Average Annual Kilowatt-Hour Use Per Customer	14,660		13,601		14,568			14,454		15,051
Residential Average Annual Revenue Per Customer	$	1,878	$	1,819	$	1,844		$	1,764	$	1,775
Plant Nameplate Capacity Ratings (year-end) (megawatts)	11,815		11,797		11,797			11,797		12,222
Maximum Peak-Hour Demand (megawatts):
Winter	11,744		10,513		10,282			12,162		11,761
Summer	10,652		10,711		10,932			11,292		11,054
Annual Load Factor (percent)	60.1		63.5		63.5			58.4		61.4
Plant Availability (percent):
Fossil-steam	81.6		82.8		83.0			81.5		82.5
Nuclear	91.6		97.6		88.0			92.1		93.3
Source of Energy Supply (percent):
Coal	43.8		44.8		47.1			49.1		49.0
Nuclear	20.5		22.2		20.3			21.3		20.7
Gas	17.2		18.1		17.1			14.6		15.4
Hydro	6.7		5.4		4.8			5.6		5.5
Purchased power —
From non-affiliates	5.4		4.6		4.8			4.4		3.6
From affiliates	6.4		4.9		5.9			5.0		5.8
Total	100.0		100.0		100.0			100.0		100.0

II-7

Table of Contents Index to Financial Statements

SELECTED FINANCIAL AND OPERATING DATA 2014-2018

Georgia Power Company 2018 Annual Report



	2018		2017		2016		2015		2014
Operating Revenues (in millions)	$	8,420	$	8,310	$	8,383	$	8,326	$	8,988
Net Income After Dividends on Preferred and Preference Stock (in millions)^(a)	$	793	$	1,414	$	1,330	$	1,260	$	1,225
Cash Dividends on Common Stock (in millions)	$	1,396	$	1,281	$	1,305	$	1,034	$	954
Return on Average Common Equity (percent)	6.04		12.15		12.05		11.92		12.24
Total Assets (in millions)^(b)	$	40,365	$	36,779	$	34,835	$	32,865	$	30,872
Gross Property Additions (in millions)	$	3,176	$	1,080	$	2,314	$	2,332	$	2,146
Capitalization (in millions):
Common stockholder's equity	$	14,323	$	11,931	$	11,356	$	10,719	$	10,421
Preferred and preference stock	—		—		266		266		266
Long-term debt^(b)	9,364		11,073		10,225		9,616		8,563
Total (excluding amounts due within one year)	$	23,687	$	23,004	$	21,847	$	20,601	$	19,250
Capitalization Ratios (percent):
Common stockholder's equity	60.5		51.9		52.0		52.0		54.1
Preferred and preference stock	—		—		1.2		1.3		1.4
Long-term debt^(b)	39.5		48.1		46.8		46.7		44.5
Total (excluding amounts due within one year)	100.0		100.0		100.0		100.0		100.0
Customers (year-end):
Residential	2,220,240		2,185,782		2,155,945		2,127,658		2,102,673
Commercial^(c)	312,474		308,939		305,488		302,891		300,186
Industrial^(c)	10,571		10,644		10,537		10,429		10,192
Other	9,838		9,766		9,585		9,261		9,003
Total	2,553,123		2,515,131		2,481,555		2,450,239		2,422,054
Employees (year-end)	6,967		6,986		7,527		7,989		7,909



(a)	Georgia Power recorded a pre-tax estimated probable loss of $1.1 billion ($0.8 billion after tax) in the second quarter 2018 to reflect its revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4.
(b)	A reclassification of debt issuance costs from Total Assets to Long-term debt of $124 million and a reclassification of deferred tax assets from Total Assets to Accumulated deferred income taxes of $34 million is reflected for 2014, in accordance with new accounting standards adopted in 2015 and applied retrospectively.
(c)	A reclassification of customers from commercial to industrial is reflected for years 2014-2015 to be consistent with the rate structure approved by the Georgia PSC. The impact to operating revenues, kilowatt-hour sales, and average revenue per kilowatt-hour by class is not material.

II-8

Table of Contents Index to Financial Statements

SELECTED FINANCIAL AND OPERATING DATA 2014-2018 (continued)

Georgia Power Company 2018 Annual Report



	2018		2017		2016		2015		2014
Operating Revenues (in millions):
Residential	$	3,301	$	3,236	$	3,318	$	3,240	$	3,350
Commercial	3,023		3,092		3,077		3,094		3,271
Industrial	1,344		1,321		1,291		1,305		1,525
Other	84		89		86		88		94
Total retail	7,752		7,738		7,772		7,727		8,240
Wholesale — non-affiliates	163		163		175		215		335
Wholesale — affiliates	24		26		42		20		42
Total revenues from sales of electricity	7,939		7,927		7,989		7,962		8,617
Other revenues	481		383		394		364		371
Total	$	8,420	$	8,310	$	8,383	$	8,326	$	8,988
Kilowatt-Hour Sales (in millions):
Residential	28,331		26,144		27,585		26,649		27,132
Commercial	32,958		32,155		32,932		32,719		32,426
Industrial	23,655		23,518		23,746		23,805		23,549
Other	549		584		610		632		633
Total retail	85,493		82,401		84,873		83,805		83,740
Wholesale — non-affiliates	3,140		3,277		3,415		3,501		4,323
Wholesale — affiliates	526		800		1,398		552		1,117
Total	89,159		86,478		89,686		87,858		89,180
Average Revenue Per Kilowatt-Hour (cents):
Residential	11.65		12.38		12.03		12.16		12.35
Commercial	9.17		9.62		9.34		9.46		10.09
Industrial	5.68		5.62		5.44		5.48		6.48
Total retail	9.07		9.39		9.16		9.22		9.84
Wholesale	5.10		4.64		4.51		5.80		6.93
Total sales	8.90		9.17		8.91		9.06		9.66
Residential Average Annual Kilowatt-Hour Use Per Customer	12,849		12,028		12,864		12,582		12,969
Residential Average Annual Revenue Per Customer	$	1,555	$	1,489	$	1,557	$	1,529	$	1,605
Plant Nameplate Capacity Ratings (year-end) (megawatts)	15,308		15,274		15,274		15,455		17,593
Maximum Peak-Hour Demand (megawatts):
Winter	15,372		13,894		14,527		15,735		16,308
Summer	15,748		16,002		16,244		16,104		15,777
Annual Load Factor (percent)	64.5		61.1		61.9		61.9		61.2
Plant Availability (percent):
Fossil-steam	81.5		85.0		87.4		85.6		86.3
Nuclear	95.0		93.5		95.6		94.1		90.8
Source of Energy Supply (percent):
Gas	29.1		28.6		28.2		28.3		26.3
Coal	21.1		22.4		26.4		24.5		30.9
Nuclear	17.6		17.8		17.6		17.6		16.7
Hydro	1.9		1.0		1.1		1.6		1.3
Other	0.3		0.3		—		—		—
Purchased power —
From non-affiliates	7.3		7.8		6.7		5.0		3.8
From affiliates	22.7		22.1		20.0		23.0		21.0
Total	100.0		100.0		100.0		100.0		100.0

II-9

Table of Contents Index to Financial Statements

SELECTED FINANCIAL AND OPERATING DATA 2014-2018

Mississippi Power Company 2018 Annual Report



	2018		2017			2016			2015			2014
Operating Revenues (in millions)	$	1,265	$	1,187		$	1,163		$	1,138		$	1,243
Net Income (Loss) After Dividends on Preferred Stock (in millions)^(a)(b)	$	235	$	(2,590	)	$	(50	)	$	(8	)	$	(329	)
Return on Average Common Equity (percent)^(a)(b)	15.83		(120.43		)	(1.87		)	(0.34		)	(15.43		)
Total Assets (in millions)^(c)	$	4,886	$	4,866		$	8,235		$	7,840		$	6,642
Gross Property Additions (in millions)	$	206	$	536		$	946		$	972		$	1,389
Capitalization (in millions):
Common stockholder's equity	$	1,609	$	1,358		$	2,943		$	2,359		$	2,084
Redeemable preferred stock	—		33			33			33			33
Long-term debt^(c)	1,539		1,097			2,424			1,886			1,621
Total (excluding amounts due within one year)	$	3,148	$	2,488		$	5,400		$	4,278		$	3,738
Capitalization Ratios (percent):
Common stockholder's equity	51.1		54.6			54.5			55.1			55.8
Redeemable preferred stock	—		1.3			0.6			0.8			0.9
Long-term debt^(c)	48.9		44.1			44.9			44.1			43.3
Total (excluding amounts due within one year)	100.0		100.0			100.0			100.0			100.0
Customers (year-end):
Residential	153,423		153,115			153,172			153,158			152,453
Commercial	33,968		33,992			33,783			33,663			33,496
Industrial	445		452			451			467			482
Other	188		173			175			175			175
Total	188,024		187,732			187,581			187,463			186,606
Employees (year-end)	1,053		1,242			1,484			1,478			1,478



(a)	As a result of the Tax Reform Legislation, Mississippi Power recorded an income tax expense (benefit) of $(35) million and $372 million in 2018 and 2017, respectively.
(b)	A significant loss to income was recorded by Mississippi Power related to the suspension of the Kemper IGCC in June 2017. Earnings in all periods presented were impacted by losses related to the Kemper IGCC.
(c)	A reclassification of debt issuance costs from Total Assets to Long-term debt of $9 million and a reclassification of deferred tax assets from Total Assets to Accumulated deferred income taxes of $105 million is reflected for 2014, in accordance with new accounting standards adopted in 2015 and applied retrospectively.

II-10

Table of Contents Index to Financial Statements

SELECTED FINANCIAL AND OPERATING DATA 2014-2018 (continued)

Mississippi Power Company 2018 Annual Report



	2018		2017			2016			2015			2014
Operating Revenues (in millions):
Residential	$	273	$	257		$	260		$	238		$	239
Commercial	286		285			279			256			257
Industrial	321		321			313			287			291
Other	9		(9		)	7			(5		)	8
Total retail	889		854			859			776			795
Wholesale — non-affiliates	263		259			261			270			323
Wholesale — affiliates	91		56			26			76			107
Total revenues from sales of electricity	1,243		1,169			1,146			1,122			1,225
Other revenues	22		18			17			16			18
Total	$	1,265	$	1,187		$	1,163		$	1,138		$	1,243
Kilowatt-Hour Sales (in millions):
Residential	2,113		1,944			2,051			2,025			2,126
Commercial	2,797		2,764			2,842			2,806			2,860
Industrial	4,924		4,841			4,906			4,958			4,943
Other	37		39			39			40			40
Total retail	9,871		9,588			9,838			9,829			9,969
Wholesale — non-affiliates	3,980		3,672			3,920			3,852			4,191
Wholesale — affiliates	2,584		2,024			1,108			2,807			2,900
Total	16,435		15,284			14,866			16,488			17,060
Average Revenue Per Kilowatt-Hour (cents):
Residential	12.92		13.22			12.68			11.75			11.26
Commercial	10.23		10.31			9.82			9.12			8.99
Industrial	6.52		6.63			6.38			5.79			5.89
Total retail	9.01		8.91			8.73			7.90			7.97
Wholesale	5.39		5.53			5.71			5.20			6.06
Total sales	7.56		7.65			7.71			6.80			7.18
Residential Average Annual Kilowatt-Hour Use Per Customer	13,768		12,692			13,383			13,242			13,934
Residential Average Annual Revenue Per Customer	$	1,780	$	1,680		$	1,697		$	1,556		$	1,568
Plant Nameplate Capacity Ratings (year-end) (megawatts)	3,516		3,628			3,481			3,561			3,867
Maximum Peak-Hour Demand (megawatts):
Winter	2,763		2,390			2,195			2,548			2,618
Summer	2,346		2,322			2,384			2,403			2,345
Annual Load Factor (percent)	55.8		63.1			64.0			60.6			59.4
Plant Availability Fossil-Steam (percent)	82.4		89.1			91.4			90.6			87.6
Source of Energy Supply (percent):
Gas	86.1		88.0			84.9			81.6			55.3
Coal	6.9		7.5			8.0			16.5			39.7
Purchased power —
From non-affiliates	4.7		0.5			(0.3		)	0.4			1.4
From affiliates	2.3		4.0			7.4			1.5			3.6
Total	100.0		100.0			100.0			100.0			100.0

II-11

Table of Contents Index to Financial Statements

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 2014-2018

Southern Power Company and Subsidiary Companies 2018 Annual Report



	2018		2017		2016		2015		2014
Operating Revenues (in millions):
Wholesale — non-affiliates	$	1,757	$	1,671	$	1,146	$	964	$	1,116
Wholesale — affiliates	435		392		419		417		383
Total revenues from sales of electricity	2,192		2,063		1,565		1,381		1,499
Other revenues	13		12		12		9		2
Total	$	2,205	$	2,075	$	1,577	$	1,390	$	1,501
Net Income Attributable to Southern Power (in millions)^(a)	$	187	$	1,071	$	338	$	215	$	172
Cash Dividends on Common Stock (in millions)	$	312	$	317	$	272	$	131	$	131
Return on Average Common Equity (percent)^(a)	4.62		22.39		9.79		10.16		10.39
Total Assets (in millions)^(b)	$	14,883	$	15,206	$	15,169	$	8,905	$	5,233
Property, Plant, and Equipment — In Service (in millions)	$	13,271	$	13,755	$	12,728	$	7,275	$	5,657
Capitalization (in millions):
Common stockholders' equity	$	2,968	$	5,138	$	4,430	$	2,483	$	1,752
Noncontrolling interests	4,316		1,360		1,245		781		219
Redeemable noncontrolling interests	—		—		164		43		39
Long-term debt^(b)	4,418		5,071		5,068		2,719		1,085
Total (excluding amounts due within one year)	$	11,702	$	11,569	$	10,907	$	6,026	$	3,095
Capitalization Ratios (percent):
Common stockholders' equity	25.4		44.4		40.6		41.2		56.6
Noncontrolling interests	36.9		11.8		11.4		13.0		7.1
Redeemable noncontrolling interests	—		—		1.5		0.7		1.3
Long-term debt^(b)	37.7		43.8		46.5		45.1		35.0
Total (excluding amounts due within one year)	100.0		100.0		100.0		100.0		100.0
Kilowatt-Hour Sales (in millions):
Wholesale — non-affiliates	37,164		35,920		23,213		18,544		19,014
Wholesale — affiliates	12,603		12,811		15,950		16,567		11,194
Total	49,767		48,731		39,163		35,111		30,208
Plant Nameplate Capacity Ratings (year-end) (megawatts)	11,888		12,940		12,442		9,808		9,185
Maximum Peak-Hour Demand (megawatts):
Winter	2,867		3,421		3,469		3,923		3,999
Summer	4,210		4,224		4,303		4,249		3,998
Annual Load Factor (percent)	52.2		49.1		50.0		49.0		51.8
Plant Availability (percent)	99.9		99.9		91.6		93.1		91.8
Source of Energy Supply (percent):
Natural gas	68.1		67.7		79.4		89.5		86.0
Solar, Wind, and Biomass	23.6		22.8		12.1		4.3		2.9
Purchased power —
From non-affiliates	6.6		7.8		6.8		4.7		6.4
From affiliates	1.7		1.7		1.7		1.5		4.7
Total	100.0		100.0		100.0		100.0		100.0
Employees (year-end)^(c)	491		541		—		—		—



(a)	As a result of the Tax Reform Legislation, Southern Power recorded an income tax expense (benefit) of $79 million and $(743) million in 2018 and 2017, respectively.
(b)	A reclassification of debt issuance costs from Total Assets to Long-term debt of $11 million and a reclassification of deferred tax assets from Total Assets to Accumulated deferred income taxes of $306 million is reflected for 2014, in accordance with new accounting standards adopted in 2015 and applied retrospectively.
(c)	Prior to December 2017, Southern Power had no employees but was billed for employee-related costs from SCS.

II-12

Table of Contents Index to Financial Statements

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 2014-2018

Southern Company Gas and Subsidiary Companies 2018 Annual Report



	Successor^(a)						Predecessor^(a)
	2018^(b)		2017		July 1, 2016 through December 31, 2016		January 1, 2016 through June 30, 2016		2015		2014
Operating Revenues (in millions)	$	3,909	$	3,920	$	1,652	$	1,905	$	3,941	$	5,385
Net Income Attributable to Southern Company Gas (in millions)^(c)	$	372	$	243	$	114	$	131	$	353	$	482
Cash Dividends on Common Stock (in millions)	$	468	$	443	$	126	$	128	$	244	$	233
Return on Average Common Equity (percent)^(c)	4.23		2.68		1.74		3.31		9.05		12.96
Total Assets (in millions)	$	21,448	$	22,987	$	21,853	$	14,488	$	14,754	$	14,888
Gross Property Additions (in millions)	$	1,399	$	1,525	$	632	$	548	$	1,027	$	769
Capitalization (in millions):
Common stockholders' equity	$	8,570	$	9,022	$	9,109	$	3,933	$	3,975	$	3,828
Long-term debt	5,583		5,891		5,259		3,709		3,275		3,581
Total (excluding amounts due within one year)	$	14,153	$	14,913	$	14,368	$	7,642	$	7,250	$	7,409
Capitalization Ratios (percent):
Common stockholders' equity	60.6		60.5		63.4		51.5		54.8		51.7
Long-term debt	39.4		39.5		36.6		48.5		45.2		48.3
Total (excluding amounts due within one year)	100.0		100.0		100.0		100.0		100.0		100.0
Service Contracts (period-end)	—		1,184,257		1,198,263		1,197,096		1,205,476		1,162,065
Customers (period-end)
Gas distribution operations	4,247,804		4,623,249		4,586,477		4,544,489		4,557,729		4,529,114
Gas marketing services	697,384		773,984		655,999		630,475		654,475		633,460
Total	4,945,188		5,397,233		5,242,476		5,174,964		5,212,204		5,162,574
Employees (period-end)	4,389		5,318		5,292		5,284		5,203		5,165



(a)	As a result of the Merger, pushdown accounting was applied to create a new cost basis for Southern Company Gas' assets, liabilities, and equity as of the acquisition date. Accordingly, the successor financial statements reflect the new basis of accounting, and successor and predecessor period financial results are presented but are not comparable.
(b)	During 2018, Southern Company Gas completed the Southern Company Gas Dispositions. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 herein for additional information.
(c)	As a result of the Tax Reform Legislation, Southern Company Gas recorded income tax expense (benefit) of $(3) million and $93 million in 2018 and 2017, respectively.

II-13

Table of Contents Index to Financial Statements

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA 2014-2018 (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report



	Successor^(a)						Predecessor^(a)
	2018^(b)		2017		July 1, 2016 through December 31, 2016		January 1, 2016 through June 30, 2016		2015		2014
Operating Revenues (in millions)
Residential	$	1,886	$	2,100	$	899	$	1,101	$	2,129	$	2,877
Commercial	546		641		260		310		617		861
Transportation	944		811		269		290		526		458
Industrial	140		159		74		72		203		242
Other	393		209		150		132		466		947
Total	$	3,909	$	3,920	$	1,652	$	1,905	$	3,941	$	5,385
Heating Degree Days:
Illinois	6,101		5,246		1,903		3,340		5,433		6,556
Georgia	2,588		1,970		727		1,448		2,204		2,882
Gas Sales Volumes (mmBtu in millions):
Gas distribution operations
Firm	721		667		274		396		695		766
Interruptible	95		95		47		49		99		106
Total	816		762		321		445		794		872
Gas marketing services
Firm:
Georgia	37		32		13		21		35		41
Illinois	13		12		4		8		13		17
Other	20		18		5		7		11		10
Interruptible large commercial and industrial	14		14		6		8		14		17
Total	84		76		28		44		73		85
Market share in Georgia (percent)	29.0		29.2		29.4		29.3		29.7		30.6
Wholesale gas services
Daily physical sales (mmBtu in millions/day)	6.7		6.4		7.2		7.6		6.8		6.3



(a)	As a result of the Merger, pushdown accounting was applied to create a new cost basis for Southern Company Gas' assets, liabilities, and equity as of the acquisition date. Accordingly, the successor financial statements reflect the new basis of accounting, and successor and predecessor period financial results are presented but are not comparable.
(b)	During 2018, Southern Company Gas completed the Southern Company Gas Dispositions. See Note 15 to the financial statements under "Southern Company Gas" in Item 8 herein for additional information.

II-14

Table of Contents Index to Financial Statements


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



	Page
Southern Company	II-16
Alabama Power	II-70
Georgia Power	II-93
Mississippi Power	II-124
Southern Power	II-151
Southern Company Gas	II-171

II-15

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Company and Subsidiary Companies 2018 Annual Report

OVERVIEW

Business Activities

Southern Company is a holding company that owns all of the common stock of the traditional electric operating companies and the parent entities of 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.

•

The traditional electric operating companies are vertically integrated utilities providing electric service in three Southeastern states as of January 1, 2019. On January 1, 2019, Southern Company completed its sale of Gulf Power to NextEra Energy for an aggregate cash purchase price of approximately $5.8 billion (less $1.3 billion of indebtedness assumed), subject to customary working capital adjustments. At December 31, 2018, the assets and liabilities of Gulf Power were classified as held for sale on Southern Company's balance sheet. Unless otherwise noted, the disclosures herein related to specific asset and liability balances at December 31, 2018 exclude assets and liabilities held for sale. See Note 15 under "Assets Held for Sale" for additional information. A preliminary gain of $2.5 billion pre-tax ($1.3 billion after tax) associated with the sale of Gulf Power is expected to be recorded in 2019.

•

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. On May 22, 2018, Southern Power sold a noncontrolling 33% equity interest in SP Solar, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, for approximately $1.2 billion and, on December 11, 2018, Southern Power sold a noncontrolling tax equity interest in SP Wind, a holding company owning a portfolio of eight operating wind facilities, for approximately $1.2 billion. On November 5, 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of approximately $650 million, which is expected to close mid-2019. The ultimate outcome of this matter cannot be determined at this time.


•	Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas pipeline investments, wholesale gas services, and gas marketing services. In July 2018, Southern Company Gas completed sales of three of its natural gas distribution utilities.

See FUTURE EARNINGS POTENTIAL – "General" herein and Note 15 to the financial statements for additional information regarding disposition activities.

Many factors affect the opportunities, challenges, and risks of the Southern Company system's electricity and natural gas businesses. These factors include the ability to maintain constructive regulatory environments, to maintain and grow sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, including CCR rules, reliability, fuel, restoration following major storms, and capital expenditures, including constructing new electric generating plants, expanding and improving the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems.

The traditional electric operating companies and natural gas distribution utilities have various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the Southern Company system for the foreseeable future. See Note 2 to the financial statements for additional information.

In 2018, Alabama Power, Georgia Power, Mississippi Power, Atlanta Gas Light, and Nicor Gas reached agreements with their respective state PSCs or other applicable state regulatory agencies relating to the regulatory impacts of the Tax Reform Legislation, which, for some companies, included capital structure adjustments expected to help mitigate the potential adverse impacts to certain of their credit metrics. See Note 2 to the financial statements for additional information regarding state PSC or other regulatory agency actions related to the Tax Reform Legislation. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 10 to the financial statements for information regarding the Tax Reform Legislation.

Another major factor affecting the Southern Company system's businesses is the profitability of the competitive market-based wholesale generating business. Southern Power's strategy is 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.

II-16

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

Southern Company's other business activities include providing energy solutions, including distributed energy infrastructure, energy efficiency products and services, and utility infrastructure services, to customers. Other business activities also include investments in telecommunications, leveraged lease projects, 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.

In striving to achieve attractive risk-adjusted returns while providing cost-effective energy to more than eight million electric and gas utility customers, the Southern Company system continues 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, execution of major construction projects, and earnings per share (EPS). Southern Company's financial success is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys and reliability indicators to evaluate the results of the Southern Company system.

See RESULTS OF OPERATIONS herein for information on Southern Company's financial performance.

Plant Vogtle Units 3 and 4 Status

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each). Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. In December 2017, the Georgia PSC approved Georgia Power's recommendation to continue construction. The current expected in-service dates remain November 2021 for Unit 3 and November 2022 for Unit 4.

In the second quarter 2018, Georgia Power revised its base capital cost forecast and estimated contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for a total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds), with respect to Georgia Power's ownership interest. 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 did not seek rate recovery for the $0.7 billion increase in costs included in the current base capital cost forecast (or any related financing costs) in the nineteenth VCM report that was approved by the Georgia PSC on February 19, 2019. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate 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 a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018.

As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. On September 26, 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4. In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and certain of MEAG's wholly-owned subsidiaries, including MEAG Power SPVJ, LLC (MEAG SPVJ), to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners and (ii) a term sheet (MEAG Term Sheet) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and certain of MEAG's wholly-owned subsidiaries entered into certain amendments to their joint ownership agreements to implement the provisions of the Vogtle Owner Term Sheet.

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

See FUTURE EARNINGS POTENTIAL – "Construction Program – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

Earnings

Consolidated net income attributable to Southern Company was $2.2 billion in 2018, an increase of $1.4 billion, or 164.4%, from the prior year. The increase was primarily due to charges of $3.4 billion ($2.4 billion after tax) in 2017 related to the Kemper IGCC at Mississippi Power, partially offset by a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an

II-17

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

estimated probable loss on Georgia Power's construction of Plant Vogtle Units 3 and 4. The increase also reflects lower federal income tax expense as a result of the Tax Reform Legislation, partially offset by impairment charges, primarily associated with asset sales at Southern Power and Southern Company Gas.

Consolidated net income attributable to Southern Company was $842 million in 2017, a decrease of $1.6 billion, or 65.6%, from the prior year. The decrease was primarily due to pre-tax charges of $3.4 billion ($2.4 billion after tax) related to the Kemper IGCC at Mississippi Power. Also contributing to the change were increases of $240 million in net income from Southern Company Gas (excluding the impact of $111 million in additional expense related to the Tax Reform Legislation) reflecting the 12-month period in 2017 compared to the six-month period following the Merger closing on July 1, 2016, $264 million related to net tax benefits from the Tax Reform Legislation, higher retail electric revenues resulting from increases in base rates partially offset by milder weather and lower customer usage, and increases in renewable energy sales at Southern Power. These increases were partially offset by higher interest and depreciation and amortization.

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

Basic EPS was $2.18 in 2018, $0.84 in 2017, and $2.57 in 2016. Diluted EPS, which factors in additional shares related to stock-based compensation, was $2.17 in 2018, $0.84 in 2017, and $2.55 in 2016. EPS for 2018, 2017, and 2016 was negatively impacted by $0.04, $0.04, and $0.12 per share, respectively, as a result of increases in the average shares outstanding. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein for additional information.

Dividends

Southern Company has paid dividends on its common stock since 1948. Dividends paid per share of common stock were $2.38 in 2018, $2.30 in 2017, and $2.22 in 2016. In January 2019, Southern Company declared a quarterly dividend of 60 cents per share. This is the 285th consecutive quarter that Southern Company has paid a dividend equal to or higher than the previous quarter. For 2018, the dividend payout ratio was 109% compared to 273% for 2017. The decrease was due to an increase in earnings in 2018 resulting from charges related to the Kemper IGCC in 2017, partially offset by the charge related to construction of Plant Vogtle Units 3 and 4 in 2018. See "Earnings" and RESULTS OF OPERATIONS – "Electricity Business – Estimated Loss on Projects Under Construction" herein and Note 2 to the financial statements under "Georgia Power – Nuclear Construction" and "Mississippi Power – Kemper County Energy Facility" for additional information.

RESULTS OF OPERATIONS

Discussion of the 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.



	2018			2017			2016
	(in millions)
Electricity business	$	2,304		$	878		$	2,571
Gas business	372			243			114
Other business activities	(450		)	(279		)	(237		)
Net Income	$	2,226		$	842		$	2,448

II-18

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

Electricity Business

Southern Company's electric utilities generate and sell electricity to retail and wholesale customers. The results of operations discussed below include the results of Gulf Power through December 31, 2018. See Note 15 to the financial statements under "Southern Company's Sale of Gulf Power" for additional information.

A condensed statement of income for the electricity business follows:



	Amount		Increase (Decrease) from Prior Year
	2018		2018			2017
	(in millions)
Electric operating revenues	$	18,571	$	31		$	599
Fuel	4,637		237			39
Purchased power	971		108			113
Cost of other sales	66		(3		)	11
Other operations and maintenance	4,635		45			(76		)
Depreciation and amortization	2,565		108			224
Taxes other than income taxes	1,098		35			24
Estimated loss on plants under construction	1,097		(2,265		)	2,934
Impairment charges	156		156			—
Gain on dispositions, net	—		40			(41		)
Total electric operating expenses	15,225		(1,539		)	3,228
Operating income	3,346		1,570			(2,629		)
Allowance for equity funds used during construction	131		(21		)	(48		)
Interest expense, net of amounts capitalized	1,035		24			80
Other income (expense), net	144		17			58
Income taxes	207		125			(1,009		)
Net income	2,379		1,417			(1,690		)
Less:
Dividends on preferred and preference stock of subsidiaries	16		(22		)	(7		)
Net income attributable to noncontrolling interests	59		13			10
Net Income Attributable to Southern Company	$	2,304	$	1,426		$	(1,693	)

II-19

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

Electric Operating Revenues

Electric operating revenues for 2018 were $18.6 billion, reflecting a $31 million increase from 2017. Details of electric operating revenues were as follows:



	2018			2017
	(in millions)
Retail electric — prior year	$	15,330		$	15,234
Estimated change resulting from —
Rates and pricing	(773		)	508
Sales growth (decline)	84			(71		)
Weather	300			(281		)
Fuel and other cost recovery	281			(60		)
Retail electric — current year	15,222			15,330
Wholesale electric revenues	2,516			2,426
Other electric revenues	664			681
Other revenues	169			103
Electric operating revenues	$	18,571		$	18,540
Percent change	0.2		%	3.3		%

Retail electric revenues decreased $108 million, or 0.7%, in 2018 as compared to the prior year. The significant factors driving this change are shown in the preceding table. The decrease in rates and pricing in 2018 was primarily due to revenues deferred as regulatory liabilities for customer bill credits related to the Tax Reform Legislation and expected customer refunds at Alabama Power and Georgia Power.

Retail electric revenues increased $96 million, or 0.6%, in 2017 as compared to the prior year. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing in 2017 was primarily due to a Rate RSE increase at Alabama Power effective in January 2017, the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff at Georgia Power, and an increase in retail base rates effective July 2017 at Gulf Power.

See Note 2 to the financial statements under "Southern Company – Gulf Power," "Alabama Power – Rate RSE" and " – Rate CNP Compliance," "Georgia Power – Rate Plans," and " – Nuclear Construction" for additional information. Also see "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes related to sales growth (decline) and weather.

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.

Wholesale electric revenues consist of 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 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.

II-20

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

Wholesale electric revenues from power sales were as follows:



	2018		2017		2016
	(in millions)
Capacity and other	$	620	$	642	$	570
Energy	1,896		1,784		1,356
Total	$	2,516	$	2,426	$	1,926

In 2018, wholesale revenues increased $90 million, or 3.7%, as compared to the prior year due to a $112 million increase in energy revenues, partially offset by a $22 million decrease in capacity revenues. The increase in energy revenues was primarily related to Southern Power and includes new PPAs related to existing natural gas facilities, new renewable facilities, and an increase in the volume of KWHs sold at existing renewable facilities, partially offset by a decrease in non-PPA revenues from short-term sales. The decrease in capacity revenues was primarily due to the expiration of a wholesale contract in the fourth quarter 2017 at Georgia Power.

In 2017, wholesale revenues increased $500 million, or 26.0%, as compared to the prior year due to a $428 million increase in energy revenues and a $72 million increase in capacity revenues, primarily at Southern Power. The increase in energy revenues was primarily due to increases in renewable energy sales arising from new solar and wind facilities and non-PPA revenues from short-term sales. The increase in capacity revenues was primarily due to a PPA related to new natural gas facilities and additional customer capacity requirements.

Other Electric Revenues

Other electric revenues decreased $17 million, or 2.5%, in 2018 as compared to the prior year. The decrease is primarily related to a decrease in open access transmission tariff revenues, largely due to a lower rate related to the Tax Reform Legislation. Other electric revenues decreased $17 million, or 2.4%, in 2017, as compared to the prior year. The decrease reflects a $15 million decrease in open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts at Georgia Power.

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2018 and the percent change from the prior year were as follows:



	Total KWHs	Total KWH Percent Change				Weather-Adjusted Percent Change
	2018	2018		2017		2018		2017
	(in billions)
Residential	54.6	8.0	%	(5.3	)%	1.2	%	(0.3	)%
Commercial	53.5	2.1		(2.6	)	0.5		(0.9	)
Industrial	53.3	1.1		—		1.1		—
Other	0.8	(5.5	)	(4.0	)	(5.7	)	(3.9	)
Total retail	162.2	3.6		(2.6	)	0.9	%	(0.4	)%
Wholesale	49.9	1.9		32.4
Total energy sales	212.1	3.2	%	3.9	%

Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales increased 5.7 billion KWHs in 2018 as compared to the prior year. This increase was primarily due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017. Weather-adjusted residential KWH sales increased primarily due to customer growth. Weather-adjusted commercial KWH sales increased primarily due to customer growth, partially offset by decreased customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model. Industrial KWH energy sales increased primarily due to increased sales in the primary metals sector, partially offset by decreased sales in the paper sector.

Retail energy sales decreased 4.2 billion KWHs in 2017 as compared to the prior year. This decrease was primarily due to milder weather and decreased customer usage, partially offset by customer growth. Weather-adjusted residential KWH sales decreased

II-21

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

primarily due to decreased customer usage resulting from an increase in penetration of energy-efficient residential appliances and an increase in multi-family housing, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased primarily due to decreased customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth. Industrial KWH energy sales were flat primarily due to decreased sales in the paper, stone, clay, and glass, transportation, and chemicals sectors, offset by increased sales in the primary metals and textile sectors. Additionally, Hurricane Irma negatively impacted customer usage for all customer classes.

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 $66 million, or 64.1%, in 2018 as compared to the prior year. The increase was primarily due to unregulated sales of products and services that were reclassified from other income (expense), net as a result of the adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). See Note 1 to the financial statements for additional information regarding the adoption of ASC 606.

Other revenues increased $20 million in 2017 as compared to the prior year. The increase was primarily due to additional third party infrastructure services.

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:



	2018	2017	2016
Total generation (in billions of KWHs)	200	194	188
Total purchased power (in billions of KWHs)	21	20	19
Sources of generation (percent) —
Gas	46	46	46
Coal	30	30	33
Nuclear	15	16	16
Hydro	3	2	2
Other	6	6	3
Cost of fuel, generated (in cents per net KWH)^(a)—
Gas	2.89	2.79	2.48
Coal	2.80	2.81	3.04
Nuclear	0.80	0.79	0.81
Average cost of fuel, generated (in cents per net KWH)^(a)	2.50	2.44	2.40
Average cost of purchased power (in cents per net KWH)^(b⁾	5.46	5.19	4.81


(a)	For 2018, cost of fuel, generated and average cost of fuel, generated excludes a $30 million adjustment associated with a May 2018 Alabama PSC accounting order related to excess deferred income taxes.


(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 2018, total fuel and purchased power expenses were $5.6 billion, an increase of $345 million, or 6.6%, as compared to the prior year. The increase was primarily the result of a $178 million increase in the volume of KWHs generated and purchased primarily due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017 and a $137 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices.

In addition, fuel expense increased $30 million in 2018 as a result of an Alabama PSC accounting order authorizing the amortization of a regulatory liability to offset under recovered fuel costs. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power – Tax Reform Accounting Order" herein for additional information.

II-22

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

In 2017, total fuel and purchased power expenses were $5.3 billion, an increase of $152 million, or 3.0%, as compared to the prior year. The increase was primarily the result of a $196 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset by a $44 million net decrease 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 FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Fuel Cost Recovery" herein 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 2018, fuel expense was $4.6 billion, an increase of $237 million, or 5.4%, as compared to the prior year. The increase was primarily due to a 3.6% increase in the average cost of natural gas per KWH generated, a 3.5% increase in the volume of KWHs generated by coal, and a 2.8% increase in the volume of KWHs generated by natural gas.

In 2017, fuel expense was $4.4 billion, an increase of $39 million, or 0.9%, as compared to the prior year. The increase was primarily due to a 12.5% increase in the average cost of natural gas per KWH generated and a 2.8% increase in the volume of KWHs generated by natural gas, partially offset by a 7.9% decrease in the volume of KWHs generated by coal and a 7.6% decrease in the average cost of coal per KWH generated.

Purchased Power

In 2018, purchased power expense was $971 million, an increase of $108 million, or 12.5%, as compared to the prior year. The increase was primarily due to a 5.2% increase in the average cost per KWH purchased, primarily as a result of higher natural gas prices, and a 5.2% increase in the volume of KWHs purchased.

In 2017, purchased power expense was $863 million, an increase of $113 million, or 15.1%, as compared to the prior year. The increase was primarily due to a 7.9% increase in the average cost per KWH purchased, primarily as a result of higher natural gas prices, and a 5.0% increase in the volume of KWHs purchased.

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.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $45 million, or 1.0%, in 2018 as compared to the prior year. The increase was primarily due to a $74 million increase in transmission and distribution costs, primarily related to additional vegetation management at Georgia Power, and $74 million in expenses from unregulated sales of products and services that were reclassified to other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. These increases were partially offset by a $32.5 million charge in the first quarter 2017 related to the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with a rate case settlement agreement, a $30 million net decrease in employee compensation and benefits, including pension costs, largely due to a decrease in active medical costs at Alabama Power and a 2017 employee attrition plan at Georgia Power, and a $27 million decrease in customer accounts, service, and sales costs primarily due to cost-saving initiatives. See Note 1 to the financial statements for additional information regarding the adoption of ASC 606.

Other operations and maintenance expenses decreased $76 million, or 1.6%, in 2017 as compared to the prior year. The decrease was primarily due to cost containment and modernization activities implemented at Georgia Power that contributed to decreases of $85 million in generation maintenance costs, $46 million in transmission and distribution overhead line maintenance, $22 million in other employee compensation and benefits, and $22 million in customer accounts, service, and sales costs. Additionally, there was a $34 million decrease in scheduled outage and maintenance costs at generation facilities. These decreases were partially offset by a $56 million increase associated with new facilities at Southern Power, a $37 million increase in transmission and distribution costs primarily due to vegetation management at Alabama Power, and $32.5 million resulting from the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with a rate case settlement agreement.

Production expenses and transmission and distribution expenses fluctuate from year to year due to variations in outage and maintenance schedules and normal changes in the cost of labor and materials.

II-23

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

Depreciation and Amortization

Depreciation and amortization increased $108 million, or 4.4%, in 2018 as compared to the prior year. The increase was primarily related to additional plant in service. Additionally, the increase reflects $34 million in depreciation credits recognized in 2017, as authorized in Gulf Power's 2013 rate case settlement.

Depreciation and amortization increased $224 million, or 10.0%, in 2017 as compared to the prior year. The increase reflects $203 million related to additional plant in service at the traditional electric operating companies and Southern Power and a $13 million increase in amortization related to environmental compliance at Mississippi Power. The increase was partially offset by $34 million in depreciation credits recognized in accordance with Gulf Power's 2013 rate case settlement.

See Note 2 to the financial statements under "Southern Company – Regulatory Assets and Liabilities" and Note 5 to the financial statements under "Depreciation and Amortization" for additional information.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $35 million, or 3.3%, in 2018 as compared to the prior year primarily due to increased property taxes associated with higher assessed values and an increase in municipal franchise fees primarily related to higher retail revenues at Georgia Power.

Taxes other than income taxes increased $24 million, or 2.3%, in 2017 as compared to the prior year primarily due to an increase in property taxes due to new facilities at Southern Power.

Estimated Loss on Projects Under Construction

In the second quarter 2018, an estimated probable loss of $1.1 billion was recorded to reflect Georgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4, which reflects the increase in costs included in the revised base capital cost forecast for which Georgia Power did not seek rate recovery and costs included in the revised construction contingency estimate for which Georgia Power may seek rate recovery as and when such costs are appropriately included in the base capital cost forecast. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information.

Charges associated with the Kemper IGCC of $37 million, $3.4 billion, and $428 million were recorded in 2018, 2017, and 2016, respectively. The 2018 pre-tax charge of $37 million primarily resulted from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. On June 28, 2017, Mississippi Power suspended the gasifier portion of the project and recorded a charge to earnings for the remaining $2.8 billion book value of the gasifier portion of the project. Prior to the suspension, Mississippi Power recorded losses for revisions of estimated costs expected to be incurred on construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions. See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" for additional information.

Impairment Charges

In the second quarter 2018, Southern Power recorded a $119 million asset impairment charge in contemplation of the sale of Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) and in the third quarter 2018 recorded a $36 million asset impairment charge on wind turbine equipment held for development projects. There were no asset impairment charges recorded in 2017 or 2016. See Note 15 to the financial statements under "Southern Power – Sales of Natural Gas Plants" and " – Development Projects" for additional information.

Gain on Dispositions, Net

Gain on dispositions, net decreased $40 million in 2018 and increased $41 million in 2017 as compared to the prior periods primarily due to gains on sales of assets at Georgia Power recorded in 2017.

Allowance for Equity Funds Used During Construction

AFUDC equity decreased $21 million, or 13.8%, in 2018 as compared to the prior year primarily due to Mississippi Power's suspension of the Kemper IGCC construction in June 2017, partially offset by a higher AFUDC rate resulting from a higher equity ratio and lower short-term borrowings at Georgia Power and a higher AFUDC base related to steam and transmission construction projects at Alabama Power.

II-24

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

AFUDC equity decreased $48 million, or 24.0%, in 2017 as compared to the prior year primarily due to Mississippi Power's suspension of the Kemper IGCC in June 2017.

See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $24 million, or 2.4%, in 2018 as compared to the prior year. The increase was primarily related to Mississippi Power and reflects a $33 million net reduction in interest recorded in 2017 following a settlement with the IRS related to research and experimental deductions and a $29 million reduction in interest capitalized related to the Kemper IGCC suspension in June 2017. The increase also reflects an increase in outstanding borrowings and higher interest rates at Alabama Power, partially offset by a decrease in outstanding borrowings at Georgia Power. See Note 10 to the financial statements under "Section 174 Research and Experimental Deduction" for additional information.

Interest expense, net of amounts capitalized increased $80 million, or 8.6%, in 2017 as compared to the prior year primarily due to an increase in average outstanding long-term debt, primarily at Southern Power and Georgia Power, and a $37 million decrease in interest capitalized, primarily at Southern Power and Mississippi Power, partially offset by a net reduction of $33 million following Mississippi Power's settlement with the IRS related to research and experimental deductions. See Note 10 to the financial statements under "Unrecognized Tax Benefits" for additional information.

See Note 8 to the financial statements for additional information.

Other Income (Expense), Net

Other income (expense), net increased $17 million, or 13.4%, in 2018 as compared to the prior year primarily due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018 and a gain from a joint-development wind project at Southern Power, which is attributable to Southern Power's partner in the project and fully offset within noncontrolling interests, partially offset by an increase in charitable donations. See Note 3 to the financial statements under "General Litigation Matters – Mississippi Power" and Note 7 to the financial statements under "Southern Power" for additional information.

Other income (expense), net increased $58 million, or 84.1%, in 2017 as compared to the prior year primarily due to a decrease in non-service cost components of net periodic pension and other postretirement benefits costs, partially offset by increases in charitable donations. The change also includes an increase of $159 million in currency losses arising from a translation of euro-denominated fixed-rate notes into U.S. dollars, fully offset by an equal change in gains on the foreign currency hedges that were reclassified from accumulated OCI into earnings at Southern Power. See Note 1 under "Recently Adopted Accounting Standards" and Note 11 to the financial statements for additional information on net periodic pension and other postretirement benefit costs.

Income Taxes

Income taxes increased $125 million, or 152.4%, in 2018 as compared to the prior year. The increase was primarily due to an increase in pre-tax earnings, primarily resulting from charges recorded in 2017 related to the Kemper IGCC at Mississippi Power, partially offset by the estimated probable loss on Plant Vogtle Units 3 and 4 at Georgia Power recognized in the second quarter 2018. This increase was partially offset by lower federal income tax expense, as well as benefits from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation.

Income taxes decreased $1.0 billion, or 92.5%, in 2017 as compared to the prior year primarily due to $809 million in tax benefits related to estimated losses on the Kemper IGCC at Mississippi Power and $346 million in net tax benefits resulting from the Tax Reform Legislation.

See Note 10 to the financial statements for additional information.

Dividends on Preferred and Preference Stock of Subsidiaries

Dividends on preferred and preference stock of subsidiaries decreased $22 million, or 57.9%, in 2018 as compared to 2017 and decreased $7 million, or 15.6%, in 2017 as compared to 2016. These decreases were primarily due to the 2017 redemptions of all outstanding shares of preferred and preference stock at Georgia Power and Gulf Power. See Note 8 to the financial statements for additional information.

Net Income Attributable to Noncontrolling Interests

Substantially all noncontrolling interests relate to renewable projects at Southern Power. Net income attributable to noncontrolling interests increased $13 million, or 28.3%, in 2018, as compared to the prior year. The increase was primarily due to $20 million of net income allocations due to the sale of a noncontrolling 33% equity interest in SP Solar in 2018 and $14

II-25

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

million of other income allocations attributable to a joint-development wind project, partially offset by a reduction of $19 million due to HLBV income allocations between Southern Power and tax equity partners for partnerships entered into during 2018. In 2017, noncontrolling interests increased $10 million, or 28%, compared to 2016 primarily due to additional net income allocations from new solar partnerships.

See Note 15 under "Southern Power" 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, and gas marketing services.

A condensed statement of income for the gas business follows:



	Amount			Increase (Decrease) from Prior Year
	2018			2018			2017
	(in millions)
Operating revenues	$	3,909		$	(11	)	$	2,268
Cost of natural gas	1,539			(62		)	988
Cost of other sales	12			(17		)	19
Other operations and maintenance	981			36			424
Depreciation and amortization	500			(1		)	263
Taxes other than income taxes	211			27			113
Impairment charges	42			42			—
Gain on dispositions, net	(291		)	(291		)	—
Total operating expenses	2,994			(266		)	1,807
Operating income	915			255			461
Earnings from equity method investments	148			42			46
Interest expense, net of amounts capitalized	228			28			119
Other income (expense), net	1			(43		)	32
Income taxes	464			97			291
Net income	$	372		$	129		$	129

In the table above, the 2018 changes for Southern Company Gas reflect the year ended December 31, 2018 compared to 2017. The Southern Company Gas Dispositions were completed by July 29, 2018 and represent the primary variance driver for the 2018 changes. Additional detailed variance explanations are provided herein. The 2017 changes reflect the 12-month period in 2017 compared to the six-month period following the Merger closing on July 1, 2016, which is the primary variance driver. Additionally, earnings from equity method investments include Southern Company Gas' acquisition of a 50% equity interest in SNG completed in September 2016. See Note 15 to the financial statements under "Southern Company Gas" for additional information on Southern Company Gas' investment in SNG and the Southern Company Gas Dispositions.

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. Occasionally in the summer, operating revenues are 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 2018, the percentage of operating revenues and net income generated during the Heating Season (January through March and November through December) were 68.7% and 96.0%, respectively. For 2017, the percentage of operating revenues and net income generated during the Heating Season were 67.3% and 73.7%, respectively. The 2017 net income generated during the Heating Season was significantly impacted by additional tax expense recorded in the fourth quarter resulting from the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein for additional information.

II-26

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

Operating Revenues

Operating revenues in 2018 were $3.9 billion, reflecting an $11 million decrease from 2017. Details of operating revenues were as follows:



	(in millions)			(% change)
Operating revenues – prior year	$	3,920
Estimated change resulting from –
Infrastructure replacement programs and base rate changes	31			0.8
Gas costs and other cost recovery	3			0.1
Weather	13			0.3
Wholesale gas services	138			3.5
Southern Company Gas Dispositions^(*)	(228		)	(5.8	)
Other	32			0.8
Operating revenues – current year	$	3,909		(0.3	)%


(*)	Includes a $154 million decrease related to natural gas revenues, including alternative revenue programs, and a $74 million decrease related to other revenues. See Note 15 to the financial statements under "Southern Company Gas" for additional information.

Revenues from infrastructure replacement programs and base rate changes increased in 2018 primarily due to a $48 million increase at Nicor Gas, partially offset by a $12 million decrease at Atlanta Gas Light. These amounts include the natural gas distribution utilities' continued investments recovered through infrastructure replacement programs and base rate increases less revenue reductions for the impacts of the Tax Reform Legislation. See Note 2 to the financial statements under "Southern Company Gas" for additional information.

Revenues increased due to colder weather, as determined by Heating Degree Days, in 2018 compared to 2017.

Revenues from wholesale gas services increased in 2018 primarily due to increased commercial activity, partially offset by derivative losses.

Other revenues increased in 2018 primarily due to a $15 million increase from the Dalton Pipeline being placed in service in August 2017 and a $14 million increase in Nicor Gas' revenue taxes.

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.

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 83.2% of the total cost of natural gas for 2018.

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 in 2018 was $1.5 billion, a decrease of $62 million, or 3.9%, compared to 2017, which was substantially all as a result of the Southern Company Gas Dispositions.

II-27

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

Cost of Other Sales

Cost of other sales in 2018 was $12 million, a decrease of $17 million, or 58.6%, compared to 2017 primarily related to the disposition of Pivotal Home Solutions.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $36 million, or 3.8%, in 2018 compared to the prior year. Excluding a $39 million decrease related to the Southern Company Gas Dispositions, other operations and maintenance expenses increased $75 million. This increase was primarily due to a $53 million increase in compensation and benefit costs, including a $12 million one-time increase for the adoption of a new paid time off policy to align with the Southern Company system, a $28 million increase in disposition-related costs, and an $11 million expense for a litigation settlement to facilitate the sale of Pivotal Home Solutions. These increases were partially offset by a $27 million decrease in bad debt expense primarily at Nicor Gas, which was offset by a decrease in revenues as a result of the related regulatory recovery mechanism. See Note 3 to the financial statements under "General Litigation Matters – Southern Company Gas" for additional information on the litigation settlement.

Depreciation and Amortization

Depreciation and amortization decreased $1 million, or 0.2%, in 2018 compared to the prior year. Excluding a $37 million decrease related to the Southern Company Gas Dispositions, depreciation and amortization increased $36 million. The increase was primarily due to continued infrastructure investments at the natural gas distribution utilities, partially offset by lower amortization of intangible assets as a result of fair value adjustments in acquisition accounting at gas marketing services. See Note 2 to the financial statements under "Southern Company Gas" for additional information on infrastructure replacement programs.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $27 million, or 14.7%, in 2018 compared to the prior year. Excluding a $4 million decrease related to the Southern Company Gas Dispositions, taxes other than income taxes increased $31 million. This increase primarily reflects a $13 million increase in revenue tax expenses as a result of higher natural gas revenues, a $12 million increase in Nicor Gas' invested capital tax that reflects a $7 million credit in 2017 to establish a related regulatory asset, and a $4 million increase in property taxes. See Note 15 to the financial statements under "Southern Company Gas" for additional information on the Southern Company Gas Dispositions.

Impairment Charges

A goodwill impairment charge of $42 million was recorded in 2018 in contemplation of the sale of Pivotal Home Solutions. See Notes 1 and 15 to the financial statements under "Goodwill and Other Intangible Assets and Liabilities" and "Southern Company Gas – Sale of Pivotal Home Solutions," respectively, for additional information.

Gain on Dispositions, Net

Gain on dispositions, net was $291 million in 2018 and was associated with the Southern Company Gas Dispositions. The income tax expense on these gains included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously.

Earnings from Equity Method Investments

Earnings from equity method investments increased $42 million, or 39.6%, in 2018 compared to the prior year. The increase was primarily due to higher earnings from Southern Company Gas' equity method investment in SNG from new rates effective September 2018 and lower operations and maintenance expenses due to the timing of pipeline maintenance. See Note 7 to the financial statements under "Southern Company Gas – Equity Method Investments" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $28 million, or 14.0%, in 2018 compared to the prior year. The increase was primarily due to $21 million of additional interest expense related to new debt issuances and a $4 million reduction in capitalized interest primarily due to the Dalton Pipeline being placed in service in August 2017.

Other Income (Expense), Net

Other income (expense), net decreased $43 million, or 97.7%, in 2018 compared to the prior year. Excluding a $3 million decrease related to the Southern Company Gas Dispositions, other income (expense), net decreased $40 million. This decrease

II-28

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

was primarily due to a $23 million increase in charitable donations and a $13 million decrease in gains from the settlement of contractor litigation claims. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects – PRP" for additional information on the contractor litigation settlement.

Income Taxes

Income taxes increased $97 million, or 26.4%, in 2018 compared to the prior year. Excluding a $329 million increase related to the Southern Company Gas Dispositions, including tax expense on the goodwill for which a deferred tax liability had not been previously provided, income taxes decreased $232 million. This decrease was primarily due to a lower federal income tax rate and the flowback of excess deferred taxes as a result of the Tax Reform Legislation. In addition, 2017 included additional tax expense of $130 million from the revaluation of deferred tax assets associated with the Tax Reform Legislation, the enactment of the State of Illinois income tax legislation, and new income tax apportionment factors in several states. See 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 was acquired on May 9, 2016 and is a provider of energy solutions, including distributed infrastructure, energy efficiency products and services, and utility infrastructure services, to customers; Southern Company Holdings, Inc. (Southern Holdings), which invests in various projects, including leveraged lease projects; and Southern Linc, which 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.

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



	Amount			Increase (Decrease) from Prior Year
	2018			2018			2017
	(in millions)
Operating revenues	$	1,015		$	444		$	268
Cost of other sales	728			313			223
Other operations and maintenance	273			69			9
Depreciation and amortization	66			14			21
Taxes other than income taxes	6			3			—
Impairment charges	12			12			—
Total operating expenses	1,085			411			253
Operating income (loss)	(70		)	33			15
Interest expense	579			96			178
Other income (expense), net	(23		)	(23		)	30
Income taxes (benefit)	(222		)	85			(91		)
Net income (loss)	$	(450	)	$	(171	)	$	(42	)

In the table above, the 2018 changes for these other business activities reflect the inclusion of PowerSecure for the year ended December 31, 2018 compared to 2017. The 2017 changes reflect the inclusion of PowerSecure for the 12-month period in 2017 compared to the eight-month period following the acquisition on May 9, 2016, which is the primary variance driver. Additional detailed variance explanations are provided herein. See Note 15 to the financial statements under "Southern Company Acquisition of PowerSecure" for additional information.

Operating Revenues

Southern Company's operating revenues for these other business activities increased $444 million, or 77.8%, in 2018 as compared to the prior year. The increase was primarily related to PowerSecure's storm restoration services in Puerto Rico.

Cost of Other Sales

Cost of other sales for these other business activities increased $313 million, or 75.4% in 2018. The increase was primarily related to PowerSecure's storm restoration services in Puerto Rico.

II-29

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

Other Operations and Maintenance Expenses

Other operations and maintenance expenses for these other business activities increased $69 million, or 33.8%, in 2018 as compared to the prior year. The increase was primarily due to PowerSecure's storm restoration services in Puerto Rico and parent company expenses related to the sale of Gulf Power. Other operations and maintenance expenses for these other business activities increased $9 million, or 4.6%, in 2017 as compared to the prior year. The increase was primarily due to a $44 million increase as a result of the inclusion of PowerSecure results for the 12-month period in 2017 compared to eight months in 2016, partially offset by a $35 million decrease in parent company expenses related to the Merger and the acquisition of PowerSecure.

Impairment Charges

Impairment charges for these other business activities were $12 million in 2018. These charges were associated with Southern Linc's tower leases and were recorded in contemplation of the sale of Gulf Power.

Interest Expense

Interest expense for these other business activities increased $96 million, or 19.9%, in 2018 as compared to the prior year primarily due to an increase in variable interest rates and average outstanding debt at the parent company. Interest expense for these other business activities increased $178 million, or 58.4%, in 2017 as compared to the prior year primarily due to an increase in average outstanding long-term debt at the parent company. See Note 8 to the financial statements for additional information.

Other Income (Expense), Net

Other income (expense), net for these other business activities decreased $23 million in 2018 as compared to the prior year primarily due to charitable donations, partially offset by leveraged lease income at Southern Holdings. See Note 1 to the financial statements for additional information. Other income (expense), net for these other business activities increased $30 million in 2017 as compared to the prior year primarily due to expenses associated with bridge financing for the Merger in 2016.

Income Taxes (Benefit)

The income tax benefit for these other business activities decreased $85 million, or 27.7%, in 2018 as compared to the prior year primarily as a result of the Tax Reform Legislation, partially offset by an increase in pre-tax losses at the parent company. The income tax benefit for these other business activities increased $91 million, or 42.1%, in 2017 as compared to the prior year primarily as a result of pre-tax earnings (losses) and net tax benefits related to the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 10 to the financial statements for additional information.

Effects of Inflation

The electric operating companies and natural gas distribution utilities are subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Southern Power is party to long-term contracts reflecting market-based rates, including inflation expectations. Any adverse effect of inflation on Southern Company's results of operations has not been substantial in recent years.

FUTURE EARNINGS POTENTIAL

General

The traditional electric operating companies operate as vertically integrated utilities providing electric service to customers within their service territories in the Southeast. On January 1, 2019, Southern Company completed the sale of Gulf Power, one of the traditional electric operating companies, to NextEra Energy. The natural gas distribution utilities provide service to customers in their service territories in Illinois, Georgia, Virginia, and Tennessee. In July 2018, Southern Company Gas completed sales of three of its natural gas distribution utilities. Prices for electricity provided and natural gas distributed 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 and may be adjusted periodically within certain limitations. Prices for wholesale electricity sales and natural gas distribution, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Southern Power continues to focus on long-term PPAs. In 2018, Southern Power completed sales of noncontrolling interests in entities indirectly owning substantially all of its solar facilities and eight of its wind facilities and also completed sales and entered into an agreement to sell certain of its natural gas plants. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies

II-30

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

and Estimates – Utility Regulation" herein and Note 2 to the financial statements for additional information about regulatory matters.

The results of operations for the past three years are not necessarily indicative of Southern Company's future earnings potential. Future earnings will be impacted by the 2018 disposition activities described herein and in Note 15 to the financial statements. The level of Southern Company's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Southern Company system's primary businesses of selling electricity and distributing natural gas. These factors include the traditional electric operating companies' and the natural gas distribution utilities' ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs during a time of increasing costs, continued customer growth, and, for the traditional electric operating companies, the weak pace of growth in electricity use per customer, especially in residential and commercial markets. Plant Vogtle Units 3 and 4 construction and rate recovery and the profitability of Southern Power's competitive wholesale business are also major factors.

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, increasing volumes of electronic commerce transactions, and more multi-family home construction, all of which could contribute to a net reduction in customer usage. Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the prices of electricity and natural gas, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale electric business also depends on numerous factors including regulatory matters, creditworthiness of customers, total electric generating capacity available and related costs, the development or acquisition of renewable facilities and other energy projects, and the successful remarketing of capacity as current contracts expire. Demand for electricity and natural gas is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings. In addition, the volatility of natural gas prices has a significant impact on the natural gas distribution utilities' customer rates, long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services and wholesale gas services businesses to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability.

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 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.

On January 1, 2019, Southern Company completed the sale of Gulf Power to NextEra Energy for an aggregate cash purchase price of approximately $5.8 billion (less $1.3 billion of indebtedness assumed), subject to customary working capital adjustments. In 2018, net income attributable to Gulf Power was $160 million.

On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $365 million. On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy for a total cash purchase price of $587 million. The total cash purchase price for each transaction includes final working capital and other adjustments.

The Southern Company Gas Dispositions resulted in a net loss of $51 million, which includes $342 million of tax expense. The after-tax impacts of these dispositions included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. In addition, a goodwill impairment charge of $42 million was recorded during 2018 in contemplation of the sale of Pivotal Home Solutions.

On May 22, 2018, Southern Power sold a noncontrolling 33% equity interest in SP Solar, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, for approximately $1.2 billion and, on December 11, 2018, sold a noncontrolling tax equity interest in SP Wind, a holding company owning a portfolio of eight operating wind facilities, for approximately $1.2 billion. Additionally, on November 5, 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of approximately $650 million. The completion of the disposition is subject to the expansion unit reaching commercial operation as well as various other customary conditions to closing, including FERC and state commission approvals, and the sale is expected

II-31

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

to close mid-2019. The ultimate outcome of this matter cannot be determined at this time. On December 4, 2018, Southern Power sold of all of its equity interests in the Florida Plants to NextEra Energy for approximately $203 million.

See Note 15 to the financial statements for additional information regarding disposition activities.

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, and protection of other natural resources. The Southern Company system maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future electric generating unit retirement and replacement decisions, 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. The ultimate impact of environmental laws and regulations and the GHG goals discussed herein will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, and the outcome of pending and/or future legal challenges.

New or revised environmental laws and regulations could affect many areas of the traditional electric operating companies', Southern Power's, and the natural gas distribution utilities' operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be recovered in rates on a timely basis 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. 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 for some may have the potential to ultimately affect their demand for electricity and natural gas.

The Southern Company system's commitment to the environment has been demonstrated in many ways, including participating in partnerships resulting in approximately $140 million of funding that has restored or enhanced more than 2 million acres of habitat since 2003; the removal of more than 15.5 million pounds of trash and debris from waterways between 2000 and 2018 through the Renew Our Rivers program; a 21.2% reduction in surface water withdrawal from 2015 to 2017; reductions in SO₂ and NO_X air emissions of 98% and 89%, respectively, from 1990 to 2017; the reduction of mercury air emissions of over 95% from 2005 to 2017; and the Southern Company system's changing energy mix.

Through 2018, the traditional electric operating companies have invested approximately $14.2 billion in environmental capital retrofit projects to comply with environmental requirements, with annual totals of approximately $1.3 billion, $0.9 billion, and $0.5 billion for 2018, 2017, and 2016, respectively. 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, the Southern Company system's current compliance strategy estimates capital expenditures of $1.4 billion from 2019 through 2023, with annual totals of approximately $0.5 billion, $0.2 billion, $0.3 billion, $0.3 billion, and $0.2 billion for 2019, 2020, 2021, 2022, and 2023, respectively. These estimates do not include any potential compliance costs associated with pending regulation of CO₂ emissions from fossil fuel-fired electric generating units. See "Global Climate Issues" herein for additional information. The Southern Company system also anticipates substantial expenditures associated with ash pond closure and ground water monitoring under the CCR Rule, which are reflected in Southern Company's ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 6 to the financial statements for additional information.

Environmental Laws and Regulations

Air Quality

II-32

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

except for a seven-county area within metropolitan Atlanta that is not in attainment with the 2015 ozone NAAQS and the area surrounding Plant Hammond, in Georgia, which will not be designated attainment or nonattainment for the 2010 SO₂standard until December 2020. If areas are designated as nonattainment in the future, increased compliance costs could result. See "Regulatory Matters – Georgia Power – Integrated Resource Plan" herein for information regarding Georgia Power's request to decertify and retire Plant Hammond.

In 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to address impacts of SO₂ and NO_X emissions from fossil fuel-fired electric generating plants. CSAPR establishes emissions trading programs and budgets for certain states and allocates emissions allowances for sources in those states. In 2016, the EPA published a final rule establishing more stringent ozone season NO_X emissions budgets in Alabama, Mississippi, and Texas. Georgia's ozone season NO_Xemissions budget remained unchanged. The EPA also removed North Carolina from this particular CSAPR program. The outcome of ongoing CSAPR litigation concerning the 2016 CSAPR rule, to which Mississippi Power is a party, could have an impact on the State of Mississippi's ozone season NO_X emissions budget. Increases in either future fossil fuel-fired generation or the availability or cost of CSAPR allowances could have a negative financial impact on results of operations for Southern Company.

The EPA finalized regional haze regulations in 2005 and 2017. These regulations require states, tribal governments, 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 must submit a revised state implementation plan (SIP) to the EPA demonstrating continued reasonable progress towards achieving visibility improvement goals. These plans could require reductions in certain pollutants, such as particulate matter, SO₂, and NO_X, which could result in increased compliance costs. The EPA approved the regional progress SIPs for the States of Alabama and Georgia, but only issued a limited approval of the regional progress SIP for the State of Mississippi because Mississippi must revise the best available retrofit technology (BART) provisions of its SIP. Therefore, Mississippi Power's Plant Daniel is the only electric generating unit in the Southern Company system that continues to be evaluated under the regional haze BART provisions. Mississippi Power is required to submit Plant Daniel's BART analysis to the State of Mississippi by summer 2019. Requirements for further reduction of these pollutants at Plant Daniel could increase compliance costs.

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 (e.g. coal, natural gas, oil, and nuclear generating plants) and manufacturing facilities. The regulation requires plant-specific studies to determine applicable CWIS changes to protect organisms that either get caught on the intake screens (impingement) or are drawn into the cooling system (entrainment). The Southern Company system is conducting these studies and currently anticipates applicable CWIS changes may include fish-friendly CWIS screens with fish return systems and minor additions of monitoring equipment at certain plants. However, the ultimate 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 National Pollutant Discharge Elimination System (NPDES) permit based on site-specific factors, and the outcome of any legal challenges.

In 2015, the EPA finalized the steam electric effluent limitations guidelines (ELG) rule (2015 ELG Rule) that set national standards for wastewater discharges from new and existing steam electric generating units generating greater than 50 MWs. The 2015 ELG Rule prohibits effluent discharges of certain waste streams and imposes stringent limits on flue gas desulfurization (scrubber) wastewater discharges. The revised technology-based limits and the CCR Rule require extensive changes to existing ash and wastewater management systems or the installation and operation of new ash and wastewater management systems. Compliance with the 2015 ELG Rule is expected to require capital expenditures and increased operational costs primarily for the traditional electric operating companies' coal-fired electric generation. State environmental agencies will incorporate specific compliance applicability dates in the NPDES permitting process for each ELG waste stream no later than December 31, 2023. The EPA is scheduled to issue a new rulemaking by December 2019 that could revise the limitations and applicability dates of two of the waste streams regulated in the 2015 ELG Rule. The impact of any changes to the 2015 ELG Rule will depend on the content of the new rule and the outcome of any legal challenges.

In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) jointly published a final rule that revised the regulatory definition of waters of the United States (WOTUS) for all CWA programs. The rule significantly expanded the scope of federal jurisdiction over waterbodies (such as rivers, streams, canals, and wastewater treatment ponds), which could impact new generation projects and permitting and reporting requirements associated with the installation, expansion, and maintenance of transmission, distribution, and pipeline projects. The EPA and the Corps are expected to publish a final rule in 2019 to replace the 2015 WOTUS definition. The impact of any changes to the 2015 WOTUS rule will depend on the content of this final rule and the outcome of any legal challenges.

II-33

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

Coal Combustion Residuals

In 2015, the EPA finalized non-hazardous solid waste regulations for the disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments (ash ponds) at active generating power plants. In addition to the EPA's CCR Rule, the States of Alabama and Georgia have also finalized regulations regarding the handling of CCR within their respective states. The EPA's CCR Rule requires landfills and ash ponds to be evaluated against a set of performance criteria and potentially closed if minimum criteria are not met. Closure of existing landfills and ash ponds could require installation of equipment and infrastructure to manage CCR in accordance with the CCR Rule. Based on cost estimates for closure and monitoring of landfills and ash ponds pursuant to the CCR Rule, the Southern Company system recorded AROs for each CCR unit in 2015. As further analysis was performed and closure details were developed, the traditional electric operating companies have continued to periodically update these cost estimates, as discussed further below.

The EPA published certain amendments to the CCR Rule, which became effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to ash ponds that demonstrate compliance with all except two of the specified performance criteria.

On August 21, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision suggesting the EPA should regulate previously-excluded inactive ash ponds located at retired generation facilities and questioning both the ability of unlined ash ponds to continue operating no matter the performance criteria results and the classification of clay-lined landfills and ash ponds. These developments could impact the expected timing of the traditional electric operating companies' landfill and ash pond closure activities, but the extent of any impact will depend on the outcome of ongoing litigation, anticipated EPA rulemaking action to establish further guidance, and the outcome of any legal challenges.

In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related to the CCR Rule. The revised cost estimates were based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power, including at a plant jointly-owned by Mississippi Power. During the second quarter 2018, Alabama Power's management completed its analysis of these studies which indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology. As the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material.

In December 2018, Georgia Power recorded an increase of approximately $3.1 billion to its AROs related to the CCR Rule and the related state rule. During the second half of 2018, Georgia Power completed a strategic assessment 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. This assessment included engineering and constructability studies related to design assumptions for ash pond closures and advanced engineering methods. The results indicated that additional closure costs will be required to close these ash ponds, primarily due to changes in closure strategies, the estimated amount of ash to be excavated, and additional water management requirements necessary to support closure strategies. These factors also impact the estimated timing of future cash outlays.

The traditional electric operating companies expect to periodically update their ARO cost estimates. Absent continued recovery of ARO costs through regulated rates, Southern Company's results of operations, cash flows, and financial condition could be materially impacted. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 6 to the financial statements for additional information.

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

Nuclear Decommissioning

In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in an increase in Alabama Power's ARO liability of approximately $300 million. Amounts previously contributed to Alabama Power's external trust funds are currently projected to be adequate to meet the updated decommissioning obligations.

In December 2018, Georgia Power completed updated decommissioning cost site studies for Plant Hatch and Plant Vogtle Units 1 and 2. The estimated cost of decommissioning based on the studies resulted in an increase in Georgia Power's ARO liability of approximately $130 million. Georgia Power currently collects $4 million and $2 million annually in rates, which is used to fund external nuclear decommissioning trusts for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Georgia Power expects the Georgia PSC to review and adjust, if necessary, these amounts in the Georgia Power 2019 Base Rate Case.

See Note 6 to the financial statements for additional information.

II-34

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

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 Southern Company has recognized the estimated costs to clean up known impacted sites in its 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 have all received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance 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

On August 31, 2018, the EPA published a proposed rule known as the Affordable Clean Energy (ACE) Rule, which is intended to replace a regulation enacted in 2015 known as the Clean Power Plan (CPP), that would limit CO₂ emissions from existing fossil fuel-fired electric generating units. The CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule would require states to develop GHG unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of January 1, 2019, the Southern Company system has ownership interests in 40 fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to the Southern Company system is currently unknown and will depend on changes between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal challenges.

On December 20, 2018, the EPA published a proposed review of the Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units final rule (2015 NSPS rule). The EPA's final 2015 NSPS rule set standards of performance for new, modified, and reconstructed electric utility generating units which included stationary combustion turbines and fossil-fired steam boilers. This proposal reduces the stringency of the 2015 NSPS rule by not basing the new and reconstructed fossil-fired steam boiler and IGCC standards on partial carbon capture and sequestration. The impact of any changes to this rule will depend on the content of the final rule and the outcome of any legal challenges.

Additional domestic GHG policies may emerge in the future requiring the United States to transition to a lower GHG emitting economy. The Southern Company system has transitioned from an electric generating mix of 70% coal and 15% natural gas in 2007 to a mix of 30% coal and 46% natural gas in 2018, along with over 8,000 MWs of renewable resources. This transition has been supported in part by the Southern Company system retiring 4,226 MWs of coal- and oil-fired generating capacity since 2010 and converting 3,280 MWs of generating capacity from coal to natural gas since 2015. In addition, Southern Company Gas has replaced approximately 5,600 miles of bare steel and cast-iron pipe, resulting in removal of approximately 2.5 million metric tons of GHG from its natural gas distribution system since 1998. Based on ownership or financial control of facilities, the Southern Company system's 2017 GHG emissions (CO₂ equivalent) were approximately 98 million metric tons, with 2018 emissions estimated at 98 million metric tons. This equates to a reduction of 36% between 2007 and 2018. The 2018 estimates include GHG emissions attributable to each of Elizabethtown Gas, Elkton Gas, Florida City Gas, and the Florida Plants through the date of the applicable disposition. See Note 15 to the financial statements for additional information regarding disposition activities.

II-35

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

FERC Matters

Open Access Transmission Tariff

On May 10, 2018, AMEA and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requested that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through December 31, 2018, the estimated maximum potential refund is not expected to be material to Southern Company's results of operations or cash flows. The ultimate outcome of this matter cannot be determined at this time.

Southern Company Gas

Southern Company Gas' gas pipeline investments business is involved in two significant pipeline construction projects, the Atlantic Coast Pipeline (5% ownership) and the PennEast Pipeline (20% ownership), which received FERC approval in October 2017 and January 2018, respectively. Southern Company Gas' total capital expenditures, excluding AFUDC, at completion are expected to be between $350 million and $390 million for the Atlantic Coast Pipeline and $276 million for the PennEast Pipeline. These projects, along with Southern Company Gas' existing pipelines, are intended to provide diverse sources of natural gas supplies to customers, resolve current and long-term supply planning for new capacity, enhance system reliability, and generate economic development in the areas served.

The Atlantic Coast Pipeline has experienced challenges to its permits since construction began in 2018. During the third and fourth quarters 2018, a FERC stop work order, together with delays in obtaining permits necessary for construction and construction delays due to judicial actions, impacted the cost and schedule for the project. As a result, total project cost estimates have increased from between $6.0 billion and $6.5 billion to between $7.0 billion and $7.8 billion, excluding financing costs. Southern Company Gas' share of the total project costs is 5% and Southern Company Gas' investment at December 31, 2018 totaled $83 million. The operator of the joint venture currently expects to achieve a late 2020 in-service date for at least key segments of the Atlantic Coast Pipeline, while the remainder may extend into early 2021. Southern Company Gas has evaluated the recoverability of its investment and determined there was no impairment as of December 31, 2018. Abnormal weather, work delays (including due to judicial or regulatory action), and other conditions may result in additional cost or schedule modifications, which could result in an impairment of Southern Company Gas' investment and could have a material impact on Southern Company's financial statements.

The ultimate outcome of these matters cannot be determined at this time. See Notes 7 and 9 to the financial statements under "Southern Company Gas – Equity Method Investments" and "Guarantees," respectively, for additional information on these pipeline projects.

Regulatory Matters

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. See Note 2 to the financial statements under "Alabama Power" for additional information regarding Alabama Power's rate mechanisms and accounting orders.

Rate RSE

II-36

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

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. If Alabama Power's actual retail return is above the allowed WCER range, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCER range. Prior to January 2019, retail rates remained unchanged when the WCER range was between 5.75% and 6.21%.

On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments 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. Alabama Power plans 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 December 31, 2018, Alabama Power's equity ratio was approximately 47%.

The approved modifications to Rate RSE began for billings in January 2019. The modifications include reducing the top of the allowed WCER range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range.

Generally, 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%.

In conjunction with these modifications to Rate RSE, on May 8, 2018, Alabama Power consented to a moratorium on any upward adjustments under Rate RSE for 2019 and 2020 and will also return $50 million to customers through bill credits in 2019.

On November 30, 2018, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2019. Projected earnings were within the specified range; therefore, retail rates under Rate RSE remain unchanged for 2019.

At December 31, 2018, Alabama Power's retail return exceeded the allowed WCER range, which resulted in Alabama Power establishing a regulatory liability of $109 million for Rate RSE refunds. In accordance with an Alabama PSC order issued on February 5, 2019, Alabama Power will apply $75 million to reduce the Rate ECR under recovered balance and the remaining $34 million will be refunded to customers through bill credits in July through September 2019.

Rate CNP PPA

Alabama Power's retail rates, approved by the Alabama PSC, provide for adjustments under Rate CNP to recognize the placing of new generating facilities into retail service. Alabama Power may also recover retail costs associated with certificated PPAs under Rate CNP PPA. No adjustments to Rate CNP PPA occurred during the period 2016 through 2018 and no adjustment is expected in 2019.

In accordance with an accounting order issued in February 2017 by the Alabama PSC, Alabama Power reclassified $69 million of the December 31, 2016 Rate CNP PPA under recovered balance to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur no later than 2022.

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 a factor that is calculated annually. 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 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.

II-37

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur no later than 2022.

On November 30, 2018, Alabama Power submitted calculations associated with its cost of complying with environmental mandates, as provided under Rate CNP Compliance. The filing reflected a projected unrecovered retail revenue requirement for environmental compliance of approximately $205 million, which is being recovered in the billing months of January 2019 through December 2019.

Tax Reform Accounting Order

On May 1, 2018, the Alabama PSC approved an accounting order that authorized Alabama Power to defer the benefits of federal excess deferred income taxes associated with the Tax Reform Legislation for the year ended December 31, 2018 as a regulatory liability and to use up to $30 million of such deferrals to offset under recovered amounts under Rate ECR. The estimated deferrals for the year ended December 31, 2018 totaled approximately $63 million, subject to adjustment following the filing of the 2018 tax return, of which $30 million was used to offset the Rate ECR under recovered balance and $33 million is recorded in other regulatory liabilities, deferred on the balance sheet to be used for the benefit of customers as determined by the Alabama PSC at a future date. See Note 10 to the financial statements under "Current and Deferred Income Taxes" for additional information.

Environmental Accounting Order

Based on an order from the Alabama PSC (Environmental Accounting Order), Alabama Power is allowed 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 being amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement through Rate CNP Compliance. At December 31, 2018, this regulatory asset had a balance of $42 million. See "Environmental Matters – Environmental Laws and Regulations" herein for additional information regarding environmental regulations.

Subsequent to December 31, 2018, Alabama Power determined that Plant Gorgas Units 8, 9, and 10 (approximately 1,000 MWs) will be retired by April 15, 2019 due to the expected costs of compliance with federal and state environmental regulations. In accordance with the Environmental Accounting Order, approximately $740 million of net investment costs will be transferred to a regulatory asset at the retirement date and recovered over the affected units' remaining useful lives, as established prior to the decision to retire.

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 2013 ARP, which includes traditional base tariff rates, Demand-Side Management (DSM) tariffs, Environmental Compliance Cost Recovery (ECCR) tariffs, and Municipal Franchise Fee (MFF) tariffs. Georgia Power is scheduled to file a base rate case by July 1, 2019, which may continue or modify these 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 separate fuel cost recovery tariff. See Note 2 to the financial statements under "Georgia Power" for additional information.

Rate Plans

Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC in 2016, the 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power will retain its merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings will be shared on a 60/40 basis with customers; thereafter, all merger savings will be retained by customers. See Note 15 to the financial statements under "Southern Company Merger with Southern Company Gas" for additional information regarding the Merger.

There were no changes to Georgia Power's traditional base tariff rates, ECCR tariff, DSM tariffs, or MFF tariff in 2017 or 2018.

II-38

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

of the Georgia PSC under which Georgia Power's retail ROE for 2017 was stipulated to exceed 12.00% and Georgia Power will reduce certain regulatory assets by approximately $4 million in lieu of providing refunds to retail customers. In 2018, Georgia Power's retail ROE exceeded 12.00%, and Georgia Power accrued approximately $100 million to refund to retail customers, subject to review and approval by the Georgia PSC.

On April 3, 2018, the Georgia PSC approved the Georgia Power Tax Reform Settlement Agreement. Pursuant to the Georgia Power Tax Reform Settlement Agreement, to reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power will refund to customers a total of $330 million through bill credits. Georgia Power issued bill credits of approximately $130 million in 2018 and will issue bill credits of approximately $95 million in June 2019 and $105 million in February 2020. In addition, Georgia Power is deferring as a regulatory liability (i) the revenue equivalent of the tax expense reduction resulting from legislation lowering the Georgia state income tax rate from 6.00% to 5.75% in 2019 and (ii) the entire benefit of federal and state excess accumulated deferred income taxes, which is expected to total approximately $700 million at December 31, 2019. At December 31, 2018, the related regulatory liability balance totaled $610 million. The amortization of these regulatory liabilities is expected to be addressed in the Georgia Power 2019 Base Rate Case. If there is not a base rate case in 2019, customers will receive $185 million in annual bill credits beginning in 2020, with any additional federal and state income tax savings deferred as a regulatory liability, until Georgia Power's next base rate case.

To address some of the negative cash flow and credit quality impacts of the Tax Reform Legislation, the Georgia PSC also approved an increase in Georgia Power's retail equity ratio to the lower of (i) Georgia Power's actual common equity weight in its capital structure or (ii) 55%, until the Georgia Power 2019 Base Rate Case. At December 31, 2018, Georgia Power's actual retail common equity ratio (on a 13-month average basis) was approximately 55%. Benefits from reduced federal income tax rates in excess of the amounts refunded to customers will be retained by Georgia Power to cover the carrying costs of the incremental equity in 2018 and 2019.

Integrated Resource Plan

See "Environmental Matters" herein for additional information regarding proposed and final EPA rules and regulations, including revisions to ELG for steam electric power plants and additional regulations of CCR and CO₂.

In 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan (2016 IRP) including the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date was deferred for consideration in the Georgia Power 2019 Base Rate Case.

In the 2016 IRP, the Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. In March 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. The timing of recovery for costs incurred of approximately $50 million is expected to be determined by the Georgia PSC in the Georgia Power 2019 Base Rate Case.

On January 31, 2019, Georgia Power filed its triennial IRP (2019 IRP). The filing includes a request to decertify and retire Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) upon approval of the 2019 IRP.

In the 2019 IRP, Georgia Power requested approval to reclassify the remaining net book value of Plant Hammond Units 1 through 4 (approximately $520 million at December 31, 2018) upon retirement to a regulatory asset to be amortized ratably over a period equal to the applicable unit's remaining useful life through 2035. For Plant McIntosh Unit 1, Georgia Power requested approval to reclassify the remaining net book value (approximately $40 million at December 31, 2018) upon retirement to a regulatory asset to be amortized over a three-year period to be determined in the Georgia Power 2019 Base Rate Case. Georgia Power also requested approval to reclassify any unusable material and supplies inventory balances remaining at the applicable unit's retirement date to a regulatory asset for recovery over a period to be determined in the Georgia Power 2019 Base Rate Case.

The 2019 IRP also includes a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020, following the expiration of a wholesale PPA.

The 2019 IRP also includes details regarding ARO costs associated with ash pond and landfill closures and post-closure care. Georgia Power requested the timing and rate of recovery of these costs be determined by the Georgia PSC in the Georgia Power 2019 Base Rate Case. See "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 6 to the financial statements for additional information regarding Georgia Power's AROs.

II-39

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

Georgia Power also requested approval to issue two capacity-based requests for proposals (RFP). If approved, the first capacity-based RFP will seek resources that can provide capacity beginning in 2022 or 2023 and the second capacity-based RFP will seek resources that can provide capacity beginning in 2026, 2027, or 2028. Additionally, the 2019 IRP includes a request to procure an additional 1,000 MWs of renewable resources through a competitive bidding process. Georgia Power also proposed to invest in a portfolio of up to 50 MWs of battery energy storage technologies.

A decision from the Georgia PSC on the 2019 IRP is expected in mid-2019.

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

Storm Damage Recovery

Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operations and maintenance costs of damage from major storms to its transmission and distribution facilities. At December 31, 2018, the total balance in the regulatory asset related to storm damage was $416 million. During October 2018, Hurricane Michael caused significant damage to Georgia Power's transmission and distribution facilities. The incremental restoration costs related to this hurricane deferred in the regulatory asset for storm damage totaled approximately $115 million. Hurricanes Irma and Matthew also caused significant damage to Georgia Power's transmission and distribution facilities during September 2017 and October 2016, respectively. The incremental restoration costs related to Hurricanes Irma and Matthew deferred in Georgia Power's regulatory asset for storm damage totaled approximately $250 million. The rate of storm damage cost recovery is expected to be adjusted as part of the Georgia Power 2019 Base Rate Case and further adjusted in future regulatory proceedings as necessary. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements under "Georgia Power – Storm Damage Recovery" for additional information regarding Georgia Power's storm damage reserve.

Mississippi Power

Mississippi Power's retail base rates generally are set under the PEP, a rate plan approved by the Mississippi PSC. Two filings are made for each calendar year: the PEP projected filing, which is typically filed prior to the beginning of the year based on a projected revenue requirement, and the PEP lookback filing, which is filed after the end of the year and allows for review of the actual revenue requirement compared to the projected filing.

On February 7, 2018, Mississippi Power revised its annual projected PEP filing for 2018 to reflect the impacts of the Tax Reform Legislation. The revised filing requested an increase of $26 million in annual revenues, based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%. On July 27, 2018, Mississippi Power and the MPUS entered into a settlement agreement with respect to the 2018 PEP filing and all unresolved PEP filings for prior years (PEP Settlement Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement became effective with the first billing cycle of September 2018. The PEP Settlement Agreement provides for an increase of approximately $21.6 million in annual base retail revenues, which excludes certain compensation costs contested by the MPUS, as well as approximately $2 million which was subsequently approved for recovery through Mississippi Power's 2018 Energy Efficiency Cost Rider.

Pursuant to the PEP Settlement Agreement, PEP proceedings are suspended until after the conclusion of the Mississippi Power 2019 Base Rate Case and Mississippi Power is not required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolved all open PEP filings with no change to customer rates.

Kemper County Energy Facility

II-40

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

2020 through 2023. Mississippi Power is currently evaluating its options regarding the final disposition of the CO₂pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. If Mississippi Power ultimately decides to remove the CO₂pipeline, the cost of removal could have a material impact on Southern Company's financial statements. The ultimate outcome of these matters cannot be determined at this time.

The combined cycle and associated common facilities portions of the Kemper County energy facility were dedicated as Plant Ratcliffe on April 27, 2018.

For additional information on the Kemper County energy facility, see Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility."

Reserve Margin Plan

On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP), as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costs related to the Kemper County energy facility. Under the RMP, Mississippi Power proposed alternatives that would reduce its reserve margin, with the most economic of the alternatives being the two-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. A decision by the Mississippi PSC that does not include recovery of the remaining book value of any generating units retired could have a material impact on Southern Company's financial statements. The ultimate outcome of this matter cannot be determined at this time.

Government Grants

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. Through December 31, 2018, Mississippi Power received total DOE grants of $387 million, of which $382 million reduced the construction costs of the Kemper County energy facility and $5 million reimbursed Mississippi Power for expenses associated with DOE reporting. On December 12, 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the grants received. Mississippi Power and the DOE are currently in discussions regarding the requested closeout and property disposition, which may require payment to the DOE for a portion of certain property that is to be retained by Mississippi Power. The ultimate outcome of this matter cannot be determined at this time; however, it could have a significant impact on Southern Company's financial statements.

Southern Company Gas

The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies for the rates charged to their customers and other matters.

The natural gas market for Atlanta Gas Light was deregulated in 1997. Accordingly, Marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. Atlanta Gas Light earns revenue for its distribution services by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC and adjusted periodically.

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. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on revenues or net income, but will affect cash flows. In addition to natural gas cost recovery mechanisms, there are other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs, as well as environmental remediation and energy efficiency plans. See Note 1 to the financial statements under "Cost of Natural Gas" for additional information.

II-41

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

Infrastructure Replacement Programs and Capital Projects

In addition to capital expenditures recovered through base rates by each of the natural gas distribution utilities, Nicor Gas and Virginia Natural Gas have separate rate riders that provide timely recovery of capital expenditures for specific infrastructure replacement programs. These infrastructure replacement programs and capital projects are risk-based and designed to update and replace cast iron, bare steel, and mid-vintage plastic materials or expand the natural gas distribution systems to improve reliability and meet operational flexibility and growth. The total expected investment under the infrastructure replacement programs for 2019 is $408 million. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" for additional information.

Rate Proceedings

On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation. The Georgia PSC maintained Atlanta Gas Light's previously authorized earnings band based on a ROE between 10.55% and 10.95% and increased the allowed equity ratio by 4% to an equity ratio of 55% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. Additionally, Atlanta Gas Light is required to file a traditional base rate case on or before June 1, 2019 for rates effective January 1, 2020.

On January 31, 2018, the Illinois Commission approved a $137 million increase in Nicor Gas' annual base rate revenues, including $93 million related to the recovery of investments under Nicor Gas' infrastructure program, effective February 8, 2018, based on a ROE of 9.8%.

On May 2, 2018, the Illinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately $44 million in annual base rate revenues became effective May 5, 2018. Nicor Gas' previously-authorized capital structure and ROE of 9.80% were not addressed in the rehearing and remain unchanged. On November 9, 2018, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $230 million increase in annual base rate revenues. The requested increase is based on a projected test year for the 12-month period ending September 30, 2020, a ROE of 10.6%, and an increase in the equity ratio from 52.0% to 54.0% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. The Illinois Commission is expected to rule on the requested increase within the 11-month statutory time limit, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues 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 revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.

See Note 1 to the financial statements under "Revenues" and Note 2 to the financial statements under "Alabama Power – Rate ECR," "Georgia Power – Fuel Cost Recovery," and "Mississippi Power – Fuel Cost Recovery" for additional information.

Construction Program

Overview

The subsidiary companies of Southern Company 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, adding environmental modifications to certain existing units, expanding and improving the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. 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 15 to the financial statements under "Southern Power" for additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy facilities and Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement

II-42

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

Programs and Capital Projects" for additional information regarding infrastructure improvement programs at the natural gas distribution utilities.

The Southern Company system's construction program is currently estimated to total approximately $8.0 billion, $7.7 billion, $6.7 billion, $6.3 billion, and $6.0 billion for 2019, 2020, 2021, 2022, and 2023, respectively. The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs). See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.

Nuclear Construction

In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired in July 2017 when Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement. Under the Vogtle Services Agreement, 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. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.

Cost and Schedule



	(in billions)
Base project capital cost forecast^(a)(b)	$	8.0
Construction contingency estimate	0.4
Total project capital cost forecast^(a)(b)	8.4
Net investment as of December 31, 2018^(b)	(4.6		)
Remaining estimate to complete^(a)	$	3.8


(a)	Excludes financing costs expected to be capitalized through AFUDC of approximately $315 million.


(b)	Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds.

II-43

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

required engineering changes, of plant systems, structures, and components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers must be retained and deployed.

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 August 31, 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 the vote to continue construction, Georgia Power entered into (i) the Vogtle Owner Term Sheet with the other Vogtle Owners and MEAG's wholly-owned subsidiaries 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, and (ii) the MEAG Term Sheet with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 (Project J) under certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet (MEAG Funding Agreement). On February 18, 2019, Georgia Power, the other Vogtle Owners, and MEAG'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).

II-44

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

II-45

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

the holders of more than 50% of the ownership interests vote in favor of continuing construction (Majority Voting Owners). In such a case, the Vogtle Owners (i) have agreed to negotiate in good faith towards the resumption of the project, (ii) if no agreement is reached during such 30-day period, the project will be cancelled, and (iii) in the event of such a cancellation, the Majority Voting Owners will be obligated to reimburse any other Vogtle Owner for the incremental costs it incurred during such 30-day negotiation period.

Purchase of PTCs During Commercial Operation

Potential Funding to MEAG Project J

Under the terms of the MEAG Funding Agreement, Georgia Power may cancel the project in lieu of providing funding in the form of advances or PTC purchases.

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, 2018, Georgia Power had recovered approximately $1.9 billion of financing costs. Financing costs related to capital costs above $4.418 billion will be recovered through AFUDC; however, Georgia Power will not record 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 December 18, 2018, the Georgia PSC approved Georgia Power's request to increase the NCCR tariff by $88 million annually, effective January 1, 2019.

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.

II-46

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

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, which included a recommendation to continue construction with Southern Nuclear as project manager and Bechtel serving as the primary construction contractor, 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 amounts 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 prudence decisions on cost recovery will be made at a later date, 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 upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. 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 $100 million, $25 million, and $20 million in 2018, 2017, and 2016, respectively, and are estimated to have negative earnings impacts of approximately $75 million in 2019 and an aggregate of approximately $615 million from 2020 to 2022.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. (GIPL) and Partnership for Southern Equity, Inc. (PSE) filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. On March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's decision and denial of Georgia Watch's motion for reconsideration. On December 21, 2018, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. On January 9, 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. Georgia Power believes the appeal has no merit; however, an adverse outcome in the appeal combined with subsequent adverse action by the Georgia PSC could have a material impact on Southern Company's results of operations, financial condition, and liquidity.

II-47

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

tax) in the second quarter 2018, which includes the total increase in the base capital cost forecast and construction contingency estimate.

On August 31, 2018, Georgia Power filed its nineteenth VCM report with the Georgia PSC, which requested approval of $578 million of construction capital costs incurred from January 1, 2018 through June 30, 2018. On February 19, 2019, the Georgia PSC approved the nineteenth VCM, but deferred approval of $51.6 million of expenditures related to Georgia Power's portion of an administrative claim filed in the Westinghouse bankruptcy proceedings. Through the nineteenth VCM, the Georgia PSC has approved total construction capital costs incurred through June 30, 2018 of $5.4 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds). In addition, the staff of the Georgia PSC requested, and Georgia Power agreed, to file its twentieth VCM report concurrently with the twenty-first VCM report by August 31, 2019.

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

DOE Financing

At December 31, 2018, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In September 2018, the DOE extended the conditional commitment to March 31, 2019. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and conditions to borrowing.

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

Income Tax Matters

Federal Tax Reform Legislation

In December 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduced the federal corporate income tax rate to 21%, retained normalization provisions for public utility property and existing renewable energy incentives, and repealed the corporate alternative minimum tax. In addition, under the Tax Reform Legislation, NOLs generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income of the subsequent tax year. The projected reduction of the consolidated income tax liability resulting from the tax rate reduction also delays the expected utilization of existing tax credit carryforwards.

Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provided for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes and their application under GAAP, Southern Company considered all amounts recorded in the financial statements as a result of the Tax Reform Legislation "provisional" as discussed in SAB 118 and subject to revision prior to filing its 2017 tax return in the fourth quarter 2018. Southern Company recognized tax benefits of $30 million and $264 million in 2018 and 2017, respectively, for a total net tax benefit of $294 million as a result of the Tax Reform Legislation. In addition, in total, Southern Company recorded a $417 million decrease in regulatory assets and a $6.2 billion increase in regulatory liabilities as a result of the Tax Reform Legislation and $16 million of stranded excess deferred tax balances in AOCI at December 31, 2017 were adjusted through retained earnings in 2018. As of December 31, 2018, Southern Company considered the measurement of impacts from the Tax Reform Legislation on deferred income tax assets and liabilities, primarily due to the impact of the reduction of the corporate income tax rate, to be complete.

However, the IRS continues to issue regulations that provide further interpretation and guidance on the law and each state's adoption of the provisions contained in the Tax Reform Legislation remains uncertain. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and each state's regulatory commission. The ultimate impact of these matters cannot be determined at this time. See Note 2 to the financial statements for additional information regarding the traditional electric operating companies' and the natural gas distribution utilities' rate filings, including

II-48

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

amounts returned to customers during 2018, to reflect the impacts of the Tax Reform Legislation. Also see FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 10 to the financial statements under "Current and Deferred Income Taxes" for additional information.

Bonus Depreciation

Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the PATH Act. The PATH Act allowed for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. Based on provisional estimates, bonus depreciation is expected to result in positive cash flows of approximately $300 million for the 2018 tax year and approximately $130 million for the 2019 tax year. The ultimate outcome of this matter cannot be determined at this time.

Tax Credits

The Tax Reform Legislation retained the renewable energy incentives that were included in the PATH Act. The PATH Act allows for 30% ITC for solar projects that commence construction by December 31, 2019; 26% ITC for solar projects that commence construction in 2020; 22% ITC for solar projects that commence construction in 2021; and a permanent 10% ITC for solar projects that commence construction on or after January 1, 2022. In addition, the PATH Act allows for 100% PTC for wind projects that commenced construction in 2016; 80% PTC for wind projects that commenced construction in 2017; 60% PTC for wind projects that commenced construction in 2018 and 40% PTC for wind projects that commence construction in 2019. Wind projects commencing construction after 2019 will not be entitled to any PTCs. Southern Company has received ITCs and PTCs in connection with investments in solar, wind, and biomass facilities primarily at Southern Power and Georgia Power. See Note 1 to the financial statements under "Income Taxes" and Note 10 to the financial statements under "Current and Deferred Income Taxes – Tax Credit Carryforwards" for additional information regarding the utilization and amortization of credits and the tax benefit related to basis differences.

Other Matters

Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of other natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings 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 would have a material effect on Southern Company's financial statements. See Notes 2 and 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

Litigation

In January 2017, a putative securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In June 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. In July 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition in September 2017. On March 29, 2018, the U.S. District Court for the Northern District of Georgia, Atlanta Division, issued an order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers of Southern Company and Mississippi Power and dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. On April 26, 2018, the

II-49

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. On August 10, 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal.

In February 2017, Jean Vineyard filed a shareholder derivative lawsuit and, in May 2017, Judy Mesirov filed a shareholder derivative lawsuit, each 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 officers, and certain former Mississippi Power officers. In August 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. Each plaintiff seeks 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. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On April 25, 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.

In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia that names as defendants Southern Company, certain of its directors, certain of its 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. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On May 4, 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.

On May 18, 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in September 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. In the first quarter 2019, Mississippi Power and Southern Company filed motions to dismiss.

Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.

Investments in Leveraged Leases

A subsidiary of Southern Holdings has several leveraged lease agreements, with original terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. Southern Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows. See Note 1 to the financial statements under "Leveraged Leases" for additional information.

The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. In 2017, the financial and operational performance of one of the lessees 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 to the Southern Holdings subsidiary beginning in June 2018. As a result of operational improvements in 2018, the 2018 lease payments were paid in full. However, operational issues and the resulting cash liquidity challenges persist and significant concerns continue regarding the lessee's ability to make the remaining semi-annual lease payments. These operational challenges may also impact the expected residual value of the assets at the end of the lease term in 2047. If any future lease payment is 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 from the

II-50

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable, which would result in a reduction in net income of approximately $86 million after tax based on the lease receivable balance at December 31, 2018. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired at December 31, 2018. 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. The ultimate outcome of this matter cannot be determined at this time.

Mississippi Power

Southern Power

On January 29, 2019, Pacific Gas & Electric Company (PG&E) filed petitions to reorganize under Chapter 11 of the U.S. Bankruptcy Code. Southern Power, together with its noncontrolling partners, owns four solar facilities where PG&E is the energy off-taker for approximately 207 MWs of capacity under long-term PPAs. PG&E is also the transmission provider for these facilities and two of Southern Power's other solar facilities. Southern Power has evaluated the recoverability of its investments in these solar facilities under various scenarios, including selling the related energy into the competitive markets, and has concluded they are not impaired. At December 31, 2018, Southern Power had outstanding accounts receivables due from PG&E of $1 million related to the PPAs and $36 million related to the transmission interconnections. Southern Company does not expect a material impact to its financial statements if, as a result of the bankruptcy proceedings, PG&E does not perform in accordance with the PPAs or the terms of the PPAs are renegotiated; however, the ultimate outcome of this matter cannot be determined at this time.

Southern Company Gas

A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At December 31, 2018, the facility's property, plant, and equipment had a net book value of $109 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.

The cavern continues to maintain its pressures and overall structural integrity. Southern Company Gas intends to monitor the cavern and comply with the Louisiana DNR order through 2020 and place the cavern back in service in 2021. These events were considered in connection with Southern Company Gas' annual long-lived asset impairment analysis, which determined there was no impairment as of December 31, 2018. Any changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Notes 1, 5, and 6 to the financial statements. In the application of these policies, certain estimates are made that may

II-51

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

have a material impact on Southern Company's results of operations and related disclosures. 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.

Utility Regulation

Southern Company's traditional electric operating companies and natural gas distribution utilities, which collectively comprised approximately 85% of Southern Company's total operating revenues for 2018, 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 has a further effect on Southern Company's 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 Southern Company's results of operations and financial condition than they would on a non-regulated company. See Note 15 to the financial statements for information regarding the sale of Gulf Power and three of Southern Company Gas' natural gas distribution utilities.

As reflected in Note 2 to the financial statements under "Southern Company – Regulatory Assets and Liabilities," 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 Southern Company's financial statements.

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

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 December 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) 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; (iii) Georgia Power would have the burden of proof to show that any capital costs above $5.68 billion were prudent; (iv) 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 (v) prudence decisions would be made 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.

In the second quarter 2018, Georgia Power revised its base cost forecast and estimated contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for a total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds). 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 did not seek rate recovery for the $0.7 billion increase in costs included in the current base capital cost forecast in the nineteenth VCM report. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate 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

II-52

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018.

Georgia Power's revised cost estimate reflects an expected in-service date of November 2021 for Unit 3 and November 2022 for Unit 4.

The ultimate outcome of these matters cannot be determined at this time. Any extension of the in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4 is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, 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 Southern Company's results of operations and cash flows, Southern Company considers 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

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, 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 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 no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. Certain deductions and credits can be limited at the consolidated or combined level resulting in NOL and tax credit carryforwards that would not otherwise result on a stand-alone basis. Utilization of NOL and tax credit carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of

II-53

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

Southern Company's current financial position and result 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 utilize various formulas to calculate the apportionment of taxable income, primarily using sales, assets, or payroll within the jurisdiction compared to the consolidated totals. In addition, each state varies as to whether a stand-alone, combined, or unitary filing methodology is required. 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 Southern Company's financial statements.

Given the significant judgment involved in estimating NOL and tax credit carryforwards and multi-state apportionments for all subsidiaries, Southern Company considers federal and state deferred income tax liabilities and assets to be critical accounting estimates.

Asset Retirement Obligations

AROs are computed as the fair 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.

The liability for AROs primarily relates to facilities that are subject to the CCR Rule and the related state rules, principally ash ponds, and the decommissioning of the Southern Company system's nuclear facilities – Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2. In addition, the Southern Company system has AROs related to various landfill sites, asbestos removal, mine reclamation, land restoration related to solar and wind facilities, and disposal of polychlorinated biphenyls in certain transformers.

The traditional electric operating companies and Southern Company Gas also have identified 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 as 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 retirement obligation.

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. During 2018, Alabama Power and Georgia Power recorded increases of approximately $1.2 billion and $3.1 billion, respectively, to their AROs related to the disposal of CCR and increases of approximately $300 million and $130 million, respectively, to their AROs related to updated nuclear decommissioning cost site studies. Alabama Power's CCR-related update resulted from feasibility studies performed on ash ponds in use at the plants it operates, which indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology. Georgia Power's CCR-related update resulted from a strategic assessment which indicated additional closure costs will be required to close its ash ponds, primarily due to changes in closure strategies, the estimated amount of ash to be excavated, and additional water management requirements necessary to support closure strategies. The traditional electric operating companies expect to periodically update their ARO cost estimates. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 6 to the financial statements for additional information.

Given the significant judgment involved in estimating AROs, Southern Company considers the liabilities for AROs to be critical accounting estimates.

Pension and Other Postretirement Benefits

Southern Company's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include

II-54

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

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 Southern Company believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefit costs and obligations.

Key elements in determining Southern Company's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on Southern Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. Southern Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to Southern Company's target asset allocation. For purposes of determining its liability 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 following table illustrates the sensitivity to changes in Southern Company's long-term assumptions with respect to the discount rate, salary increases, and the long-term rate of return on plan assets:



Change in Assumption	Increase/(Decrease) in Total Benefit Expense for 2019	Increase/(Decrease) in Projected Obligation for Pension Plan at December 31, 2018	Increase/(Decrease) in Projected Obligation for Other Postretirement Benefit Plans at December 31, 2018
	(in millions)
25 basis point change in discount rate	$37/$(36)	$434/$(411)	$50/$(48)
25 basis point change in salaries	$11/$(11)	$105/$(101)	$–/$–
25 basis point change in long-term return on plan assets	$33/$(33)	N/A	N/A

N/A – Not applicable

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

Goodwill and Other Intangible Assets

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. Southern Company recognizes goodwill as of the acquisition date, as a residual over the fair values of the identifiable net assets acquired. Goodwill is tested for impairment 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. Primarily as a result of the acquisitions of Southern Company Gas and PowerSecure in 2016, goodwill totaled approximately $5.3 billion at December 31, 2018. As a result of the Southern Company Gas Dispositions, goodwill was reduced by $910 million during 2018. In addition, Southern Company Gas recorded a $42 million goodwill impairment charge in 2018 in contemplation of the sale of Pivotal Home Solutions.

Definite-lived intangible assets acquired are amortized over the estimated useful lives of the respective assets to reflect the pattern in which the economic benefits of the intangible assets are consumed. Whenever events or changes in circumstances indicate that the carrying amount of the intangible assets may not be recoverable, the intangible assets will be reviewed for impairment. Primarily as a result of the acquisitions of Southern Company Gas and PowerSecure and PPA fair value adjustments resulting from Southern Power's acquisitions, other intangible assets, net of amortization totaled approximately $613 million at December 31, 2018.

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 Southern Company'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, Southern Company considers 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 Southern Company's goodwill and other intangible assets and Note 15 to the financial statements for additional

II-55

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

information related to Southern Company's 2016 acquisitions of Southern Company Gas and PowerSecure, as well as the Southern Company Gas Dispositions.

Derivatives and Hedging Activities

Derivative instruments are recorded on the balance sheets as either assets or liabilities measured at their fair value, unless the transactions qualify for the normal purchases or normal sales scope exception and are instead subject to traditional accrual accounting. For those transactions that do not qualify as a normal purchase or normal sale, changes in the derivatives' fair values are recognized concurrently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, derivative gains and losses offset related results of the hedged item in the income statement in the case of a fair value hedge, or gains and losses are deferred in OCI until the hedged transaction affects earnings in the case of a cash flow hedge. Certain subsidiaries of Southern Company enter into energy-related derivatives that are designated as regulatory hedges where gains and losses are initially recorded as regulatory liabilities and assets and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through billings to customers.

Southern Company uses derivative instruments to reduce the impact to the results of operations due to the risk of changes in the price of natural gas, to manage fuel hedging programs per guidelines of state regulatory agencies, and to mitigate residual changes in the price of electricity, weather, interest rates, and foreign currency exchange rates. The fair value of commodity derivative instruments used to manage exposure to changing prices reflects the estimated amounts that Southern Company would receive or pay to terminate or close the contracts at the reporting date. To determine the fair value of the derivative instruments, Southern Company utilizes market data or assumptions that market participants would use in pricing the derivative asset or liability, including assumptions about risk and the risks inherent in the inputs of the valuation technique.

Southern Company classifies derivative assets and liabilities based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The determination of the fair value of the derivative instruments incorporates various required factors. These factors include:


•	the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit);


•	events specific to a given counterparty; and


•	the impact of Southern Company's nonperformance risk on its liabilities.

Given the assumptions used in pricing the derivative asset or liability, Southern Company considers the valuation of derivative assets and liabilities a critical accounting estimate. See FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein and Note 14 to the financial statements for more information.

Contingent Obligations

Southern Company is subject to a number of federal and state laws and regulations as well as other factors and conditions that subject it 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. Southern Company periodically evaluates its exposure to such risks and records 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 Southern Company's results of operations, cash flows, or financial condition.

Recently Issued Accounting Standards

See Note 1 to the financial statements under "Recently Adopted Accounting Standards" for additional information.

In 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Southern Company adopted the new standard effective January 1, 2019.

Southern Company elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby the requirements of ASU 2016-02 are applied on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Southern Company elected the package of practical expedients provided by ASU 2016-02

II-56

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Southern Company 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. Southern Company also made accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and combined lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.

The Southern Company system completed the implementation of a new application to track and account for its leases and updated its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. The Southern Company system completed its lease inventory and determined its most significant leases involve PPAs, real estate, and communication towers where certain of Southern Company's subsidiaries are the lessee and PPAs where certain of Southern Company's subsidiaries are the lessor. In the first quarter 2019, the adoption of ASU 2016-02 resulted in recording lease liabilities and right-of-use assets on Southern Company's balance sheet each totaling approximately $2.0 billion, with no impact on Southern Company's statement of income.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Earnings in all periods presented were negatively affected by charges associated with plants under construction; however, Southern Company's financial condition remained stable at December 31, 2018.

The Southern Company system's cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. The Southern Company system's capital expenditures and other investing activities include investments to meet projected long-term demand requirements, including to build new electric generation facilities, to maintain existing electric generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing electric generating units and closures of ash ponds, to expand and improve electric transmission and distribution facilities, to update and expand natural gas distribution systems, and for restoration following major storms. Operating cash flows provide a substantial portion of the Southern Company system's cash needs. For the three-year period from 2019 through 2021, Southern Company's projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. Southern Company plans to finance future cash needs in excess of its operating cash flows primarily by accessing borrowings from financial institutions and through debt and equity issuances in the capital markets. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.

Southern Company's investments in the qualified pension plans and the nuclear decommissioning trust funds decreased in value at December 31, 2018 as compared to December 31, 2017. No contributions to the qualified pension plan were made for the year ended December 31, 2018 and no mandatory contributions to the qualified pension plans are anticipated during 2019. See "Contractual Obligations" herein and Notes 6 and 11 to the financial statements under "Nuclear Decommissioning" and "Pension Plans," respectively, for additional information.

Net cash provided from operating activities in 2018 totaled $6.9 billion, an increase of $0.6 billion from 2017. The increase in net cash provided from operating activities was primarily due to the timing of vendor payments and increased fuel cost recovery. Net cash provided from operating activities in 2017 totaled $6.4 billion, an increase of $1.5 billion from 2016. Significant changes in operating cash flow for 2017 as compared to 2016 included increases of $1.2 billion related to operating activities of Southern Company Gas, which was acquired on July 1, 2016, and $1.0 billion related to voluntary contributions to the qualified pension plan in 2016, partially offset by the timing of vendor payments.

Net cash used for investing activities in 2018, 2017, and 2016 totaled $5.8 billion, $7.2 billion, and $20.0 billion, respectively. The cash used for investing activities in 2018 was primarily due to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities and capital expenditures for Southern Company Gas' infrastructure replacement programs, partially offset by proceeds from the sale transactions described in Note 15 to the financial statements. The cash used for investing activities in 2017 was primarily due to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, capital expenditures for Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions. The cash used for investing activities in 2016 was primarily due to the closing of the Merger, the acquisition of PowerSecure, Southern Company Gas' investment in SNG, the traditional electric operating companies' construction of electric generation, transmission, and distribution facilities and

II-57

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

installation of equipment at electric generating facilities to comply with environmental standards, and Southern Power's acquisitions and construction of renewable facilities and a natural gas facility.

Net cash used for financing activities totaled $1.8 billion in 2018 primarily due to net redemptions and repurchases of long-term debt, common stock dividend payments, and a decrease in commercial paper borrowings, partially offset by net issuances of short-term bank debt, proceeds from Southern Power's sales of non-controlling equity interests in entities indirectly owning substantially all of its solar facilities and eight of its wind facilities, and the issuance of common stock. Net cash provided from financing activities totaled $1.0 billion in 2017 primarily due to net issuances of long-term and short-term debt, partially offset by common stock dividend payments. Net cash provided from financing activities totaled $15.7 billion in 2016 primarily due to issuances of long-term debt and common stock associated with completing the Merger and funding the subsidiaries' continuous construction programs, Southern Power's acquisitions, and Southern Company Gas' investment in SNG, partially offset by redemptions of long-term debt and common stock dividend payments. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes in 2018 included the reclassification of $5.7 billion and $3.3 billion in total assets and liabilities held for sale, respectively, primarily associated with Gulf Power, as well as decreases of $3.0 billion and $0.4 billion in total assets and liabilities, respectively, associated with the sales described in Note 15 to the financial statements under "Southern Power" and "Southern Company Gas." Also see Note 15 to the financial statements under "Southern Company's Sale of Gulf Power" and "Assets Held for Sale" for additional information. After adjusting for these changes, other significant balance sheet changes included an increase of $7.1 billion in total property, plant, and equipment primarily related to the $4.7 billion increase in AROs at Alabama Power and Georgia Power, as well as the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities and Southern Company Gas' capital expenditures for infrastructure replacement programs, partially offset by the second quarter 2018 charge related to the construction of Plant Vogtle Units 3 and 4; a decrease of $3.1 billion in long-term debt (including amounts due within one year) resulting from the repayment of long-term debt; an increase of $3.0 billion in noncontrolling interests at Southern Power as a result of sales of interests in entities indirectly owning substantially all of its solar facilities and eight of its wind facilities; and an increase of $1.9 billion in other regulatory assets, deferred primarily related to AROs at Georgia Power. See Notes 2 and 15 to the financial statements under "Georgia Power – Nuclear Construction" and "Southern Power – Sales of Renewable Facility Interests," respectively, as well as Notes 6 and 8 to the financial statements and "Financing Activities" herein for additional information.

At the end of 2018, the market price of Southern Company's common stock was $43.92 per share (based on the closing price as reported on the NYSE) and the book value was $23.91 per share, representing a market-to-book value ratio of 184%, compared to $48.09, $23.99, and 201%, respectively, at the end of 2017.

Southern Company's consolidated ratio of common equity to total capitalization plus short-term debt was 32.5% and 31.5% at December 31, 2018 and 2017, respectively. See Note 8 to the financial statements for additional information.

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 in the capital markets. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of additional equity and debt issuances in 2019, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements and will depend upon prevailing market conditions and other factors. See "Capital Requirements and Contractual Obligations" herein for additional information.

Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, borrowings from financial institutions, and equity contributions or loans from Southern Company. Southern Power also plans to utilize tax equity partnership contributions, as well as funds resulting from its pending sale of Plant Mankato. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See Note 15 to the financial statements under "Southern Power – Sales of Natural Gas Plants" herein for additional information.

In addition, in 2014, Georgia Power entered into the Loan Guarantee Agreement with the DOE, 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. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. At December 31, 2018, Georgia Power had borrowed $2.6 billion under

II-58

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

the FFB Credit Facility. In July 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.

In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on March 31, 2019, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and additional conditions to borrowing. Also see Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

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 and certain of its 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 continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

Southern Company, each traditional electric operating company, and Southern Power generally obtain financing separately without credit support from any affiliate. 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.

In addition, 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. 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.

See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information.

At December 31, 2018, Southern Company's current liabilities exceeded current assets by $4.7 billion, primarily due to $3.2 billion of long-term debt that is due within one year (including approximately $1.3 billion at the parent company, $0.2 billion at Alabama Power, $0.6 billion at Georgia Power, $0.6 billion at Southern Power, and $0.4 billion at Southern Company Gas) and $2.9 billion of notes payable (including approximately $1.8 billion at the parent company, $0.3 billion at Georgia Power, $0.1 billion at Southern Power, and $0.7 billion at Southern Company Gas). Subsequent to December 31, 2018, using proceeds from the sale of Gulf Power, the Southern Company parent entity repaid $0.7 billion of its long-term debt due within one year and all $1.8 billion of its notes payable at December 31, 2018. See "Financing Activities" herein for additional information. To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.

II-59

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

At December 31, 2018, Southern Company and its subsidiaries had approximately $1.4 billion of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2018 were as follows:



	Expires										Executable Term Loans				Expires Within One Year
Company	2019		2020		2022		Total		Unused^(d)		One Year		Two Years		Term Out		No Term Out
	(in millions)
Southern Company^(a)	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—	$	—	$	—	$	—
Alabama Power	33		500		800		1,333		1,333		—		—		—		33
Georgia Power	—		—		1,750		1,750		1,736		—		—		—		—
Mississippi Power	100		—		—		100		100		—		—		—		100
Southern Power^(b)	—		—		750		750		727		—		—		—		—
Southern Company Gas^(c)	—		—		1,900		1,900		1,895		—		—		—		—
Other	30		—		—		30		30		—		—		—		30
Southern Company Consolidated^(e)	$	163	$	500	$	7,200	$	7,863	$	7,820	$	—	$	—	$	—	$	163


(a)	Represents the Southern Company parent entity.


(b)	Does not include Southern Power Company's $120 million continuing letter of credit facility for standby letters of credit expiring in 2021, of which $17 million was unused at December 31, 2018. Southern Power's subsidiaries are not parties to its bank credit arrangement.

(c)

Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of this arrangement. Southern Company Gas' committed credit arrangement also includes $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to this multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.


(d)	Amounts used are for letters of credit.


(e)	Excludes $280 million of committed credit arrangements of Gulf Power, which was sold on January 1, 2019. See Note 15 to the financial statements under "Southern Company's Sale of Gulf Power" for additional information.

See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information.

Most of these bank credit arrangements, as well as the term loan arrangements of Alabama Power and Southern Power Company, contain covenants that limit debt levels and contain cross-acceleration or 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 the applicable borrower 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. At December 31, 2018, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

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.

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 Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support at December 31, 2018 was approximately $1.6 billion, which included $82 million related to Gulf Power. In addition, at December 31, 2018, the traditional electric operating companies had approximately $403 million of revenue bonds outstanding that are required to be remarketed within the next 12 months, which included $58 million related to Gulf Power. See Note 15 to the financial statements under "Southern Company's Sale of Gulf Power" for information regarding the sale of Gulf Power on January 1, 2019. Subsequent to December 31, 2018, Georgia Power redeemed approximately $108 million of obligations related to outstanding variable rate pollution control revenue bonds.

Southern Company, Alabama Power, Georgia Power, Southern Power Company, Southern Company Gas, 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. Short-term borrowings are included in notes payable in the balance sheets.

II-60

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

Details of short-term borrowings were as follows:



	Short-term Debt at the End of the Period				Short-term Debt During the Period ^(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
December 31, 2018:
Commercial paper	$	1,064	3.0	%	$	1,655	2.3	%	$	3,042
Short-term bank debt	1,851		3.1	%	1,722		2.9	%	2,504
Total	$	2,915	3.1	%	$	3,377	2.6	%
December 31, 2017:
Commercial paper	$	1,832	1.8	%	$	2,117	1.3	%	$	2,946
Short-term bank debt	607		2.3	%	555		2.1	%	1,020
Total	$	2,439	1.9	%	$	2,672	1.5	%
December 31, 2016:
Commercial paper	$	1,909	1.1	%	$	976	0.8	%	$	1,970
Short-term bank debt	123		1.7	%	176		1.7	%	500
Total	$	2,032	1.1	%	$	1,152	1.1	%


(*)	Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2018, 2017, and 2016.

In addition to the short-term borrowings of Southern Power Company included in the table above, at December 31, 2016, Southern Power Company subsidiaries assumed credit agreements (Project Credit Facilities) with the acquisition of certain solar facilities, which were non-recourse to Southern Power Company, the proceeds of which were used to finance project costs related to such solar facilities. The Project Credit Facilities were fully repaid in January 2017. For the year ended December 31, 2016, the Project Credit Facilities had a maximum amount outstanding of $828 million and an average amount outstanding of $566 million at a weighted average interest rate of 2.1% and had total amounts outstanding of $209 million at a weighted average interest rate of 2.1% at December 31, 2016.

Southern Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank term loans, and operating cash flows.

Financing Activities

During 2018, Southern Company issued approximately 11.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $442 million.

In addition, during the third and fourth quarters 2018, Southern Company issued a total of approximately 12.1 million and 2.5 million shares, respectively, of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of approximately $540 million and $108 million, respectively, net of $5 million and $1 million in commissions, respectively.

II-61

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the year ended December 31, 2018:



Company	Senior Note Issuances		Senior Note Maturities, Redemptions, and Repurchases		Revenue Bond Issuances and Reofferings of Purchased Bonds		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Issuances		Other Long-Term Debt Redemptions and Maturities^(a)
	(in millions)
Southern Company^(b)	$	750	$	1,000	$	—	$	—	$	—	$	—
Alabama Power	500		—		120		120		—		1
Georgia Power	—		1,500		108		469		—		111
Mississippi Power	600		155		—		43		—		900
Southern Power	—		350		—		—		—		420
Southern Company Gas	—		155		—		200		300		—
Other^(c)	—		100		—		—		100		13
Elimination^(d)	—		—		—		—		—		(4		)
Southern Company Consolidated	$	1,850	$	3,260	$	228	$	832	$	400	$	1,441


(a)	Includes reductions in capital lease obligations resulting from cash payments under capital leases.


(b)	Represents the Southern Company parent entity.

(c)

In November 2018, SEGCO, as borrower, and Alabama Power, as guarantor, entered into a $100 million long-term delayed draw floating rate bank term loan bearing interest based on three-month LIBOR, which SEGCO used to repay at maturity $100 million aggregate principal amount of Series 2013A Senior Notes due December 1, 2018. See Note 9 to the financial statements under "Guarantees" for additional information.


(d)	Represents reductions in affiliate capital lease obligations at Georgia Power, which are eliminated in Southern Company's consolidated financial statements.

Except as otherwise described herein, Southern Company and its subsidiaries 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 subsidiaries also used the proceeds for their construction programs.

In March 2018, Southern Company entered into a $900 million short-term floating rate bank loan bearing interest based on one-month LIBOR, which was repaid in August 2018.

In April 2018, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, bearing interest at a rate agreed upon by Southern Company and the bank from time to time and payable on no less than 30 days' demand by the bank. Subsequent to December 31, 2018, Southern Company repaid this loan.

In June 2018, Southern Company repaid at maturity two $100 million short-term floating rate bank term loans.

In August 2018, Southern Company issued $750 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due February 14, 2020 bearing interest based on three-month LIBOR, entered into a $1.5 billion short-term floating rate bank loan bearing interest based on one-month LIBOR, and repaid $250 million borrowed in August 2017 pursuant to a short-term uncommitted bank credit arrangement. Subsequent to December 31, 2018, Southern Company repaid the $1.5 billion short-term floating rate bank loan.

In the third quarter 2018, Southern Company repaid at maturity $500 million aggregate principal amount of 1.55% Senior Notes and $500 million aggregate principal amount of Series 2013A 2.45% Senior Notes.

Subsequent to December 31, 2018, through cash tender offers, Southern Company repurchased and retired approximately $522 million of the $1.0 billion aggregate principal amount outstanding of its 1.85% Senior Notes due July 1, 2019 (1.85% Notes), approximately $180 million of the $350 million aggregate principal amount outstanding of its Series 2014B 2.15% Senior Notes due September 1, 2019 (Series 2014B Notes), and approximately $504 million of the $750 million aggregate principal amount outstanding of its Series 2018A Floating Rate Notes due February 14, 2020 (Series 2018A Notes), for an aggregate purchase price, excluding accrued and unpaid interest, of approximately $1.2 billion. In addition, subsequent to December 31, 2018, and following the completion of the cash tender offers, Southern Company completed the redemption of all of the Series 2018A Notes remaining outstanding and called for redemption all of the 1.85% Notes and Series 2014B Notes remaining outstanding.

II-62

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

Subsequent to December 31, 2018, Alabama Power repaid at maturity $200 million aggregate principal amount of Series Z 5.125% Senior Notes.

In January 2018, Georgia Power repaid its outstanding $150 million short-term floating rate bank loan due May 31, 2018.

In May 2018, through cash tender offers, Georgia Power repurchased and retired $89 million of the $250 million aggregate principal amount outstanding of its Series 2007A 5.65% Senior Notes due March 1, 2037, $326 million of the $500 million aggregate principal amount outstanding of its Series 2009A 5.95% Senior Notes due February 1, 2039, and $335 million of the $600 million aggregate principal amount outstanding of its Series 2010B 5.40% Senior Notes due June 1, 2040, for an aggregate purchase price, excluding accrued and unpaid interest, of $902 million.

Subsequent to December 31, 2018, Georgia Power redeemed approximately $13 million, $20 million, and $75 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1992, Eighth Series 1994, and Second Series 1995, respectively.

In March 2018, Mississippi Power entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $100 million was repaid in the third quarter 2018. The proceeds of this loan, together with the proceeds of Mississippi Power's $600 million senior notes issuances, were used to repay Mississippi Power's $900 million unsecured floating rate term loan.

In May 2018, Southern Power entered into two short-term floating rate bank loans, each for an aggregate principal amount of $100 million, which bear interest based on one-month LIBOR. In November 2018, Southern Power repaid one of these short-term loans.

During 2018, Southern Power received approximately $148 million of third-party tax equity related to certain of its renewable facilities. See Note 15 to the financial statements under "Southern Power" for additional information.

Prior to its sale, in the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of gas facility revenue bonds to be redeemed.

In May 2018, Southern Company Gas Capital borrowed $95 million pursuant to a short-term uncommitted bank credit arrangement, guaranteed by Southern Company Gas, bearing interest at a rate agreed upon by Southern Company Gas Capital and the bank from time to time and payable on no less than 30 days' demand by the bank. In July 2018, Southern Company Gas Capital repaid this loan.

Other long-term debt issuances for Southern Company Gas include the issuance by Nicor Gas of $300 million aggregate principal amount of first mortgage bonds in a private placement, of which $100 million was issued in August 2018 and $200 million was issued in November 2018.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries 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.

Credit Rating Risk

At December 31, 2018, Southern Company and its subsidiaries 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 subsidiaries to BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and construction of new generation at Plant Vogtle Units 3 and 4.

II-63

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

The maximum potential collateral requirements under these contracts at December 31, 2018 were as follows:



Credit Ratings	Maximum Potential Collateral Requirements^(a)
	(in millions)
At BBB and/or Baa2	$	30
At BBB- and/or Baa3	$	542
At BB+ and/or Ba1^(b)	$	2,176


(a)	Includes potential collateral requirements related to Gulf Power of $111 million and $221 million at a credit rating of BBB- and/or Baa3 and BB+ and/or Ba1, respectively. See Note 15 to the financial statements under "Southern Company's Sale of Gulf Power" for information regarding the sale of Gulf Power on January 1, 2019.


(b)	Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million.

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 Southern Company and its subsidiaries to access capital markets and would be likely to impact the cost at which they do so.

On February 26, 2018, Moody's revised its rating outlook for Mississippi Power from stable to positive. On August 8, 2018, Moody's upgraded Mississippi Power's senior unsecured rating to Baa3 from Ba1 and maintained the positive rating outlook.

On February 28, 2018, Fitch removed Mississippi Power from rating watch negative and revised its rating outlook from stable to positive.

Also on February 28, 2018, Fitch downgraded the senior unsecured long-term debt rating of Southern Company to BBB+ from A- with a stable outlook and of Georgia Power to A from A+ with a negative outlook. On August 9, 2018, Fitch downgraded the senior unsecured long-term debt rating of Georgia Power to A- from A.

On March 14, 2018, S&P upgraded the senior unsecured long-term debt rating of Mississippi Power to A- from BBB+. The outlook remained negative.

On August 8, 2018, Moody's downgraded the senior unsecured debt rating of Georgia Power to Baa1 from A3.

On September 28, 2018, Moody's revised its rating outlooks for Southern Company, Alabama Power, and Georgia Power from negative to stable.

Also on September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and its subsidiaries (excluding Mississippi Power).

As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries may be negatively impacted. Southern Company and most of its regulated subsidiaries have taken actions to mitigate the resulting impacts, which, among other alternatives, include adjusting capital structure. Absent actions by Southern Company and its subsidiaries that fully mitigate the impacts, the credit ratings of Southern Company and certain of its subsidiaries could be negatively affected. See Note 2 to the financial statements for additional information related to state PSC or other regulatory agency actions related to the Tax Reform Legislation, including approvals of capital structure adjustments for Alabama Power, Georgia Power, and Atlanta Gas Light by their respective state PSCs, which are expected to help mitigate the potential adverse impacts to certain of their credit metrics.

Market Price Risk

The Southern Company system is 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, the applicable company nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the applicable company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet 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.

II-64

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

To mitigate future exposure to a change in interest rates, Southern Company and certain of its subsidiaries enter into derivatives that have been designated as hedges. Derivatives that have been designated as hedges outstanding at December 31, 2018 have a notional amount of $2.0 billion and are intended to mitigate interest rate volatility related to existing fixed rate obligations. The weighted average interest rate on $5.8 billion of long-term variable interest rate exposure at December 31, 2018 was 3.02%. If Southern Company sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would affect annualized interest expense by approximately $58 million at December 31, 2018. See Note 1 to the financial statements under "Financial Instruments" and Note 14 to the financial statements for additional information.

Southern Power Company had foreign currency denominated debt of €1.1 billion at December 31, 2018. Southern Power Company has mitigated its exposure to foreign currency exchange rate risk through the use of foreign currency swaps converting all interest and principal payments to fixed-rate U.S. dollars.

Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional electric operating companies and natural gas distribution utilities continue to have limited exposure to market volatility in interest rates, foreign currency exchange rates, commodity fuel prices, and prices of electricity. In addition, Southern Power's exposure to market volatility in commodity fuel prices and prices of electricity is limited because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. 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. 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. Southern Company had no material change in market risk exposure for the year ended December 31, 2018 when compared to the year ended December 31, 2017.

The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. For the years ended December 31, the changes in fair value of energy-related derivative contracts, the majority of which are composed of regulatory hedges, were as follows:



	2018			2017
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(163	)	$	41
Contracts realized or settled	93			(8		)
Current period changes^(a)	(131		)	(196		)
Contracts outstanding at the end of the period, assets (liabilities), net^(b)(c)	$	(201	)	$	(163	)


(a)	Current period changes also include the changes in fair value of new contracts entered into during the period, if any.


(b)	Excludes premium and intrinsic value associated with weather derivatives of $8 million and $11 million at December 31, 2018 and 2017, respectively.


(c)	Includes $6 million of net liabilities related to Gulf Power. See Note 15 to the financial statements under "Southern Company's Sale of Gulf Power" for information regarding the sale of Gulf Power on January 1, 2019.

The net hedge volumes of energy-related derivative contracts were 431 million mmBtu and 621 million mmBtu at December 31, 2018 and 2017, respectively.

For the traditional electric operating companies and Southern Power, the weighted average swap contract cost above market prices was approximately $0.12 per mmBtu at December 31, 2018 and $0.15 per mmBtu at December 31, 2017. The majority of the natural gas hedge gains and losses are recovered through the traditional electric operating companies' fuel cost recovery clauses.

At December 31, 2018 and 2017, a portion of the Southern Company system's energy-related derivative contracts were designated as regulatory hedges and were related to the applicable company's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the energy cost recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. 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. See Note 14 to the financial statements for additional information.

The Southern Company system uses exchange-traded market-observable contracts, which are categorized as Level 1 of the fair value hierarchy, and over-the-counter contracts that are not exchange traded but are fair valued using prices which are market

II-65

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

observable, and thus fall into Level 2 of the fair value hierarchy. See Note 13 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts at December 31, 2018 were as follows:



	Fair Value Measurements
	December 31, 2018
	Total Fair Value			Maturity
	Total Fair Value			Year 1			Years 2&3			Years 4&5
	(in millions)
Level 1	$	(179	)	$	(59	)	$	(86	)	$	(34	)
Level 2	(22		)	20			(17		)	(25		)
Level 3	—			—			—			—
Fair value of contracts outstanding at end of period	$	(201	)	$	(39	)	$	(103	)	$	(59	)

The Southern Company system is exposed to market price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. The Southern Company system only enters 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 Southern Company system does 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.

With the exception of Southern Company Gas' subsidiary, Atlanta Gas Light, and the Southern Company Gas wholesale gas services business, the Southern Company system is not exposed to 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 15 Marketers in Georgia responsible for the retail sale of natural gas to end-use customers in Georgia. For 2018, the four largest Marketers based on customer count, which includes SouthStar, accounted for 20% of Southern Company Gas' adjusted operating margin. Southern Company Gas' wholesale gas services business has a concentration of credit risk for services it provides to its counterparties as measured by its 30-day receivable exposure plus forward exposure. At December 31, 2018, Southern Company Gas' wholesale gas services business' top 20 counterparties represented approximately 48%, or $298 million, of its total counterparty exposure and had a weighted average S&P equivalent credit rating of A-, all of which is consistent with the prior year.

Southern Company performs periodic reviews of its leveraged lease transactions, both domestic and international, and the creditworthiness of the lessees, including a review of the value of the underlying leased assets and the credit ratings of the lessees. Southern Company's domestic lease transactions generally do not have any credit enhancement mechanisms; however, the lessees in its international lease transactions have pledged various deposits as additional security to secure the obligations. The lessees in Southern Company's international lease transactions are also required to provide additional collateral in the event of a credit downgrade below a certain level.

Capital Requirements and Contractual Obligations

The Southern Company system's construction program is currently estimated to total approximately $8.0 billion for 2019, $7.7 billion for 2020, $6.7 billion for 2021, $6.3 billion for 2022, and $6.0 billion for 2023. These amounts include expenditures of approximately $1.5 billion, $1.2 billion, $1.0 billion, and $0.5 billion for the construction of Plant Vogtle Units 3 and 4 in 2019, 2020, 2021, and 2022, respectively. These amounts do not include up to approximately $0.5 billion per year on average for 2019 through 2023 for Southern Power's planned expenditures for plant acquisitions and placeholder growth. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $0.5 billion, $0.2 billion, $0.3 billion, $0.3 billion, and $0.2 billion for 2019, 2020, 2021, 2022, and 2023, respectively. These estimated expenditures do not include any potential compliance costs associated with pending regulation of CO₂ emissions from fossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and " – Global Climate Issues" herein for additional information.

The traditional electric operating companies also anticipate costs associated with closure and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in Southern Company's ARO liabilities. These costs, which are expected to change and could change materially as underlying assumptions are refined and the cost and the method and timing of compliance activities continue to be evaluated, are currently estimated to be approximately $0.5 billion, $0.5 billion, $0.7 billion, $0.9 billion, and $0.9 billion for 2019, 2020, 2021, 2022, and 2023, respectively. See FUTURE EARNINGS POTENTIAL – "Environmental

II-66

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 6 to the financial statements for additional information.

The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. 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; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 15 to the financial statements under "Southern Power" for additional information regarding Southern Power's plant acquisitions.

The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only recently began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. The ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs, availability, and productivity; challenges with management of contractors, subcontractors, or vendors; adverse weather conditions; shortages, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; non-performance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance matters, including the timely resolution of ITAAC and the related approvals by the NRC; challenges with start-up activities, including major equipment failure and system integration; and/or operational performance. 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.

As a result of NRC requirements, Alabama Power and Georgia Power have external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. For additional information, see Note 6 to the financial statements under "Nuclear Decommissioning."

In addition, as discussed in Note 11 to the financial statements, the Southern Company system provides postretirement benefits to the majority of its employees and funds trusts to the extent required by PSCs, other applicable state regulatory agencies, or the FERC.

Funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred stock dividends of subsidiaries, leases, pipeline charges, storage capacity, gas supply, asset management agreements, other purchase commitments, ARO settlements, and trusts are detailed in the contractual obligations table that follows. See Notes 1, 6, 8, 9, 11, and 14 to the financial statements for additional information.

II-67

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report

Contractual Obligations

The Southern Company system's contractual obligations at December 31, 2018 (excluding Gulf Power) were as follows:



	2019		2020- 2021		2022- 2023		After 2023		Total
	(in millions)
Long-term debt^(a) —
Principal	$	3,133	$	7,204	$	4,354	$	28,950	$	43,641
Interest	1,668		3,082		2,270		25,796		32,816
Preferred stock dividends of subsidiaries^(b)	15		29		29		—		73
Financial derivative obligations^(c)	610		243		109		—		962
Operating leases^(d)	156		244		177		1,040		1,617
Capital leases^(d)	25		22		8		143		198
Pipeline charges, storage capacity, and gas supply^(e)	781		1,104		901		1,871		4,657
Asset management agreements^(f)	10		8		—		—		18
Purchase commitments—
Capital^(g)	7,600		13,608		11,486		—		32,694
Fuel^(h)	3,168		3,854		1,863		5,862		14,747
Purchased power⁽ⁱ⁾	304		653		545		2,494		3,996
Other^(j)	328		642		464		2,265		3,699
ARO settlements^(k)	451		1,186		1,841		—		3,478
Trusts —
Nuclear decommissioning^(l)	5		11		11		88		115
Pension and other postretirement benefit plans^(m)	137		265		—		—		402
Total	$	18,391	$	32,155	$	24,058	$	68,509	$	143,113

(a)

All amounts are reflected based on final maturity dates except for amounts related to FFB borrowings and certain revenue bonds. As it relates to the FFB borrowings, the final maturity date is February 20, 2044; however, principal amortization is reflected beginning in 2020. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" and "Securities Due Within One Year" for additional information. Southern Company and its subsidiaries plan to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates at December 31, 2018, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately).


(b)	Represents preferred stock of Alabama Power. Preferred stock does not mature; therefore, amounts are provided for the next five years only.


(c)	See Notes 1 and 14 to the financial statements.


(d)	Excludes PPAs that are accounted for as leases and included in "Purchased power."

(e)

Includes charges recoverable through a natural gas cost recovery mechanism, or alternatively billed to Marketers selling retail natural gas, and demand charges associated with Southern Company Gas' wholesale gas services. The gas supply balance includes amounts for gas commodity purchase commitments associated with Southern Company Gas' gas marketing services of 47 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2018 and valued at $150 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations.


(f)	Represents fixed-fee minimum payments for asset management agreements associated with wholesale gas services.

(g)

The Southern Company system provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel, capital expenditures covered under LTSAs, and estimated capital expenditures for AROs, which are reflected in "Fuel," "Other," and "ARO settlements," respectively. These amounts also exclude up to approximately $0.5 billion per year on average for 2019 through 2023 for Southern Power's planned expenditures for plant acquisitions and placeholder growth. At December 31, 2018, significant purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and "Construction Programs" herein for additional information.

(h)

Primarily includes commitments to purchase coal, nuclear fuel, and natural gas, 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. Amounts reflected for natural gas purchase commitments have been estimated based on the NYMEX future prices at December 31, 2018.


(i)	Estimated minimum long-term obligations for various PPA purchases from gas-fired, biomass, and wind-powered facilities and capacity payments related to Plant Vogtle Units 1 and 2. See Note 9 to the financial statements under "Fuel and Power Purchase Agreements" for additional information.

II-68

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company and Subsidiary Companies 2018 Annual Report


(j)	Includes LTSAs, contracts for the procurement of limestone, contractual environmental remediation liabilities, and operation and maintenance agreements. LTSAs include price escalation based on inflation indices.

(k)

Represents estimated costs for a five-year period associated with closing and monitoring ash ponds in accordance with the CCR Rule and the related state rules, which are reflected in Southern Company's ARO liabilities. Material expenditures in future years for ARO settlements also will be required for ash ponds, nuclear decommissioning, and other liabilities reflected in Southern Company's AROs. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 6 to the financial statements for additional information.

(l)

Projections of nuclear decommissioning trust fund contributions for Plant Hatch and Plant Vogtle Units 1 and 2 are based on the 2013 ARP for Georgia Power. Alabama Power also has external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. See Note 6 to the financial statements under "Nuclear Decommissioning" for additional information.

(m)

The Southern Company system forecasts contributions to the pension and other postretirement benefit plans over a three-year period. Southern Company anticipates no mandatory contributions to the qualified pension plans during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from corporate assets of Southern Company's subsidiaries. See Note 11 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from corporate assets of Southern Company's subsidiaries.

II-69

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Alabama Power Company 2018 Annual Report

OVERVIEW

Business Activities

Many factors affect the opportunities, challenges, and risks of Alabama Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, including CCR rules, reliability, fuel, capital expenditures, including improving the electric transmission and distribution systems, and restoration following major storms. Alabama Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future. On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the retail rate impact and the growing pressure on its credit quality resulting from the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information.

Alabama Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock. Alabama Power's financial success is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys to evaluate Alabama Power's results and generally targets the top quartile of these surveys in measuring performance.

See RESULTS OF OPERATIONS herein for information on Alabama Power's financial performance.

Earnings

Alabama Power's 2018 net income after dividends on preferred and preference stock was $930 million, representing an $82 million, or 9.7%, increase over the previous year. The increase was primarily due to a decrease in income tax expense, partially offset by a decrease in retail revenues associated with customer bill credits related to the Tax Reform Legislation. The increase also reflects an increase in revenues associated with colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017, partially offset by an accrual for a Rate RSE refund. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate RSE" herein for additional information.

Alabama Power's 2017 net income after dividends on preferred and preference stock was $848 million, representing a $26 million, or 3.2%, increase over the previous year. The increase was primarily due to an increase in rates under Rate RSE effective in January 2017 and the impact of a Rate RSE refund recorded in 2016. These increases to income were partially offset by a decrease in retail revenues associated with milder weather, lower customer usage, and an increase in non-fuel operations and maintenance expenses in 2017 as compared to 2016. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate RSE" herein for additional information.

II-70

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

RESULTS OF OPERATIONS

A condensed income statement for Alabama Power follows:



	Amount		Increase (Decrease) from Prior Year
	2018		2018			2017
	(in millions)
Operating revenues	$	6,032	$	(7	)	$	150
Fuel	1,301		76			(72		)
Purchased power	432		104			(6		)
Other operations and maintenance	1,669		(40		)	152
Depreciation and amortization	764		28			33
Taxes other than income taxes	389		5			4
Total operating expenses	4,555		173			111
Operating income	1,477		(180		)	39
Allowance for equity funds used during construction	62		23			11
Interest expense, net of amounts capitalized	323		18			3
Other income (expense), net	20		(23		)	17
Income taxes	291		(277		)	37
Net income	945		79			27
Dividends on preferred and preference stock	15		(3		)	1
Net income after dividends on preferred and preference stock	$	930	$	82		$	26

Operating Revenues

Operating revenues for 2018 were $6.0 billion, reflecting a $7 million decrease from 2017. Details of operating revenues were as follows:



	2018			2017
	(in millions)
Retail — prior year	$	5,458		$	5,322
Estimated change resulting from —
Rates and pricing	(354		)	362
Sales decline	(10		)	(44		)
Weather	137			(89		)
Fuel and other cost recovery	136			(93		)
Retail — current year	5,367			5,458
Wholesale revenues —
Non-affiliates	279			276
Affiliates	119			97
Total wholesale revenues	398			373
Other operating revenues	267			208
Total operating revenues	$	6,032		$	6,039
Percent change	(0.1		)%	2.6		%

Retail revenues in 2018 were $5.4 billion. These revenues decreased $91 million, or 1.7%, in 2018 as compared to the prior year. The decrease in 2018 was primarily due to customer bill credits related to the Tax Reform Legislation and an accrual for a Rate RSE refund, partially offset by an increase in fuel revenues and colder weather in the first quarter and warmer weather in the second and third quarters 2018 as compared to the corresponding periods in 2017.

II-71

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

Retail revenues in 2017 were $5.5 billion. These revenues increased $136 million, or 2.6%, in 2017 as compared to the prior year. The increase in 2017 was primarily due to an increase in rates under Rate RSE effective in January 2017, partially offset by a decrease in fuel revenues and milder weather in the first and third quarters 2017 as compared to the corresponding periods in 2016.

See Note 2 to the financial statements under "Alabama Power – Rate RSE" for additional information. See "Energy Sales" herein for a discussion of changes in the volume of energy sold, including changes related to sales decline and weather.

Electric rates include provisions to recognize the recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate ECR" herein for additional information.

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



	2018		2017		2016
	(in millions)
Capacity and other	$	101	$	96	$	93
Energy	178		180		190
Total non-affiliated	$	279	$	276	$	283

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

In 2018, wholesale revenues from sales to non-affiliates increased $3 million, or 1.1%, as compared to the prior year. In 2017, wholesale revenues from sales to non-affiliates decreased $7 million, or 2.5%, as compared to the prior year.

In 2018, wholesale revenues from sales to affiliates increased $22 million, or 22.7%, as compared to the prior year. In 2018, the price of energy increased 12.3% as a result of higher natural gas prices and KWH sales increased 10.0% primarily due to an increase in hydro generation. In 2017, wholesale revenues from sales to affiliates increased $28 million, or 40.6%, as compared to the prior year. In 2017, KWH sales increased 31.1% as a result of supporting Southern Company system transmission reliability and a 6.9% increase in the price of energy primarily due to higher natural gas prices.

In 2018, other operating revenues increased $59 million, or 28.4%, as compared to the prior year primarily due to revenues related to unregulated sales of products and services that were reclassified as other revenues as a result of the adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). In prior periods, these revenues were included in other income (expense), net. See Note 1 to the financial statements for additional information regarding Alabama Power's adoption of ASC 606. This increase was partially offset by decreases in open access transmission tariff revenues primarily due to a lower rate related to the Tax Reform Legislation.

II-72

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2018 and the percent change from the prior year were as follows:



	Total KWHs	Total KWH Percent Change				Weather-Adjusted Percent Change
	2018	2018		2017		2018		2017
	(in billions)
Residential	18.6	8.2	%	(6.1	)%	(0.4	)%	(1.2	)%
Commercial	13.9	1.9		(3.4	)	(1.0	)	(1.3	)
Industrial	23.0	1.4		1.7		1.4		1.7
Other	0.2	(5.7	)	(5.0	)	(5.7	)	(5.0	)
Total retail	55.7	3.7		(2.3	)	0.2	%	(0.1	)%
Wholesale
Non-affiliates	5.0	(8.7	)	(6.5	)
Affiliates	4.6	9.6		31.1
Total wholesale	9.6	(0.9	)	6.6
Total energy sales	65.3	3.0	%	(1.0	)%

Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales in 2018 were 3.7% higher than in 2017. Residential sales and commercial sales increased 8.2% and 1.9% in 2018, respectively, primarily due to colder weather in the first quarter and warmer weather in the second and third quarters 2018 as compared to the corresponding periods in 2017. Weather-adjusted residential sales were 0.4% lower in 2018 primarily due to lower customer usage resulting from an increase in penetration of energy-efficient residential appliances. Weather-adjusted commercial sales were 1.0% lower in 2018 primarily due to lower customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model. Industrial sales increased 1.4% in 2018 as compared to 2017 as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, pipelines, and mining sectors offset by the paper sector.

Retail energy sales in 2017 were 2.3% lower than in 2016. Residential sales and commercial sales decreased 6.1% and 3.4% in 2017, respectively, primarily due to milder weather in the first and third quarters 2017 as compared to the corresponding periods in 2016. Weather-adjusted residential sales were 1.2% lower in 2017 primarily due to lower customer usage resulting from an increase in penetration of energy-efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial sales were 1.3% lower in 2017 primarily due to lower customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth. Industrial sales increased 1.7% in 2017 as compared to 2016 as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, chemicals, and mining sectors offset by the pipelines and paper sectors.

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

Fuel and Purchased Power Expenses

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

II-73

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

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



	2018	2017	2016
Total generation (in billions of KWHs)	60.5	60.3	60.2
Total purchased power (in billions of KWHs)	8.1	6.4	7.1
Sources of generation (percent) —
Coal	50	50	53
Nuclear	23	24	23
Gas	19	20	19
Hydro	8	6	5
Cost of fuel, generated (in cents per net KWH) —
Coal	2.73	2.60	2.75
Nuclear	0.77	0.75	0.78
Gas	2.84	2.72	2.67
Average cost of fuel, generated (in cents per net KWH)^(a)(b)	2.26	2.14	2.26
Average cost of purchased power (in cents per net KWH)^(c)	5.47	5.29	4.80



(a)	For 2018, cost of fuel, generated and average cost of fuel, generated excludes a $30 million adjustment associated with a May 2018 Alabama PSC accounting order related to excess deferred income taxes. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Tax Reform Accounting Order" herein for additional information.
(b)	KWHs generated by hydro are excluded from the average cost of fuel, generated.
(c)	Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.

Fuel and purchased power expenses were $1.73 billion in 2018, an increase of $180 million, or 11.6%, compared to 2017. The increase was primarily due to an $81 million net increase related to the volume of KWHs purchased and generated, a $54 million increase in the average cost of fuel, and a $15 million increase in the average cost of purchased power.

In addition, fuel expense increased $30 million in 2018 as a result of an Alabama PSC accounting order authorizing the amortization of a regulatory liability to offset under recovered fuel costs. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Tax Reform Accounting Order" herein for additional information.

Fuel and purchased power expenses were $1.55 billion in 2017, a decrease of $78 million, or 4.8%, compared to 2016. The decrease was primarily due to a $67 million net decrease related to the volume of KWHs generated and purchased and a $42 million decrease in the average cost of fuel, partially offset by a $31 million increase in the average cost of purchased power.

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

Fuel

Fuel expenses were $1.3 billion in 2018, an increase of $76 million, or 6.2%, compared to 2017. The increase was primarily due to a 5.0% increase in the average cost of KWHs generated by coal and a 4.4% increase in the average cost of KWHs generated by natural gas, which excludes tolling agreements. These increases were partially offset by a 28.3% increase in the volume of KWHs generated by hydro and a 2.1% decrease in the volume of KWHs generated by natural gas. Fuel expenses were $1.2 billion in 2017, a decrease of $72 million, or 5.6%, compared to 2016. The decrease was primarily due to a 12.2% increase in the volume of KWHs generated by hydro, a 5.8% decrease in the volume of KWHs generated by coal, and a 5.5% and 3.9% decrease in the average cost of KWHs generated by coal and nuclear fuel, respectively. These decreases were partially offset by an 8.1% increase in the volume of KWHs generated by nuclear fuel and a 4.0% increase in the volume of KWHs generated by natural gas.

In addition, fuel expense increased $30 million in 2018 as a result of an Alabama PSC accounting order authorizing the amortization of a regulatory liability to offset under recovered fuel costs. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Tax Reform Accounting Order" herein for additional information.

II-74

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

Purchased Power – Non-Affiliates

Purchased power expense from non-affiliates was $216 million in 2018, an increase of $46 million, or 27.1%, compared to 2017. This increase was primarily due to an 18.9% increase in the amount of energy purchased due to colder weather in the first quarter and warmer weather in the second and third quarters 2018 as compared to the corresponding periods in 2017 and a 6.6% increase in the average cost per KWH purchased due to higher natural gas prices. Purchased power expense from non-affiliates was $170 million in 2017, an increase of $4 million, or 2.4%, compared to 2016.

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

Purchased Power – Affiliates

Purchased power expense from affiliates was $216 million in 2018, an increase of $58 million, or 36.7%, compared to 2017. This increase was primarily due to a 34.5% increase in the amount of energy purchased due to colder weather in the first quarter and warmer weather in the second and third quarters 2018 as compared to the corresponding periods in 2017 and a 1.4% increase in the average cost per KWH purchased due to higher natural gas prices. Purchased power expense from affiliates was $158 million in 2017, a decrease of $10 million, or 6.0%, compared to 2016. This decrease was primarily due to a 17.2% decrease in the amount of energy purchased due to milder weather partially offset by a 13.9% increase in the average cost per KWH purchased due to higher natural gas prices.

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

Other Operations and Maintenance Expenses

In 2018, other operations and maintenance expenses decreased $40 million, or 2.3%, as compared to the prior year. Generation costs decreased $34 million primarily due to fewer outages resulting in lower costs. Employee benefit costs, including pension costs, decreased $26 million primarily due to lower active medical costs. Customer service costs decreased $10 million primarily due to cost-saving initiatives. These decreases were partially offset by a $47 million increase in expenses from unregulated sales of products and services that were reclassified as other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. See Note 1 to the financial statements under "Revenue" for additional information.

In 2017, other operations and maintenance expenses increased $152 million, or 9.8%, as compared to the prior year. Distribution and transmission expenses increased $58 million primarily due to vegetation management expenses. Generation costs increased $38 million primarily due to outage costs. Employee benefit costs, including pension costs, increased $32 million.

See Note 11 to the financial statements under "Pension Plans" for additional information.

Depreciation and Amortization

Depreciation and amortization increased $28 million, or 3.8%, in 2018 as compared to the prior year primarily due to additional plant in service related to distribution, transmission, compliance-related steam, and other generation production projects. Depreciation and amortization increased $33 million, or 4.7%, in 2017 as compared to the prior year primarily due to additional plant in service and an increase in generation-related depreciation rates, effective January 1, 2017, associated with compliance-related steam projects and ARO recovery, partially offset by a decrease in distribution-related depreciation rates. See Note 5 to the financial statements under "Depreciation and Amortization" for additional information.

Allowance for Equity Funds Used During Construction

AFUDC equity increased $23 million, or 59.0%, in 2018 as compared to the prior year. The increase was primarily associated with steam and transmission construction projects. AFUDC equity increased $11 million, or 39.3%, in 2017 as compared to the prior year. The increase was primarily associated with steam, transmission, and nuclear construction projects. See Note 1 to financial statements under "Allowance for Funds Used During Construction" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $18 million, or 5.9%, in 2018 as compared to the prior year primarily due to an increase in debt outstanding and higher interest rates, partially offset by an increase in the amounts capitalized. Interest

II-75

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

expense, net of amounts capitalized increased $3 million, or 1.0%, in 2017 as compared to the prior year. See FUTURE EARNINGS POTENTIAL – "Financing Activities" herein for additional information.

Other Income (Expense), Net

Other income (expense), net decreased $23 million, or 53.5%, in 2018 as compared to the prior year primarily due to an increase in charitable donations and the reclassification of revenues and expenses associated with unregulated sales of products and services to other revenues and operations and maintenance expenses, respectively, as a result of the adoption of ASC 606. See Note 1 to the financial statements under "Revenue" for additional information. Other income (expense), net increased $17 million, or 65.4%, in 2017 as compared to the prior year primarily due to increases in unregulated lighting services and a decrease in the non-service cost components of net periodic pension and other postretirement benefits costs. See Note 1 to the financial statements under "Recently Adopted Accounting Standards" and Note 11 to the financial statements for additional information on net periodic pension and other postretirement benefit costs.

Income Taxes

Income taxes decreased $277 million, or 48.8%, in 2018 as compared to the prior year primarily due to the reduction in the federal income tax rate, the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation, and lower pre-tax earnings. Income taxes increased $37 million, or 7.0%, in 2017 as compared to the prior year primarily due to higher pre-tax earnings, an increase related to prior year tax return actualization, and an increase in income tax reserves, partially offset by an increase in state income tax credits. The impact to net income as a result of the Tax Reform Legislation was not material due to the application of regulatory accounting. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 10 to the financial statements for additional information.

Effects of Inflation

Alabama Power is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on Alabama Power's results of operations has not been substantial in recent years. See Note 2 to the financial statements under "Alabama Power – Rate RSE" for additional information.

FUTURE EARNINGS POTENTIAL

General

Alabama Power operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in the State of Alabama and to wholesale customers in the Southeast. Prices for electric service provided by Alabama Power to retail customers are set by the Alabama PSC under cost-based regulatory principles. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. Prices for wholesale electric service, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Utility Regulation" herein and Note 2 to the financial statements under "Alabama Power" for additional information about regulatory matters.

The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of Alabama Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Alabama Power's primary business of providing electric service. These factors include Alabama Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and the weak pace of growth in new customers and electricity use per customer, especially in residential and commercial markets. Earnings 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, both of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.

II-76

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

Environmental Matters

Alabama Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Alabama Power maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future electric generating unit retirement and replacement decisions, 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 Alabama Power's transmission and distribution systems. A major portion of these costs is expected to be recovered through existing ratemaking provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed herein will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, and the outcome of pending and/or future legal challenges.

New or revised environmental laws and regulations could affect many areas of Alabama Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be recovered in rates on a timely basis. Environmental compliance costs are recovered through Rate CNP Compliance. See Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance" for additional information. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity, 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 for some may have the potential to ultimately affect their demand for electricity.

Through 2018, Alabama Power has invested approximately $5.4 billion in environmental capital retrofit projects to comply with environmental requirements, with annual totals of approximately $681 million, $491 million, and $260 million for 2018, 2017, and 2016, respectively. 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, Alabama Power's current compliance strategy estimates capital expenditures of $635 million from 2019 through 2023, with annual totals of approximately $226 million in 2019, $68 million in 2020, $118 million in 2021, $112 million in 2022, and $111 million in 2023. These estimates do not include any potential compliance costs associated with pending regulation of CO₂ emissions from fossil fuel-fired electric generating units. See "Global Climate Issues" herein for additional information. Alabama Power also anticipates substantial expenditures associated with ash pond closure and ground water monitoring under the CCR Rule, which are reflected in Alabama Power's ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 6 to the financial statements for additional information.

Environmental Laws and Regulations

Air Quality

II-77

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

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 (e.g. coal, natural gas, oil, and nuclear generating plants) and manufacturing facilities. The regulation requires plant-specific studies to determine applicable CWIS changes to protect organisms that either get caught on the intake screens (impingement) or are drawn into the cooling system (entrainment). Alabama Power is conducting these studies and currently anticipates applicable CWIS changes may include fish-friendly CWIS screens with fish return systems and minor additions of monitoring equipment at certain plants. However, the ultimate 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 National Pollutant Discharge Elimination System (NPDES) permit based on site-specific factors, and the outcome of any legal challenges.

In 2015, the EPA finalized the steam electric effluent limitations guidelines (ELG) rule (2015 ELG Rule) that set national standards for wastewater discharges from new and existing steam electric generating units generating greater than 50 MWs. The 2015 ELG Rule prohibits effluent discharges of certain waste streams and imposes stringent limits on flue gas desulfurization (scrubber) wastewater discharges. The revised technology-based limits and the CCR Rule require extensive changes to existing ash and wastewater management systems or the installation and operation of new ash and wastewater management systems. Compliance with the 2015 ELG Rule is expected to require capital expenditures and increased operational costs primarily for Alabama Power's coal-fired electric generation. State environmental agencies will incorporate specific compliance applicability dates in the NPDES permitting process for each ELG waste stream no later than December 31, 2023. The EPA is scheduled to issue a new rulemaking by December 2019 that could revise the limitations and applicability dates of two of the waste streams regulated in the 2015 ELG Rule. The impact of any changes to the 2015 ELG Rule will depend on the content of the new rule and the outcome of any legal challenges. Alabama Power does not anticipate that the unavailability of any units as a result of the ELG rule will have a material impact on Alabama Power's operations or financial condition.

In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) jointly published a final rule that revised the regulatory definition of waters of the United States (WOTUS) for all CWA programs. The rule significantly expanded the scope of federal jurisdiction over waterbodies (such as rivers, streams, canals, and wastewater treatment ponds), which could impact new generation projects and permitting and reporting requirements associated with the installation, expansion, and maintenance of transmission and distribution projects. The EPA and the Corps are expected to publish a final rule in 2019 to replace the 2015 WOTUS definition. The impact of any changes to the 2015 WOTUS rule will depend on the content of this final rule and the outcome of any legal challenges.

Coal Combustion Residuals

In 2015, the EPA finalized non-hazardous solid waste regulations for the disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments (ash ponds) at active generating power plants. In addition to the EPA's CCR Rule, the State of Alabama has also finalized regulations regarding the handling of CCR that have been provided to the EPA for review. This state CCR rule is generally consistent with the federal CCR Rule. The EPA's CCR Rule requires landfills and ash ponds to be evaluated against a set of performance criteria and potentially closed if minimum criteria are not met. Closure of existing landfills and ash ponds could require installation of equipment and infrastructure to manage CCR in accordance with the CCR Rule. Based on cost estimates for closure in place and monitoring of ash ponds pursuant to the CCR Rule, Alabama Power recorded AROs for each CCR unit in 2015. As further analysis was performed and closure details were developed, Alabama Power has continued to periodically update these cost estimates, as discussed further below.

On August 21, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision suggesting the EPA should regulate previously-excluded inactive ash ponds located at retired generation facilities and questioning both the ability of unlined ash ponds to continue operating no matter the performance criteria results and the classification of clay-lined landfills and ash ponds. These developments could impact the expected timing of Alabama Power's landfill and ash pond closure activities, but the extent of any impact will depend on the outcome of ongoing litigation, anticipated EPA rulemaking action to establish further guidance, and the outcome of any legal challenges.

II-78

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology. As the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material.

Alabama Power expects to periodically update its ARO cost estimates. Absent continued recovery of ARO costs through regulated rates, Alabama Power's results of operations, cash flows, and financial condition could be materially impacted. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 6 to the financial statements for additional information.

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

Nuclear Decommissioning

Global Climate Issues

On August 31, 2018, the EPA published a proposed rule known as the Affordable Clean Energy (ACE) Rule, which is intended to replace a regulation enacted in 2015 known as the Clean Power Plan (CPP), that would limit CO₂ emissions from existing fossil fuel-fired electric generating units. The CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule would require states to develop GHG unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of January 1, 2019, Alabama Power has ownership interests in 20 fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to Alabama Power is currently unknown and will depend on changes between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal challenges.

The EPA's GHG reporting rule requires annual reporting of GHG emissions expressed in terms of metric tons of CO₂ equivalent emissions for a company's operational control of facilities. Based on ownership or financial control of facilities, Alabama Power's 2017 GHG emissions were approximately 37 million metric tons of CO₂ equivalent. The preliminary estimate of Alabama Power's 2018 GHG emissions on the same basis is approximately 36 million metric tons of CO₂ equivalent.

Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, complete ongoing construction projects, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies.

FERC Matters

Open Access Transmission Tariff

On May 10, 2018, AMEA and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies (including Alabama Power) claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Alabama Power's) open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requested that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and

II-79

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Alabama Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through December 31, 2018, the estimated maximum potential refund is not expected to be material to Alabama Power's results of operations or cash flows. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

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. If Alabama Power's actual retail return is above the allowed WCER range, the excess will be refunded to customers unless otherwise directed by the Alabama PSC; however, there is no provision for additional customer billings should the actual retail return fall below the WCER range. Prior to January 2019, retail rates remained unchanged when the WCER range was between 5.75% and 6.21%.

Rate CNP PPA

II-80

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

Rate CNP PPA. No adjustments to Rate CNP PPA occurred during the period 2016 through 2018 and no adjustment is expected in 2019.

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 a factor that is calculated annually. 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 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 accordance with an accounting order issued in February 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its under recovered balance in Rate CNP Compliance to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur no later than 2022.

Rate ECR

Alabama Power has established energy cost recovery rates under Alabama Power's Rate ECR as approved by the Alabama PSC. Rates are 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 give 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 Alabama Power's net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH.

In accordance with an accounting order issued in February 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its under recovered balance in Rate ECR to a separate regulatory asset. The amortization of the new regulatory asset through Rate RSE will begin concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur no later than 2022. Alabama Power's current depreciation study became effective January 1, 2017.

On May 1, 2018, the Alabama PSC approved an increase to Rate ECR from 2.015 cents per KWH to 2.353 cents per KWH effective July 2018 through December 2018. On December 4, 2018, the Alabama PSC issued a consent order to leave this rate in effect through December 31, 2019. This change is expected to increase collections by approximately $183 million in 2019. Absent any further order from the Alabama PSC, in January 2020, the rates will return to the originally authorized 5.910 cents per KWH.

As discussed herein under "Rate RSE," in accordance with an Alabama PSC order issued on February 5, 2019, Alabama Power will utilize $75 million of the 2018 Rate RSE refund liability to reduce the Rate ECR under recovered balance.

Tax Reform Accounting Order

II-81

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

regulatory liabilities, deferred on the balance sheet to be used for the benefit of customers as determined by the Alabama PSC at a future date. See Note 10 to the financial statements under "Current and Deferred Income Taxes" for additional information.

Software Accounting Order

On February 5, 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.

Plant Greene County

Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 5 to the financial statements under "Joint Ownership Agreements" for additional information regarding the joint ownership agreement. On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP) with the Mississippi PSC, which proposes a four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively. Mississippi Power's proposed Plant Greene County unit retirements would require the completion of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will continue to monitor the status of Mississippi Power's proposed RMP and associated regulatory process as well as the proposed transmission and system reliability improvements. Alabama Power will review all the facts and circumstances and will evaluate all its alternatives prior to reaching a final determination on the ongoing operations of Plant Greene County. The ultimate outcome of this matter cannot be determined at this time.

Request for Proposals for Future Generation

On September 21, 2018, Alabama Power issued a request for proposals of between 100 MWs and 1,200 MWs of capacity beginning no later than 2023. On November 9, 2018, bids were received and an evaluation of those bids is in progress. Any purchases will depend upon the cost competitiveness of the respective offers as well as other options available to Alabama Power. 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. In December 2017, the reserve maintenance charge was suspended and the reserve establishment charge was activated as a result of the NDR balance falling below $50 million. Alabama Power expects to collect approximately $16 million annually until the reserve balance is restored to $75 million. The NDR balance at December 31, 2018 was $20 million and is included in other regulatory liabilities, deferred on the balance sheet.

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.

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

II-82

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

Income Tax Matters

Federal Tax Reform Legislation

In December 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduced the federal corporate income tax rate to 21%, retained normalization provisions for public utility property and existing renewable energy incentives, and repealed the corporate alternative minimum tax. In addition, under the Tax Reform Legislation, net operating losses (NOLs) generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income of the subsequent tax year. The projected reduction of Southern Company's consolidated income tax liability resulting from the tax rate reduction also delays the expected utilization of existing tax credit carryforwards. See Note 10 to the financial statements for information on Southern Company's joint consolidated income tax allocation agreement.

Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provided for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes and their application under GAAP, Alabama Power considered all amounts recorded in the financial statements as a result of the Tax Reform Legislation "provisional" as discussed in SAB 118 and subject to revision prior to filing its 2017 tax return in the fourth quarter 2018. Alabama Power recognized tax expense of $3 million in 2017 as a result of the Tax Reform Legislation. In addition, in total, Alabama Power recorded a $281 million decrease in regulatory assets and a $2.0 billion increase in regulatory liabilities as a result of the Tax Reform Legislation. As of December 31, 2018, Alabama Power considered the measurement of impacts from the Tax Reform Legislation on deferred income tax assets and liabilities, primarily due to the impact of the reduction of the corporate income tax rate, to be complete.

However, the IRS continues to issue regulations that provide further interpretation and guidance on the law and each state's adoption of the provisions contained in the Tax Reform Legislation remains uncertain. The regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC. The ultimate impact of this matter cannot be determined at this time. See Note 2 to the financial statements under "Alabama Power – Rate RSE" for additional information regarding modifications to Rate RSE to reflect the impacts of the Tax Reform Legislation. Also see FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 10 to the financial statements under "Current and Deferred Income Taxes" for additional information.

Bonus Depreciation

Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the PATH Act. The PATH Act allowed for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. Based on provisional estimates, bonus depreciation is expected to result in positive cash flows of approximately $100 million for the 2018 tax year and approximately $30 million for the 2019 tax year. See Note 10 to the financial statements under "Current and Deferred Income Taxes" for additional information. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

Alabama Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Alabama Power is subject to certain claims and legal actions arising in the ordinary course of business. Alabama Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of other natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

II-83

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings 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 would have a material effect on Alabama Power's financial statements. See Notes 2 and 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Alabama Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Notes 1, 5, and 6 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on Alabama Power's results of operations and related disclosures. 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.

Utility Regulation

Alabama Power is subject to retail regulation by the Alabama PSC and wholesale regulation by the FERC. As a result, Alabama Power applies 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 has a further effect on Alabama Power's 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 Alabama Power; 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 Alabama Power's results of operations and financial condition than they would on a non-regulated company.

As reflected in Note 2 to the financial statements under "Alabama Power – Regulatory Assets and Liabilities," 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 Alabama Power's financial statements.

Asset Retirement Obligations

The liability for AROs primarily relates to the decommissioning of Alabama Power's nuclear facility, Plant Farley, and facilities that are subject to the CCR Rule and the related state rule, principally ash ponds. In addition, Alabama Power has AROs related to various landfill sites, underground storage tanks, asbestos removal related to ongoing repair and maintenance, disposal of polychlorinated biphenyls in certain transformers, and disposal of sulfur hexafluoride gas in certain substation breakers.

Alabama Power also has identified retirement obligations related to certain transmission and distribution facilities, asbestos containing material within long-term assets not subject to ongoing repair and maintenance activities, and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the 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 retirement obligation.

II-84

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

to its AROs related to the CCR Rule and approximately $300 million to its AROs related to updated nuclear decommissioning cost site studies. The revised CCR-related cost estimates as of June 30, 2018 were based on information from feasibility studies performed on ash ponds in use at the plants Alabama Power operates. During the second quarter 2018, Alabama Power's management completed its analysis of these studies which indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology. As the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material. Alabama Power expects to periodically update its ARO cost estimates. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 6 to the financial statements for additional information.

Given the significant judgment involved in estimating AROs, Alabama Power considers the liabilities for AROs to be critical accounting estimates.

Pension and Other Postretirement Benefits

Alabama Power's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return 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 Alabama Power believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefit costs and obligations.

Key elements in determining Alabama Power's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on Southern Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. Southern Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to Southern Company's target asset allocation. For purposes of determining Alabama Power's liability related to the pension and other postretirement benefit plans, Southern Company discounts the future related cash flows using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments.

A 25 basis point change in any significant assumption (discount rate, salary increases, or long-term rate of return on plan assets) would result in a $9 million or less change in total annual benefit expense, a $99 million or less change in the projected obligation for the pension plan, and an $11 million or less change in the projected obligation for other post retirement benefit plans.

Alabama Power recorded pension costs of $27 million, $9 million, and $11 million in 2018, 2017, and 2016, respectively. Postretirement benefit costs for Alabama Power were $2 million, $3 million, and $4 million in 2018, 2017, and 2016, respectively. Such amounts are dependent on several factors including trust earnings and changes to the plans. A portion of pension and other postretirement benefit costs is capitalized based on construction-related labor charges. Pension and other postretirement benefit costs are a component of the regulated rates and generally do not have a long-term effect on net income.

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

Contingent Obligations

Alabama Power is subject to a number of federal and state laws and regulations, as well as other factors and conditions that subject it 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. Alabama Power periodically evaluates its exposure to such risks and records 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 Alabama Power's results of operations, cash flows, or financial condition.

II-85

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

Recently Issued Accounting Standards

See Note 1 to the financial statements under "Recently Adopted Accounting Standards" for additional information.

In 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Alabama Power adopted the new standard effective January 1, 2019.

Alabama Power elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby the requirements of ASU 2016-02 are applied on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Alabama Power elected the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Alabama Power 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. Alabama Power also made accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and combined lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.

Alabama Power completed the implementation of a new application to track and account for its leases and updated its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Alabama Power completed its lease inventory and determined its most significant leases involve PPAs. In the first quarter 2019, the adoption of ASU 2016-02 resulted in recording lease liabilities and right-of-use assets on Alabama Power's balance sheet each totaling approximately $195 million, with no impact on Alabama Power's statement of income.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Alabama Power's financial condition remained stable at December 31, 2018. Alabama Power's cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. Capital expenditures and other investing activities include investments to meet projected long-term demand requirements, 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. Operating cash flows provide a substantial portion of Alabama Power's cash needs. For the three-year period from 2019 through 2021, Alabama Power's projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. Alabama Power plans to finance future cash needs in excess of its operating cash flows primarily through external securities issuances, borrowings from financial institutions, or equity contributions from Southern Company. Alabama Power plans to use commercial paper to manage seasonal variations in operating cash flows and for other working capital needs. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.

Alabama Power's investments in the qualified pension plan and the nuclear decommissioning trust funds decreased in value as of December 31, 2018 as compared to December 31, 2017. No contributions to the qualified pension plan were made for the year ended December 31, 2018 and no mandatory contributions to the qualified pension plan are anticipated during 2019. Alabama Power's funding obligations for the nuclear decommissioning trust funds are based on the most recent site study completed in 2018, and the next study is expected to be conducted by 2023. See Notes 6 and 11 to the financial statements under "Nuclear Decommissioning" and "Pension Plans," respectively, for additional information.

Net cash provided from operating activities totaled $1.9 billion for 2018, an increase of $44 million as compared to 2017. The increase in cash provided from operating activities was primarily due to an increase in weather-related revenues, fuel cost recovery, and income tax refunds received in 2018, partially offset by materials and supplies purchases, the timing of vendor payments, and settlement of AROs. Net cash provided from operating activities totaled $1.8 billion for 2017, a decrease of $112 million as compared to 2017. The decrease in cash provided from operating activities was primarily due to the timing of income tax payments in 2017 and the receipt of income tax refunds in 2016 as a result of bonus depreciation, partially offset by the voluntary contribution to the qualified pension plan in 2016.

II-86

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

Net cash used for investing activities totaled $2.3 billion for 2018, $1.9 billion for 2017, and $1.4 billion for 2016. These activities were primarily related to gross property additions for environmental, distribution, transmission, and steam generation assets.

Net cash provided from financing activities totaled $177 million in 2018 primarily due to issuances of long-term debt and additional capital contributions from Southern Company, partially offset by the payment of common stock dividends and a maturity of long-term debt. Net cash provided from financing activities totaled $163 million in 2017 primarily due to issuances of long-term debt and additional capital contributions from Southern Company, partially offset by the payment of common stock dividends and maturities of long-term debt. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for 2018 included increases of $2.84 billion in property, plant, and equipment primarily due to $1.35 billion in AROs and additions to nuclear, distribution, and transmission assets. Other changes include $522 million in capital contributions from Southern Company and $295 million in long-term debt primarily due to a senior notes issuance. See Notes 6 and 8 to the financial statements for additional information related to changes in Alabama Power's AROs and financing activities, respectively.

Alabama Power's ratio of common equity to total capitalization plus short-term debt was 47.0% and 46.3% at December 31, 2018 and 2017, respectively. See Note 8 to the financial statements for additional information.

Sources of Capital

Alabama Power plans to obtain the funds to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, external security issuances, borrowings from financial institutions, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. Subsequent to December 31, 2018, Alabama Power received a capital contribution totaling $1.225 billion from Southern Company.

Security issuances are subject to regulatory approval by the Alabama PSC. Additionally, with respect to the public offering of securities, Alabama Power files registration statements with the SEC under the Securities Act of 1933, as amended. The amounts of securities authorized by the Alabama PSC are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

Alabama Power obtains 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 Alabama Power are not commingled with funds of any other company in the Southern Company system.

At December 31, 2018, Alabama Power's current liabilities exceeded current assets by $50 million. Alabama Power's current liabilities sometimes exceed 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.

At December 31, 2018, Alabama Power had approximately $313 million of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2018 were as follows:



Expires										Expires Within One Year
2019		2020		2022		Total		Unused		Term Out		No Term Out
(in millions)						(in millions)				(in millions)
$	33	$	500	$	800	$	1,333	$	1,333	$	—	$	33

See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information.

Most of these bank credit arrangements, as well as Alabama Power's term loan arrangements, contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Alabama Power defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2018, Alabama Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

Subject to applicable market conditions, Alabama Power expects to renew or replace its bank credit arrangements as needed prior to expiration. In connection therewith, Alabama Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

II-87

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

A portion of the unused credit with banks is allocated to provide liquidity support to Alabama Power's pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was $854 million at December 31, 2018.

Alabama Power also has substantial cash flow from operating activities and access to the capital markets, including a commercial paper program, to meet liquidity needs. Alabama Power may meet short-term cash needs through its commercial paper program. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support.

Details of short-term borrowings were as follows:



	Short-term Debt at the End of the Period				Short-term Debt During the Period ^(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
December 31, 2018	$	—	—	%	$	27	2.3	%	$	258
December 31, 2017	$	3	3.7	%	$	25	1.3	%	$	223
December 31, 2016	$	—	—	%	$	16	0.6	%	$	200


(*)	Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2018, 2017, and 2016.

Alabama Power believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.

Financing Activities

In June 2018, Alabama Power issued $500 million aggregate principal amount of Series 2018A 4.300% Senior Notes due July 15, 2048. The proceeds were used to repay outstanding commercial paper and for general corporate purposes, including Alabama Power's continuous construction program.

In October 2018, Alabama Power purchased and held $120 million aggregate principal amount of The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008. Alabama Power reoffered these bonds to the public in November 2018.

In November 2018, Alabama Power guaranteed a $100 million three-year bank term loan for SEGCO. See Note 9 to the financial statements under "Guarantees" for additional information.

Subsequent to December 31, 2018, Alabama Power repaid at maturity $200 million aggregate principal amount of Series Z 5.125% Senior Notes due February 15, 2019.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Alabama Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

Credit Rating Risk

At December 31, 2018, Alabama Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

II-88

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, energy price risk management, and transmission.

The maximum potential collateral requirements under these contracts at December 31, 2018 were as follows:



Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	1
At BBB- and/or Baa3	$	1
Below BBB- and/or Baa3	$	356

Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power (an affiliate of Alabama 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 Alabama Power to access capital markets and would be likely to impact the cost at which it does so.

On September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and certain of its subsidiaries (including Alabama Power).

Also on September 28, 2018, Moody's revised its rating outlook for Alabama Power from negative to stable.

As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Alabama Power, may be negatively impacted. The modifications to Rate RSE and other commitments approved by the Alabama PSC are expected to help mitigate these potential adverse impacts to certain credit metrics and will help Alabama Power meet its goal of achieving an equity ratio of approximately 55% by the end of 2025. See Note 2 to the financial statements under "Alabama Power – Rate RSE" for additional information.

Market Price Risk

Due to cost-based rate regulation and other various cost recovery mechanisms, Alabama Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, Alabama Power nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Alabama Power's policies in areas such as counterparty exposure and risk management practices. Alabama Power'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.

To mitigate future exposure to changes in interest rates, Alabama Power may enter into derivatives designated as hedges. The weighted average interest rate on $1.1 billion of long-term variable interest rate exposure at December 31, 2018 was 2.5%. If Alabama Power sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would affect annualized interest expense by approximately $11 million at December 31, 2018. See Note 1 to the financial statements under "Financial Instruments" and Note 14 to the financial statements for additional information.

To mitigate residual risks relative to movements in electricity prices, Alabama Power enters into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and financial hedge contracts for natural gas purchases. Alabama Power continues to manage a retail fuel-hedging program implemented per the guidelines of the Alabama PSC. Alabama Power had no material change in market risk exposure for the year ended December 31, 2018 when compared to the year ended December 31, 2017.

In addition, Rate ECR allows the recovery of specific costs associated with the sales of natural gas that become necessary due to operating considerations at Alabama Power's electric generating facilities. Rate ECR also allows recovery of the cost of financial instruments used for hedging market price risk up to 75% of the budgeted annual amount of natural gas purchases. Alabama Power may not engage in natural gas hedging activities that extend beyond a rolling 42-month window. Also, the premiums paid for natural gas financial options may not exceed 5% of Alabama Power's natural gas budget for that year.

II-89

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report



	2018 Changes			2017 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(6	)	$	12
Contracts realized or settled	(2		)	(1		)
Current period changes^(*)	4			(17		)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(4	)	$	(6	)


(*)	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 at December 31, 2018 and 2017 were as follows:



	2018	2017
	mmBtu Volume
	(in millions)
Commodity – Natural gas swaps	65	64
Commodity – Natural gas options	9	5
Total hedge volume	74	69

The weighted average swap contract cost above market prices was approximately $0.08 per mmBtu at December 31, 2018 and December 31, 2017. 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 natural gas hedge gains and losses are recovered through Alabama Power's retail energy cost recovery clause.

At December 31, 2018 and 2017, substantially all of Alabama Power's energy-related derivative contracts were designated as regulatory hedges and were related to Alabama Power's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the energy cost recovery clause. Certain other gains and losses on energy-related derivatives, designated as cash flow hedges, are initially deferred in OCI before being recognized in income in the same period as the hedged transaction. 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 and were not material for any year presented.

Alabama Power uses 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. See Note 13 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts, which are primarily Level 2 of the fair value hierarchy, at December 31, 2018 were as follows:



				Fair Value Measurements
				December 31, 2018
	Total			Maturity
	Fair Value			Year 1			Years 2&3
	(in millions)
Level 1	$	—		$	—		$	—
Level 2	(4		)	(1		)	(3		)
Level 3	—			—			—
Fair value of contracts outstanding at end of period	$	(4	)	$	(1	)	$	(3	)

Alabama Power is exposed to market price risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts. Alabama Power only enters into agreements and material transactions with counterparties that have

II-90

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

investment grade credit ratings by Moody's and S&P, or with counterparties who have posted collateral to cover potential credit exposure. Therefore, Alabama Power does 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.

Capital Requirements and Contractual Obligations

The construction program of Alabama Power is currently estimated to total $1.8 billion for 2019, $1.6 billion for 2020, $1.6 billion for 2021, $1.4 billion for 2022, and $1.5 billion for 2023. The construction program includes capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $226 million for 2019, $68 million for 2020, $118 million for 2021, $112 million for 2022, and $111 million for 2023. These estimated expenditures do not include any potential compliance costs associated with pending regulation of CO₂ emissions from fossil-fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and "– Global Climate Issues" herein for additional information.

Alabama Power also anticipates costs associated with closure-in-place and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in Alabama Power's ARO liabilities. These costs, which are expected to change and could change materially as underlying assumptions are refined and the cost, method, and timing of compliance activities continue to be evaluated, are currently estimated to be $232 million for 2019, $238 million for 2020, $246 million for 2021, $252 million for 2022, and $258 million for 2023. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 6 to the financial statements for additional information. Costs associated with the CCR Rule are expected to be recovered through Rate CNP Compliance.

As a result of NRC requirements, Alabama Power has external trust funds for nuclear decommissioning costs; however, Alabama Power currently has no additional funding requirements. For additional information, see Note 6 to the financial statements under "Nuclear Decommissioning."

In addition, as discussed in Note 11 to the financial statements, Alabama Power provides postretirement benefits to substantially all employees and funds trusts to the extent required by the Alabama PSC and the FERC.

Funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, pension and other postretirement benefit plans, preferred stock dividends, leases, other purchase commitments, and ARO settlements are detailed in the contractual obligations table that follows. See Notes 1, 6, 8, 9, 11, and 14 to the financial statements for additional information.

II-91

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Alabama Power Company 2018 Annual Report

Contractual Obligations

Contractual obligations at December 31, 2018 were as follows:



	2019		2020- 2021		2022- 2023		After 2023		Total
	(in millions)
Long-term debt^(a) —
Principal	$	200	$	560	$	1,050	$	6,377	$	8,187
Interest	330		630		575		4,751		6,286
Preferred stock dividends^(b)	15		29		29		—		73
Financial derivative obligations^(c)	4		6		—		—		10
Operating leases^(d)	12		17		9		1		39
Capital lease	1		1		1		1		4
Purchase commitments —
Capital^(e)	1,671		3,049		2,536		—		7,256
Fuel^(f)	1,072		1,342		531		1,108		4,053
Purchased power^(g)	83		178		140		512		913
Other^(h)	42		61		61		277		441
ARO settlements⁽ⁱ⁾	232		485		510		—		1,227
Pension and other postretirement benefit plans^(j)	16		32		—		—		48
Total	$	3,678	$	6,390	$	5,442	$	13,027	$	28,537

(a)

All amounts are reflected based on final maturity dates. Alabama Power plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates at December 31, 2018, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately).


(b)	Preferred stock does not mature; therefore, amounts are provided for the next five years only.


(c)	Includes derivative liabilities related to cash flow hedges of forecasted debt, as well as energy-related derivatives. For additional information, see Notes 1 and 14 to the financial statements.


(d)	Excludes PPAs that are accounted for as leases and are included in purchased power.

(e)

Alabama Power provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel, capital expenditures covered under LTSAs, and estimated capital expenditures for AROs, which are reflected in "Fuel," "Other," and "ARO settlements," respectively. At December 31, 2018, purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" herein for additional information.

(f)

Includes commitments to purchase coal, nuclear fuel, and natural gas, 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. Amounts reflected for natural gas purchase commitments have been estimated based on the NYMEX future prices at December 31, 2018.


(g)	Estimated minimum long-term obligations for various long-term commitments for the purchase of capacity and energy.


(h)	Includes LTSAs and contracts for the procurement of limestone. LTSAs include price escalation based on inflation indices.

(i)

Represents estimated costs for a five-year period associated with closing and monitoring ash ponds in accordance with the CCR Rule and the related state rule, which are reflected in Alabama Power's ARO liabilities. Material expenditures in future years for ARO settlements also will be required for ash ponds, nuclear decommissioning, and other liabilities reflected in Alabama Power's AROs. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 6 to the financial statements for additional information.

(j)

Alabama Power forecasts contributions to the pension and other postretirement benefit plans over a three-year period. Alabama Power anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from Alabama Power's corporate assets. See Note 11 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from Alabama Power's corporate assets.

II-92

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Georgia Power Company 2018 Annual Report

OVERVIEW

Business Activities

Georgia Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located within the State of Georgia and to wholesale customers in the Southeast.

Many factors affect the opportunities, challenges, and risks of Georgia Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, including CCR rules, reliability, fuel, capital expenditures, including new generating facilities and expanding and improving transmission and distribution facilities, and restoration following major storms. Georgia Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future. On April 3, 2018, the Georgia PSC approved the Georgia Power Tax Reform Settlement Agreement, which provides for a total of $330 million in customer refunds for 2018 and 2019 and the deferral of certain revenues and tax benefits to be addressed in the Georgia Power 2019 Base Rate Case. The Georgia PSC also approved an increase to Georgia Power's retail equity ratio to address some of the negative cash flow and credit metric impacts of the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate Plans" herein for additional information on the Georgia Power Tax Reform Settlement Agreement.

Georgia Power continues to focus on several key performance indicators, including, but not limited to, customer satisfaction, plant availability, system reliability, the execution of major construction projects, and net income. Georgia Power's financial success is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys to evaluate Georgia Power's results and generally targets the top quartile of these surveys in measuring performance.

See RESULTS OF OPERATIONS herein for information on Georgia Power's financial performance.

Plant Vogtle Units 3 and 4 Status

II-93

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and certain of MEAG's wholly-owned subsidiaries entered into certain amendments to their joint ownership agreements to implement the provisions of the Vogtle Owner Term Sheet.

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

See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

Earnings

Georgia Power's 2018 net income after dividends on preferred and preference stock was $0.8 billion, representing a $621 million, or 43.9%, decrease from the previous year. The decrease was due primarily to a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss related to Georgia Power's construction of Plant Vogtle Units 3 and 4, revenues deferred as a regulatory liability for customer bill credits related to the Tax Reform Legislation, an adjustment for an expected refund to retail customers as a result of Georgia Power's retail ROE exceeding the allowed retail ROE range under the 2013 ARP in 2018, and higher non-fuel operations and maintenance expenses. Partially offsetting the decrease were lower federal income tax expense as a result of the Tax Reform Legislation and an increase in retail revenues associated with colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017.

Georgia Power's 2017 net income after dividends on preferred and preference stock was $1.4 billion, representing an $84 million, or 6.3%, increase from the previous year. The increase was due primarily to lower non-fuel operations and maintenance expenses, primarily as a result of cost containment and modernization initiatives, partially offset by lower revenues resulting from milder weather and lower customer usage as compared to 2016.

RESULTS OF OPERATIONS

A condensed income statement for Georgia Power follows:



	Amount		Increase (Decrease) from Prior Year
	2018		2018			2017
	(in millions)
Operating revenues	$	8,420	$	110		$	(73	)
Fuel	1,698		27			(136		)
Purchased power	1,153		115			159
Other operations and maintenance	1,860		136			(279		)
Depreciation and amortization	923		28			40
Taxes other than income taxes	437		28			4
Estimated loss on Plant Vogtle Units 3 and 4	1,060		1,060			—
Total operating expenses	7,131		1,394			(212		)
Operating income	1,289		(1,284		)	139
Interest expense, net of amounts capitalized	397		(22		)	31
Other income (expense), net	115		11			23
Income taxes	214		(616		)	50
Net income	793		(635		)	81
Dividends on preferred and preference stock	—		(14		)	(3		)
Net income after dividends on preferred and preference stock	$	793	$	(621	)	$	84

II-94

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

Operating Revenues

Operating revenues for 2018 were $8.4 billion, reflecting a $110 million increase from 2017. Details of operating revenues were as follows:



	2018			2017
	(in millions)
Retail — prior year	$	7,738		$	7,772
Estimated change resulting from —
Rates and pricing	(363		)	114
Sales growth (decline)	92			(33		)
Weather	131			(166		)
Fuel cost recovery	154			51
Retail — current year	7,752			7,738
Wholesale revenues —
Non-affiliates	163			163
Affiliates	24			26
Total wholesale revenues	187			189
Other operating revenues	481			383
Total operating revenues	$	8,420		$	8,310
Percent change	1.3		%	(0.9		)%

Retail revenues of $7.8 billion in 2018 increased $14 million, or 0.2%, compared to 2017. The significant factors driving this change are shown in the preceding table. The decrease in rates and pricing was primarily due to revenues deferred as a regulatory liability for customer bill credits related to the Tax Reform Legislation and an adjustment for an expected refund to retail customers as a result of Georgia Power's retail ROE exceeding the allowed retail ROE range under the 2013 ARP in 2018. See Note 2 to the financial statements under "Georgia Power – Rate Plans" for additional information.

Retail revenues of $7.7 billion in 2017 decreased $34 million, or 0.4%, compared to 2016. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing was primarily due to an increase in revenues related to the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction – Regulatory Matters" for additional information on the NCCR tariff.

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

Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.

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



	2018		2017		2016
	(in millions)
Capacity and other	$	54	$	67	$	72
Energy	109		96		103
Total non-affiliated	$	163	$	163	$	175

Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant

II-95

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.

Wholesale revenues from non-affiliated sales remained flat in 2018 as compared to 2017. Capacity revenues decreased $13 million, offset by a $13 million increase in energy revenues. The decrease in capacity revenues was primarily due to the expiration of a wholesale contract in the fourth quarter 2017. The increase in energy revenues was primarily due to increased demand, partially offset by the effects of expired contracts. Wholesale revenues from non-affiliated sales decreased $12 million, or 6.9%, in 2017 as compared to 2016. The decrease was related to decreases of $5 million in capacity revenues and $7 million in energy revenues. The decrease in capacity revenues reflects the expiration of wholesale contracts in the first and second quarters of 2016. The decrease in energy revenues was primarily due to lower demand and the effects of the expired contracts.

Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost. In 2018, wholesale revenues from sales to affiliates decreased $2 million as compared to 2017. In 2017, wholesale revenues from sales to affiliates decreased $16 million as compared to 2016 due to a 42.8% decrease in KWH sales as a result of the lower market cost of available energy compared to the cost of Georgia Power-owned generation.

Other operating revenues increased $98 million, or 25.6%, in 2018 from the prior year largely due to $94 million of revenues primarily from unregulated sales of products and services that were reclassified as other revenues as a result of the adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). In prior periods, these revenues were included in other income (expense), net. See Note 1 to the financial statements for additional information regarding Georgia Power's adoption of ASC 606.

Other operating revenues decreased $11 million, or 2.8%, in 2017 from the prior year primarily due to a $15 million decrease in open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts, and a $14 million adjustment in 2016 for customer temporary facilities services revenues, partially offset by a $13 million increase in outdoor lighting sales revenues due to increased sales in new and replacement markets, primarily attributable to LED conversions.

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2018 and the percent change from the prior year were as follows:



	Total KWHs	Total KWH Percent Change				Weather-Adjusted Percent Change
	2018	2018		2017		2018		2017
	(in billions)
Residential	28.3	8.4	%	(5.2	)%	2.6	%	(0.2	)%
Commercial	33.0	2.5		(2.4	)	1.6		(0.9	)
Industrial	23.7	0.6		(1.0	)	0.2		(0.1	)
Other	0.5	(6.0	)	(4.2	)	(6.3	)	(4.0	)
Total retail	85.5	3.8		(2.9	)	1.5	%	(0.4	)%
Wholesale
Non-affiliates	3.2	(4.2	)	(4.0	)
Affiliates	0.5	(34.2	)	(42.8	)
Total wholesale	3.7	(10.1	)	(15.3	)
Total energy sales	89.2	3.1	%	(3.6	)%

Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers.

In 2018, KWH sales for the residential class increased 8.4% compared to 2017 primarily due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017. Weather-adjusted residential KWH sales and weather-adjusted commercial KWH sales increased by 2.6% and 1.6%, respectively, largely due to customer growth. Weather-adjusted industrial KWH sales were essentially flat primarily due to increased demand in the primary and fabricated metal sectors, offset by decreased demand in the textiles and stone, clay, and glass sectors. Additionally, customer usage for all customer classes increased due to the negative impacts of Hurricane Irma in 2017.

II-96

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

In 2017, KWH sales for the residential class decreased 5.2% compared to 2016 primarily due to milder weather in 2017. Weather-adjusted residential KWH sales decreased by 0.2% primarily due to a decline in average customer usage resulting from an increase in multi-family housing and energy saving initiatives, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased by 0.9% primarily due to a decline in average customer usage resulting from an increase in electronic commerce transactions and energy saving initiatives, partially offset by customer growth. Weather-adjusted industrial KWH sales were essentially flat primarily due to decreased demand in the chemicals and paper sectors, offset by increased demand in the textile, non-manufacturing, and rubber sectors. Additionally, Hurricane Irma negatively impacted customer usage for all customer classes in 2017.

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

Fuel and Purchased Power Expenses

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

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



	2018	2017	2016
Total generation (in billions of KWHs)	65.2	63.2	68.4
Total purchased power (in billions of KWHs)	27.9	26.9	24.8
Sources of generation (percent) —
Gas	42	41	38
Coal	30	32	36
Nuclear	25	25	24
Hydro	3	2	2
Cost of fuel, generated (in cents per net KWH) —
Gas	2.75	2.68	2.36
Coal	3.21	3.17	3.28
Nuclear	0.82	0.83	0.85
Average cost of fuel, generated (in cents per net KWH)	2.40	2.36	2.33
Average cost of purchased power (in cents per net KWH)⁽^*)	4.79	4.62	4.53

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

Fuel and purchased power expenses were $2.9 billion in 2018, an increase of $142 million, or 5.2%, compared to 2017. The increase was primarily due to a $74 million increase in the average cost of fuel and purchased power primarily related to higher natural gas and energy prices and an increase of $68 million related to the volume of KWHs generated and purchased primarily due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017.

Fuel and purchased power expenses were $2.7 billion in 2017, an increase of $23 million, or 0.9%, compared to 2016. The increase was primarily due to an $84 million increase in the average cost of fuel and purchased power primarily related to higher natural gas prices, partially offset by a net decrease of $61 million related to the volume of KWHs generated and purchased primarily due to milder weather, resulting in lower customer demand.

Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.

Fuel

Fuel expense was $1.7 billion in 2018, an increase of $27 million, or 1.6%, compared to 2017. The increase was primarily due to an increase of 2.6% in the average cost of natural gas per KWH generated and an increase of 1.9% in the volume of KWHs generated largely due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017. Fuel expense was $1.7 billion in 2017, a decrease of $136 million, or 7.5%,

II-97

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

compared to 2016. The decrease was primarily due to a decrease of 7.7% in the volume of KWHs generated largely due to milder weather, resulting in lower customer demand, partially offset by an increase of 13.6% in the average cost of natural gas per KWH generated.

Purchased Power - Non-Affiliates

Purchased power expense from non-affiliates was $430 million in 2018, an increase of $14 million, or 3.4%, compared to 2017. The increase was primarily due to an 8.5% increase in the average cost per KWH purchased primarily due to higher energy prices, partially offset by a decrease of 3.8% in volume of KWHs purchased primarily due to the higher market cost of available energy as compared to Southern Company system resources. Purchased power expense from non-affiliates was $416 million in 2017, an increase of $55 million, or 15.2%, compared to 2016. The increase was primarily due to a 13.4% increase in the volume of KWHs purchased primarily due to unplanned outages at Georgia Power-owned generating units.

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

Purchased Power - Affiliates

Purchased power expense from affiliates was $723 million in 2018, an increase of $101 million, or 16.2%, compared to 2017. The increase was primarily due to a 6.3% increase in the volume of KWHs purchased due to colder weather in the first quarter 2018 and scheduled generation outages and warmer weather in the second and third quarters 2018 and a 3.0% increase in the average cost per KWH purchased primarily resulting from higher energy prices. Purchased power expense from affiliates was $622 million in 2017, an increase of $104 million, or 20.1%, compared to 2016. The increase was primarily due to a 7.0% increase in the volume of KWHs purchased to support Southern Company system transmission reliability and as a result of unplanned outages at Georgia Power-owned generating units and a 1.8% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices.

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

Other Operations and Maintenance Expenses

In 2018, other operations and maintenance expenses increased $136 million, or 7.9%, compared to 2017. The increase was primarily due to $88 million of expenses from unregulated sales of products and services that were reclassified to other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. Also contributing to the increase were a $39 million decrease in gains on sales of assets and a $28 million increase in transmission and distribution overhead line maintenance, primarily related to additional vegetation management, partially offset by a decrease of $18 million associated with an employee attrition plan in 2017. See Note 1 to the financial statements for additional information regarding Georgia Power's adoption of ASC 606.

In 2017, other operations and maintenance expenses decreased $279 million, or 13.9%, compared to 2016. The decrease was primarily due to cost containment and modernization activities implemented in the third quarter 2016 that contributed to decreases of $85 million in generation maintenance costs, $46 million in transmission and distribution overhead line maintenance, $22 million in employee benefits, and $22 million in customer accounts and sales costs. Other factors include a $40 million increase in gains on sales of assets, a $19 million decrease in scheduled generation outage costs, and a $15 million decrease in customer assistance expenses, primarily in demand-side management costs related to the timing of new programs.

Depreciation and Amortization

Depreciation and amortization increased $28 million, or 3.1%, in 2018 compared to 2017. The increase was primarily due to additional plant in service.

Depreciation and amortization increased $40 million, or 4.7%, in 2017 compared to 2016. The increase was primarily due to a $33 million increase related to additional plant in service and a $14 million decrease in amortization of regulatory liabilities related to other cost of removal obligations that expired in December 2016, partially offset by a $9 million decrease in depreciation related to generating unit retirements in 2016 and amortization of regulatory assets related to certain cancelled environmental and fuel conversion projects that expired in December 2016.

See Note 5 to the financial statements under "Depreciation and Amortization" for additional information.

II-98

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

Taxes Other Than Income Taxes

In 2018, taxes other than income taxes increased $28 million, or 6.8%, compared to 2017 primarily due to increases of $19 million in property taxes as a result of an increase in the assessed value of property and $11 million in municipal franchise fees largely related to higher retail revenues. In 2017, taxes other than income taxes increased $4 million, or 1.0%, compared to 2016.

Estimated Loss on Plant Vogtle Units 3 and 4

Interest Expense, Net of Amounts Capitalized

In 2018, interest expense, net of amounts capitalized decreased $22 million, or 5.3%, compared to 2017 and increased $31 million, or 8.0%, compared to 2016 primarily due to changes in outstanding borrowings.

Other Income (Expense), Net

In 2018, other income (expense), net increased $11 million compared to the prior year primarily due to an increase in AFUDC equity of $29 million resulting from a higher AFUDC rate due to a higher equity ratio and lower short-term borrowings, partially offset by a decrease of $21 million associated with revenues and expenses, net primarily from unregulated sales of products and services. In 2018, these revenues and expenses are included in other revenues and other operations and maintenance expenses, respectively, as a result of the adoption of ASC 606. See Note 1 to the financial statements for additional information regarding Georgia Power's adoption of ASC 606.

In 2017, other income (expense), net increased $23 million compared to the prior year primarily due to a $28 million decrease in the non-service cost components of net periodic pension and other postretirement benefit costs, a $7 million increase in third party infrastructure services revenue, and a $6 million increase in wholesale operating fee revenue associated with contractual targets, partially offset by a $10 million increase in charitable donations and an $8 million decrease in AFUDC equity resulting from higher short-term borrowings. See Notes 1 under "Recently Adopted Accounting Standards" and 11 to the financial statements for additional information on Georgia Power's net periodic pension and other postretirement benefit costs.

Income Taxes

Income taxes decreased $616 million, or 74.2%, in 2018 compared to the prior year primarily due to a lower federal income tax rate as a result of the Tax Reform Legislation and the reduction in pre-tax earnings resulting from the estimated probable loss related to Plant Vogtle Units 3 and 4.

Income taxes increased $50 million, or 6.4%, in 2017 compared to the prior year primarily due to higher pre-tax earnings, partially offset by an adjustment related to the Tax Reform Legislation.

See Note 10 to the financial statements for additional information.

Dividends on Preferred and Preference Stock

Dividends on preferred and preference stock decreased $14 million, or 100.0%, in 2018 compared to 2017 and decreased $3 million, or 17.6%, in 2017 compared to 2016. The decreases were due to the redemption in October 2017 of all outstanding shares of Georgia Power's preferred and preference stock. See Note 8 to the financial statements under "Outstanding Classes of Capital Stock – Georgia Power" for additional information.

Effects of Inflation

Georgia Power is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on Georgia Power's results of operations has not been substantial in recent years.

II-99

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

FUTURE EARNINGS POTENTIAL

General

Georgia Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located in the State of Georgia and to wholesale customers in the Southeast. Prices for electricity provided by Georgia Power to retail customers are set by the Georgia PSC under cost-based regulatory principles. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Utility Regulation" herein and Note 2 to the financial statements under "Georgia Power" for additional information about regulatory matters.

The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of Georgia Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power's business of providing electric service. These factors include Georgia Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs, continued customer growth, and the weak pace of growth in electricity use per customer, especially in residential and commercial markets. Plant Vogtle Units 3 and 4 construction and rate recovery are also major factors. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and more multi-family home construction, all of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.

Environmental Matters

Georgia Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Georgia Power maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future electric generating unit retirement and replacement decisions, 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 Georgia Power's transmission and distribution systems. A major portion of these costs is expected to be recovered through retail rates. The ultimate impact of environmental laws and regulations and the GHG goals discussed herein will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, and the outcome of pending and/or future legal challenges.

New or revised environmental laws and regulations could affect many areas of Georgia Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be recovered in rates on a timely basis. Georgia Power's Environmental Compliance Cost Recovery (ECCR) tariff allows for the recovery of capital and operations and maintenance costs related to environmental controls mandated by state and federal regulations. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity, 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 for some may have the potential to ultimately affect their demand for electricity.

Through 2018, Georgia Power has invested approximately $6.0 billion in environmental capital retrofit projects to comply with environmental requirements, with annual totals of approximately $0.5 billion, $0.3 billion, and $0.2 billion for 2018, 2017, and 2016, respectively. 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, Georgia Power's current compliance strategy estimates capital expenditures of $0.7 billion from 2019 through 2023, with annual totals of approximately $0.2 billion, $0.1 billion, $0.1 billion, $0.2 billion, and $0.1 billion for 2019, 2020, 2021, 2022, and 2023, respectively. These estimates do not include any potential compliance costs associated with pending regulation of CO₂ emissions from fossil fuel-fired electric generating units. See "Global Climate Issues" herein for additional information. Georgia Power also anticipates substantial expenditures associated with ash pond closure and ground water monitoring under the CCR Rule, which

II-100

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

are reflected in Georgia Power's ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 6 to the financial statements for additional information.

Environmental Laws and Regulations

Air Quality

The EPA has set National Ambient Air Quality Standards (NAAQS) for six air pollutants (carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter, and SO₂) to protect and improve the nation's air quality, which it reviews and revises periodically. Following a NAAQS revision, states are required to develop an EPA-approved plan to protect air quality. These state plans can require additional emission controls, improvements in control efficiency, or fuel changes which can result in increased compliance and operational costs. NAAQS requirements can also adversely affect the siting of new electric generating facilities. All areas within Georgia Power's service territory have been designated as attainment for all NAAQS except for a seven-county area within metropolitan Atlanta that is not in attainment with the 2015 ozone NAAQS and the area surrounding Plant Hammond, which will not be designated attainment or nonattainment for the 2010 SO₂standard until December 2020. If areas are designated as nonattainment in the future, increased compliance costs could result. See "Retail Regulatory Matters – Integrated Resource Plan" herein for information regarding Georgia Power's request to decertify and retire Plant Hammond.

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 (e.g. coal, natural gas, oil, and nuclear generating plants) and manufacturing facilities. The regulation requires plant-specific studies to determine applicable CWIS changes to protect organisms that either get caught on the intake screens (impingement) or are drawn into the cooling system (entrainment). Georgia Power is conducting these studies and currently anticipates applicable CWIS changes may include fish-friendly CWIS screens with fish return systems and minor additions of monitoring equipment at certain plants. However, the ultimate 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 National Pollutant Discharge Elimination System (NPDES) permit based on site-specific factors, and the outcome of any legal challenges.

In 2015, the EPA finalized the steam electric effluent limitations guidelines (ELG) rule (2015 ELG Rule) that set national standards for wastewater discharges from new and existing steam electric generating units generating greater than 50 MWs. The 2015 ELG Rule prohibits effluent discharges of certain waste streams and imposes stringent limits on flue gas desulfurization (scrubber) wastewater discharges. The revised technology-based limits and the CCR Rule require extensive changes to existing ash and wastewater management systems or the installation and operation of new ash and wastewater management systems. Compliance with the 2015 ELG Rule is expected to require capital expenditures and increased operational costs primarily for Georgia Power's coal-fired electric generation. State environmental agencies will incorporate specific compliance applicability dates in the NPDES permitting process for each ELG waste stream no later than December 31, 2023. The EPA is scheduled to issue a new rulemaking by December 2019 that could revise the limitations and applicability dates of two of the waste streams regulated in the 2015 ELG Rule. The impact of any changes to the 2015 ELG Rule will depend on the content of the new rule and the outcome of any legal challenges.

In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) jointly published a final rule that revised the regulatory definition of waters of the United States (WOTUS) for all CWA programs. The rule significantly expanded the scope of federal jurisdiction over waterbodies (such as rivers, streams, canals, and wastewater treatment ponds), which could impact new generation projects and permitting and reporting requirements associated with the installation, expansion, and maintenance of transmission and distribution projects. The EPA and the Corps are expected to publish a final rule in 2019 to replace the 2015

II-101

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

WOTUS definition. The impact of any changes to the 2015 WOTUS rule will depend on the content of this final rule and the outcome of any legal challenges.

Coal Combustion Residuals

In 2015, the EPA finalized non-hazardous solid waste regulations for the disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments (ash ponds) at active generating power plants. In addition to the EPA's CCR Rule, the State of Georgia has also finalized its own regulations regarding the handling of CCR. The EPA's CCR Rule requires landfills and ash ponds to be evaluated against a set of performance criteria and potentially closed if minimum criteria are not met. Closure of existing landfills and ash ponds could require installation of equipment and infrastructure to manage CCR in accordance with the CCR Rule. Based on cost estimates for closure and monitoring of landfills and ash ponds pursuant to the CCR Rule, Georgia Power recorded an update to the AROs for each CCR unit in 2015. As further analysis is performed and closure details are developed, Georgia Power has continued to periodically update these cost estimates, as discussed further below.

On August 21, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision suggesting the EPA should regulate previously-excluded inactive ash ponds located at retired generation facilities and questioning both the ability of unlined ash ponds to continue operating no matter the performance criteria results and the classification of clay-lined landfills and ash ponds. These developments could impact the expected timing of Georgia Power's landfill and ash pond closure activities, but the extent of any impact will depend on the outcome of ongoing litigation, anticipated EPA rulemaking action to establish further guidance, and the outcome of any legal challenges.

Georgia Power expects to periodically update its ARO cost estimates. Absent continued recovery of ARO costs through regulated rates, Georgia Power's results of operations, cash flows, and financial condition could be materially impacted. See "Retail Regulatory Matters – Integrated Resource Plan" and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 6 to the financial statements for additional information.

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

Nuclear Decommissioning

Environmental Remediation

Georgia Power 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, Georgia Power may also incur substantial costs to clean up affected sites. Georgia Power conducts studies to determine the extent of any required cleanup and has recognized the estimated costs to clean up known impacted sites in its financial statements. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. Georgia Power has received authority from the Georgia PSC to recover approved environmental compliance costs through regulatory mechanisms. Georgia Power 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.

II-102

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

Global Climate Issues

On August 31, 2018, the EPA published a proposed rule known as the Affordable Clean Energy (ACE) Rule, which is intended to replace a regulation enacted in 2015 known as the Clean Power Plan (CPP), that would limit CO₂ emissions from existing fossil fuel-fired electric generating units. The CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule would require states to develop GHG unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of January 1, 2019, Georgia Power has ownership interests in 20 fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to Georgia Power is currently unknown and will depend on changes between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal challenges.

The EPA's GHG reporting rule requires annual reporting of GHG emissions expressed in terms of metric tons of CO₂ equivalent emissions for a company's operational control of facilities. Based on ownership or financial control of facilities, Georgia Power's 2017 GHG emissions were approximately 30 million metric tons of CO₂ equivalent. The preliminary estimate of Georgia Power's 2018 GHG emissions on the same basis is approximately 30 million metric tons of CO₂ equivalent.

Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, complete ongoing construction projects, including Georgia Power's interest in Plant Vogtle Units 3 and 4, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies.

FERC Matters

On May 10, 2018, AMEA and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies (including Georgia Power) claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Georgia Power's) open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requested that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Georgia Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through December 31, 2018, the estimated maximum potential refund is not expected to be material to Georgia Power's results of operations or cash flows. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

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 2013 ARP, which includes traditional base tariff rates, Demand-Side Management (DSM) tariffs, ECCR tariffs, and Municipal Franchise Fee (MFF) tariffs. Georgia Power is scheduled to file a base rate case by July 1, 2019, which may continue or modify these 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 separate fuel cost recovery tariff. See Note 2 to the financial statements under "Georgia Power – Rate Plans," " – Fuel Cost Recovery," and " – Nuclear Construction" for additional information.

II-103

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

On November 16, 2018, Georgia Power completed the sale of its natural gas lateral pipeline serving Plant McDonough Units 4 through 6 to SNG at net book value, as approved by the Georgia PSC on January 16, 2018. Georgia Power expects payment of $142 million from SNG to occur in the first quarter 2020. During the interim period, Georgia Power will receive a discounted shipping rate to reflect the delayed consideration. Southern Company Gas, an affiliate of Georgia Power, owns a 50% equity interest in SNG.

Rate Plans

There were no changes to Georgia Power's traditional base tariff rates, ECCR tariff, DSM tariffs, or MFF tariff in 2017 or 2018.

Under the 2013 ARP, Georgia Power's retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by Georgia Power. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. In 2016, Georgia Power's retail ROE exceeded 12.00%, and Georgia Power refunded to retail customers in 2018 approximately $40 million as approved by the Georgia PSC. On February 5, 2019, the Georgia PSC approved a settlement between Georgia Power and the staff of the Georgia PSC under which Georgia Power's retail ROE for 2017 was stipulated to exceed 12.00% and Georgia Power will reduce certain regulatory assets by approximately $4 million in lieu of providing refunds to retail customers. In 2018, Georgia Power's retail ROE exceeded 12.00%, and Georgia Power accrued approximately $100 million to refund to retail customers, subject to review and approval by the Georgia PSC.

Integrated Resource Plan

II-104

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

of recovery for costs incurred of approximately $50 million is expected to be determined by the Georgia PSC in the Georgia Power 2019 Base Rate Case.

A decision from the Georgia PSC on the 2019 IRP is expected in mid-2019.

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

Fuel Cost Recovery

Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. On August 16, 2018, the Georgia PSC approved the deferral of Georgia Power's next fuel case to no later than March 16, 2020, with new rates, if any, to be effective June 1, 2020. 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 under or over recovered fuel balance exceeds $200 million. At December 31, 2018, Georgia Power's under recovered fuel balance was $115 million.

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 48-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 Georgia Power's revenues or net income, but will affect operating cash flows.

Storm Damage Recovery

Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, for incremental operations and maintenance costs of damage from major storms to its transmission and distribution facilities. At December 31, 2018, the total balance in the regulatory asset related to storm damage was $416 million. During October 2018, Hurricane Michael caused significant damage to Georgia Power's transmission and distribution facilities. The incremental restoration costs related to this hurricane deferred in the regulatory asset for storm damage totaled approximately $115 million. Hurricanes Irma and Matthew also caused significant damage to Georgia Power's transmission and distribution facilities during September 2017 and October 2016, respectively. The incremental restoration costs related to Hurricanes Irma and Matthew deferred in the regulatory asset for storm damage totaled approximately $250 million. The rate of storm damage cost recovery is expected to be adjusted as part of the Georgia Power 2019 Base Rate Case and further adjusted in future regulatory proceedings as necessary. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements under "Georgia Power – Storm Damage Recovery" for additional information regarding Georgia Power's storm damage reserve.

II-105

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

Nuclear Construction

Cost and Schedule



	(in billions)
Base project capital cost forecast^(a)(b)	$	8.0
Construction contingency estimate	0.4
Total project capital cost forecast^(a)(b)	8.4
Net investment as of December 31, 2018^(b)	(4.6		)
Remaining estimate to complete^(a)	$	3.8


(a)	Excludes financing costs expected to be capitalized through AFUDC of approximately $315 million.


(b)	Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds.

II-106

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

Southern Nuclear, was underway as of December 31, 2018 and is expected to be completed during the second quarter 2019. Georgia Power currently does not anticipate any material changes to the total estimated project capital cost forecast for Plant Vogtle Units 3 and 4 or the expected in-service dates of November 2021 and November 2022, respectively, resulting from this verification process. However, the ultimate impact on cost and schedule, if any, will not be known until the verification process is completed. Georgia Power is required to report the results and any project impacts to the Georgia PSC by May 15, 2019.

Joint Owner Contracts

Amendments to the Vogtle Joint Ownership Agreements

II-107

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

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.

II-108

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

Purchase of PTCs During Commercial Operation

Potential Funding to MEAG Project J

Under the terms of the MEAG Funding Agreement, Georgia Power may cancel the project in lieu of providing funding in the form of advances or PTC purchases.

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

Regulatory Matters

II-109

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

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 amounts 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 prudence decisions on cost recovery will be made at a later date, 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 upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. 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 $100 million, $25 million, and $20 million in 2018, 2017, and 2016, respectively, and are estimated to have negative earnings impacts of approximately $75 million in 2019 and an aggregate of approximately $615 million from 2020 to 2022.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. (GIPL) and Partnership for Southern Equity, Inc. (PSE) filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. On March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's decision and denial of Georgia Watch's motion for reconsideration. On December 21, 2018, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. On January 9, 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. Georgia Power believes the appeal has no merit; however, an adverse outcome in the appeal combined with subsequent adverse action by the Georgia PSC could have a material impact on Georgia Power's results of operations, financial condition, and liquidity.

II-110

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

an administrative claim filed in the Westinghouse bankruptcy proceedings. Through the nineteenth VCM, the Georgia PSC has approved total construction capital costs incurred through June 30, 2018 of $5.4 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds). In addition, the staff of the Georgia PSC requested, and Georgia Power agreed, to file its twentieth VCM report concurrently with the twenty-first VCM report by August 31, 2019.

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

DOE Financing

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

Income Tax Matters

Federal Tax Reform Legislation

In December 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduced the federal corporate income tax rate to 21%, retained normalization provisions for public utility property and existing renewable energy incentives, and repealed the corporate alternative minimum tax. In addition, under the Tax Reform Legislation, net operating losses generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income of the subsequent tax year. The projected reduction of Southern Company's consolidated income tax liability resulting from the tax rate reduction also delays the expected utilization of existing tax credit carryforwards at Georgia Power. See Note 10 to the financial statements for information on Southern Company's joint consolidated income tax allocation agreement.

Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provided for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes and their application under GAAP, Georgia Power considered all amounts recorded in the financial statements as a result of the Tax Reform Legislation "provisional" as discussed in SAB 118 and subject to revision prior to filing its 2017 tax return in the fourth quarter 2018. Georgia Power recognized tax benefits of $50 million and $8 million in 2018 and 2017, respectively, for a total of $58 million as a result of the Tax Reform Legislation. In addition, in total, Georgia Power recorded a $147 million decrease in regulatory assets and a $3.0 billion increase in regulatory liabilities as a result of the Tax Reform Legislation and $2 million of stranded excess deferred tax balances in AOCI at December 31, 2017 were adjusted through retained earnings in 2018. As of December 31, 2018, Georgia Power considered the measurement of impacts from the Tax Reform Legislation on deferred income tax assets and liabilities, primarily due to the impact of the reduction of the corporate income tax rate, to be complete.

However, the IRS continues to issue regulations that provide further interpretation and guidance on the law and each state's adoption of the provisions contained in the Tax Reform Legislation remains uncertain. The ultimate impact of this matter cannot be determined at this time. See Note 2 to the financial statements under "Georgia Power – Rate Plans" for additional information regarding the Georgia Power Tax Reform Settlement Agreement. The regulatory treatment of certain impacts of the Tax Reform Legislation remains subject to the discretion of the Georgia PSC in the Georgia Power 2019 Base Rate Case and the FERC. Also, see FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 10 to the financial statements under "Current and Deferred Income Taxes" for additional information.

II-111

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

Bonus Depreciation

Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the PATH Act. The PATH Act allowed for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. Based on provisional estimates, bonus depreciation is expected to result in positive cash flows of approximately $80 million for the 2018 tax year and approximately $30 million for the 2019 tax year. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

Georgia Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Georgia Power is subject to certain claims and legal actions arising in the ordinary course of business. Georgia Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of other natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings 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 would have a material effect on Georgia Power's financial statements. See Notes 2 and 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Georgia Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Notes 1, 5, and 6 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power's results of operations and related disclosures. 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.

Utility Regulation

Georgia Power is subject to retail regulation by the Georgia PSC and wholesale regulation by the FERC. These regulatory agencies set the rates Georgia Power is permitted to charge customers based on allowable costs. As a result, Georgia Power applies 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 has a further effect on Georgia Power's 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 Georgia Power; 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 Georgia Power's results of operations and financial condition than they would on a non-regulated company.

As reflected in Note 2 to the financial statements under "Georgia Power – Regulatory Assets and Liabilities," 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 Georgia Power's financial statements.

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

II-112

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

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) 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; (iii) Georgia Power would have the burden of proof to show that any capital costs above $5.68 billion were prudent; (iv) 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 (v) prudence decisions would be made subsequent to achieving fuel load for Unit 4.

Georgia Power's revised cost estimate reflects an expected in-service date of November 2021 for Unit 3 and November 2022 for Unit 4.

II-113

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, 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 Georgia Power's results of operations and cash flows, Georgia Power considers these items to be critical accounting estimates. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information.

Asset Retirement Obligations

The liability for AROs primarily relates to the decommissioning of Georgia Power's nuclear facilities, which include Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2, and facilities that are subject to the CCR Rule and the related state rule, principally ash ponds. In addition, Georgia Power has AROs related to various landfill sites, underground storage tanks, and asbestos removal.

Georgia Power also has identified retirement obligations related to certain transmission and distribution facilities, including the disposal of polychlorinated biphenyls in certain transformers; leasehold improvements; equipment on customer property; and property associated with Georgia Power's rail lines and natural gas pipelines. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the 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 retirement obligation.

Georgia Power previously recorded AROs as a result of state requirements in Georgia which closely align with the requirements of the CCR Rule discussed above. 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 rule. In December 2018, Georgia Power recorded an increase of approximately $3.1 billion to its AROs related to the disposal of CCR as a result of a strategic assessment which indicated additional closure costs will be required to close the ash ponds, primarily due to changes in closure strategies, the estimated amount of ash to be excavated, and additional water management requirements necessary to support closure strategies. Also in December 2018, Georgia Power recorded an increase of approximately $130 million to its AROs as a result of updated decommissioning cost site studies for Plant Hatch and Plant Vogtle Units 1 and 2. Georgia Power expects to periodically update its ARO cost estimates. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 6 to the financial statements for additional information.

Given the significant judgment involved in estimating AROs, Georgia Power considers the liabilities for AROs to be critical accounting estimates.

Pension and Other Postretirement Benefits

Georgia Power's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return 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 Georgia Power believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefit costs and obligations.

Key elements in determining Georgia Power's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on Southern Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice.

II-114

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

Southern Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to Southern Company's target asset allocation. For purposes of determining Georgia Power's liability 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.

A 25 basis point change in any significant assumption (discount rate, salary increases, or long-term rate of return on plan assets) would result in a $10 million or less change in total annual benefit expense, a $128 million or less change in the projected obligation for the pension plan, and an $18 million or less change in the projected obligation for other postretirement benefit plans.

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

Contingent Obligations

Georgia Power is subject to a number of federal and state laws and regulations, as well as other factors and conditions that subject it 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. Georgia Power periodically evaluates its exposure to such risks and records 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 Georgia Power's results of operations, cash flows, or financial condition.

Recently Issued Accounting Standards

See Note 1 to the financial statements under "Recently Adopted Accounting Standards" for additional information.

In 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Georgia Power adopted the new standard effective January 1, 2019.

Georgia Power elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby the requirements of ASU 2016-02 are applied on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Georgia Power elected the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Georgia Power 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. Georgia Power also made accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and combined lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.

Georgia Power completed the implementation of a new application to track and account for its leases and updated its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Georgia Power completed its lease inventory and determined its most significant leases involve PPAs and real estate. In the first quarter 2019, the adoption of ASU 2016-02 resulted in recording lease liabilities and right-of-use assets on Georgia Power's balance sheet each totaling approximately $1.5 billion, with no impact on Georgia Power's statement of income.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Georgia Power's financial condition remained stable at December 31, 2018. Georgia Power's cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. Capital expenditures and other investing activities include investments to build new generation facilities, including Plant Vogtle Units 3 and 4, to maintain existing generation facilities, to comply with environmental regulations including adding environmental modifications to existing generating units and closures of ash ponds, to expand and improve transmission and distribution facilities, and for restoration following major storms. Operating cash flows provide a substantial portion of Georgia Power's cash needs. For the three-year period from 2019 through 2021, Georgia Power's projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. Georgia Power plans to finance future cash needs in excess of its operating cash flows primarily through external securities issuances, equity contributions from Southern Company, borrowings from financial

II-115

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

institutions, and borrowings through the FFB. Georgia Power plans to use commercial paper to manage seasonal variations in operating cash flows and for other working capital needs. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.

Georgia Power's investments in the qualified pension plan and nuclear decommissioning trust funds decreased in value as of December 31, 2018 as compared to December 31, 2017. No contributions to the qualified pension plan were made for the year ended December 31, 2018 and no mandatory contributions to the qualified pension plan are anticipated during 2019. Georgia Power also funded approximately $5 million to its nuclear decommissioning trust funds in 2018. See "Contractual Obligations" herein and Notes 6 and 11 to the financial statements under "Nuclear Decommissioning" and "Pension Plans," respectively, for additional information.

Net cash provided from operating activities totaled $2.8 billion in 2018, an increase of $857 million from 2017, primarily due to the timing of vendor and property tax payments and income tax refunds, a decrease in current income taxes related to the Tax Reform Legislation, increased fuel cost recovery, and the timing of fossil fuel stock purchases, partially offset by payments of customer refunds primarily related to the Guarantee Settlement Agreement and the Georgia Power Tax Reform Settlement Agreement. Net cash provided from operating activities totaled $1.9 billion in 2017, a decrease of $513 million from 2016, primarily due to the timing of vendor payments and increases in under-recovered fuel costs and prepaid federal income taxes, partially offset by a decrease in voluntary contributions to the qualified pension plan. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Note 10 to the financial statements for additional information regarding federal income taxes.

Net cash used for investing activities totaled $3.1 billion, $0.9 billion, and $2.3 billion in 2018, 2017, and 2016, respectively, due to gross property additions primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities, including a total of $2.7 billion related to the construction of Plant Vogtle Units 3 and 4, partially offset in 2017 by $1.7 billion in payments received under the Guarantee Settlement Agreement. The majority of funds needed for gross property additions for the last several years has been provided from operating activities, capital contributions from Southern Company, and the issuance of debt. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" herein for additional information on the Guarantee Settlement Agreement and construction of Plant Vogtle Units 3 and 4.

Net cash used for financing activities totaled $400 million, $151 million, and $142 million for 2018, 2017, and 2016, respectively. The increase in cash used in 2018 compared to 2017 was primarily due to lower issuances of senior notes and short-term bank debt and higher redemptions and repurchases of senior notes, partially offset by higher capital contributions from Southern Company and an increase in notes payable. The increase in cash used in 2017 compared to 2016 was primarily due to a decrease in notes payable, a decrease in borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, and the redemption of all outstanding shares of Georgia Power's preferred and preference stock, partially offset by higher issuances of senior notes and junior subordinated notes and a decrease in maturities of senior notes. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes in 2018 included an increase in property, plant, and equipment of $2.6 billion primarily related to the $3.2 billion increase in AROs, as well as the installation of equipment to comply with environmental standards and the construction of generation, transmission, and distribution facilities, and net of the $1.1 billion charge related to the construction of Plant Vogtle Units 3 and 4; an increase of $2.0 billion in other regulatory assets, deferred primarily related to AROs; and a decrease of $1.9 billion in long-term debt (including securities due within one year) primarily due to the redemption, repurchase, and maturity of senior notes and the purchase of pollution control revenue bonds. Total common stockholder's equity increased $2.4 billion primarily due to a $3.0 billion increase in paid-in capital resulting from capital contributions received from Southern Company, partially offset by a $0.6 billion decrease in retained earnings primarily due to the charge related to Plant Vogtle Units 3 and 4. See Note 6 to the financial statements for additional information on AROs and Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

Georgia Power's ratio of common equity to total capitalization plus short-term debt was 58.2% at December 31, 2018 and 49.7% at December 31, 2017. See Note 8 to the financial statements for additional information.

Sources of Capital

Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, external security issuances, borrowings from financial institutions, equity contributions from Southern Company, and borrowings from the FFB. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approvals, prevailing market conditions, and other factors.

II-116

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

In 2014, Georgia Power entered into the Loan Guarantee Agreement with the DOE, 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. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. At December 31, 2018, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. In July 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.

The issuance of long-term securities by Georgia Power is subject to the approval of the Georgia PSC. In addition, the issuance of short-term debt securities by Georgia Power is subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, Georgia Power files registration statements with the SEC under the Securities Act of 1933, as amended. The amounts of securities authorized by the Georgia PSC and the FERC are continuously monitored and appropriate filings are made to ensure flexibility in the capital markets.

Georgia Power obtains 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 Georgia Power are not commingled with funds of any other company in the Southern Company system.

At December 31, 2018, Georgia Power's current liabilities exceeded current assets by $1.4 billion primarily as a result of $0.6 billion of long-term debt that is due within one year and $0.3 billion of notes payable. Georgia Power's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.

At December 31, 2018, Georgia Power had approximately $4 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks was $1.75 billion at December 31, 2018, of which $1.74 billion was unused. This credit arrangement expires in 2022.

This bank credit arrangement contains a covenant that limits debt levels and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross-acceleration provision to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2018, Georgia Power was in compliance with this covenant. This bank credit arrangement does not contain a material adverse change clause at the time of borrowing.

Subject to applicable market conditions, Georgia Power expects to renew or replace this credit arrangement as needed prior to expiration. In connection therewith, Georgia Power may extend the maturity date and/or increase or decrease the lending commitments thereunder.

See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information.

A portion of the $1.74 billion unused credit with banks is allocated to provide liquidity support to Georgia Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support at December 31, 2018 was $659 million as compared to $550 million at December 31, 2017. In addition, at December 31, 2018, Georgia Power had obligations related to $345 million of pollution control revenue bonds outstanding that are required to be remarketed within the next 12 months. Subsequent to December 31, 2018, Georgia Power redeemed approximately $108 million of these obligations.

Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each

II-117

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Short-term borrowings are included in notes payable in the balance sheets.

Details of short-term borrowings were as follows:



	Short-term Debt at the End of the Period				Short-term Debt During the Period ^(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
December 31, 2018:
Commercial paper	$	294	3.1	%	$	127	2.5	%	$	710
Short-term bank debt	—		—	%	12		2.3	%	150
Total	$	294	3.1	%	$	139	2.5	%
December 31, 2017:
Commercial paper	$	—	—	%	$	135	1.3	%	$	760
Short-term bank debt	150		2.2	%	292		2.0	%	800
Total	$	150	2.2	%	$	427	1.8	%
December 31, 2016:
Commercial paper	$	392	1.1	%	$	87	0.8	%	$	443


(*)	Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2018, 2017, and 2016.

Georgia Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank notes, and operating cash flows.

Financing Activities

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Georgia Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

Senior Notes

In April 2018, Georgia Power redeemed all $250 million aggregate principal amount of its Series 2008B 5.40% Senior Notes due June 1, 2018.

In December 2018, Georgia Power repaid at maturity $500 million aggregate principal amount of its Series 2015A 1.95% Senior Notes.

Pollution Control Revenue Bonds

During 2018, Georgia Power purchased and held the following pollution control revenue bonds, which may be reoffered to the public at a later date:


•	approximately $105 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013


•	$173 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009


•	$55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1994

II-118

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report


•	$65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008


•	approximately $72 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2013

In December 2018, the Development Authority of Burke County (Georgia) issued approximately $108 million aggregate principal amount of Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2018 due November 1, 2052 for the benefit of Georgia Power. The proceeds were used to redeem, in January 2019, approximately $13 million, $20 million, and $75 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1992, Eighth Series 1994, and Second Series 1995, respectively.

Other

In January 2018, Georgia Power repaid its outstanding $150 million and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively.

Credit Rating Risk

At December 31, 2018, Georgia Power 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 to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and construction of new generation at Plant Vogtle Units 3 and 4.

The maximum potential collateral requirements under these contracts at December 31, 2018 were as follows:



Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	92
Below BBB- and/or Baa3	$	1,106

Included in these amounts are certain agreements that could require collateral in the event that either Georgia Power or Alabama Power (an affiliate of 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 Georgia Power to access capital markets and would be likely to impact the cost at which it does so.

On February 28, 2018, Fitch downgraded the senior unsecured long-term debt rating of Georgia Power to A from A+ with a negative outlook. On August 9, 2018, Fitch downgraded the senior unsecured long-term debt rating of Georgia Power to A- from A. On September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and certain of its subsidiaries (including Georgia Power).

On August 8, 2018, Moody's downgraded the senior unsecured debt rating of Georgia Power to Baa1 from A3. On September 28, 2018, Moody's revised its rating outlook for Georgia Power from negative to stable.

As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries (including Georgia Power) may be negatively impacted. The Georgia Power Tax Reform Settlement Agreement approved by the Georgia PSC on April 3, 2018 is expected to help mitigate these potential adverse impacts to certain credit metrics by allowing a higher retail equity ratio until the conclusion of the Georgia Power 2019 Base Rate Case. See Note 2 to the financial statements under "Georgia Power – Rate Plans" for additional information.

Market Price Risk

Due to cost-based rate regulation and other various cost recovery mechanisms, Georgia Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, Georgia Power nets the exposures, where possible, to take advantage of natural offsets and enters into various

II-119

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

derivative transactions for the remaining exposures pursuant to Georgia Power's policies in areas such as counterparty exposure and risk management practices. Georgia Power'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.

To mitigate future exposure to changes in interest rates, Georgia Power may enter into derivatives designated as hedges. The weighted average interest rate on $0.9 billion of long-term variable interest rate exposure at December 31, 2018 was 2.57%. If Georgia Power sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would affect annualized interest expense by approximately $9 million at December 31, 2018. See Note 1 to the financial statements under "Financial Instruments" and Note 14 to the financial statements for additional information.

To mitigate residual risks relative to movements in electricity prices, Georgia Power enters 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. Georgia Power continues to manage a fuel-hedging program implemented per the guidelines of the Georgia PSC. Georgia Power had no material change in market risk exposure for the year ended December 31, 2018 when compared to the December 31, 2017 reporting period.



	2018 Changes			2017 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(13	)	$	36
Contracts realized or settled:
Swaps realized or settled	1			(13		)
Options realized or settled	—			(1		)
Current period changes^(*):
Swaps	(3		)	(28		)
Options	1			(7		)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(14	)	$	(13	)


(*)	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 at December 31, 2018 and 2017 were as follows:



	2018	2017
	mmBtu Volume
	(in millions)
Commodity – Natural gas swaps	141	146
Commodity – Natural gas options	12	17
Total hedge volume	153	163

The weighted average swap contract cost above market prices was approximately $0.10 per mmBtu and $0.08 per mmBtu at December 31, 2018 and 2017, respectively. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. All natural gas hedge gains and losses are recovered through Georgia Power's fuel cost recovery mechanism.

At December 31, 2018 and 2017, substantially all of Georgia Power's energy-related derivative contracts were designated as regulatory hedges and were related to Georgia Power's fuel-hedging program, which had a time horizon up to 48 months. Hedging gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the fuel cost recovery mechanism. 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 and were not material for any year presented.

II-120

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

Georgia Power uses 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. See Note 13 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts, which are all Level 2 of the fair value hierarchy, at December 31, 2018 were as follows:



	Fair Value Measurements December 31, 2018
	Total			Maturity
	Fair Value			Year 1			Years 2&3
	(in millions)
Level 1	$	—		$	—		$	—
Level 2	(14		)	(6		)	(8		)
Level 3	—			—			—
Fair value of contracts outstanding at end of period	$	(14	)	$	(6	)	$	(8	)

Georgia Power is exposed to market price risk in the event of nonperformance by counterparties to the energy-related and interest rate derivative contracts. Georgia Power only enters 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, Georgia Power does 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.

Capital Requirements and Contractual Obligations

The construction program of Georgia Power is currently estimated to total $3.7 billion for 2019, $3.5 billion for 2020, $3.4 billion for 2021, $3.4 billion for 2022, and $2.9 billion for 2023. These amounts include expenditures of approximately $1.5 billion, $1.2 billion, $1.0 billion, and $0.5 billion for the construction of Plant Vogtle Units 3 and 4 in 2019, 2020, 2021, and 2022, respectively. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $0.2 billion, $0.1 billion, $0.1 billion, $0.2 billion, and $0.1 billion for 2019, 2020, 2021, 2022, and 2023, respectively. These estimated expenditures do not include any potential compliance costs associated with pending regulation of CO₂ emissions from fossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and " – Global Climate Issues" herein for additional information.

Georgia Power also anticipates costs associated with closure and monitoring of ash ponds and landfills in accordance with the CCR Rule, which are reflected in Georgia Power's ARO liabilities. In December 2018, Georgia Power recorded an increase of approximately $3.1 billion to its AROs related to the CCR Rule and the related state rule. These costs, which are expected to change and could change materially as underlying assumptions are refined and the cost and the method and timing of compliance activities continue to be evaluated, are currently estimated to be $0.2 billion for 2019, $0.3 billion for 2020, $0.4 billion for 2021, $0.7 billion for 2022, and $0.6 billion for 2023. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" and Note 6 to the financial statements for additional information.

The construction program is 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 generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only recently began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. The ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs, availability, and productivity; challenges with management of contractors, subcontractors, or vendors; adverse weather conditions; shortages, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier

II-121

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

delay; non-performance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance matters, including the timely resolution of ITAAC and the related approvals by the NRC; challenges with start-up activities, including major equipment failure and system integration; and/or operational performance. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for information regarding additional factors that may impact construction expenditures.

As a result of requirements by the NRC, Georgia Power has established external trust funds for nuclear decommissioning costs. For additional information, see Note 6 to the financial statements under "Nuclear Decommissioning."

In addition, as discussed in Note 11 to the financial statements, Georgia Power provides postretirement benefits to substantially all employees and funds trusts to the extent required by the Georgia PSC and the FERC.

Funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, leases, other purchase commitments, ARO settlements, and trusts are detailed in the contractual obligations table that follows. See Notes 1, 6, 8, 9, 11, and 14 to the financial statements for additional information.

II-122

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Georgia Power Company 2018 Annual Report

Contractual Obligations

Contractual obligations at December 31, 2018 were as follows:



	2019		2020- 2021		2022- 2023		After 2023		Total
	(in millions)
Long-term debt^(a) —
Principal	$	608	$	1,363	$	641	$	7,343	$	9,955
Interest	339		615		562		4,660		6,176
Financial derivative obligations^(b)	8		12		—		—		20
Operating leases^(c)	23		27		11		13		74
Capital leases^(c)	9		7		—		—		16
Purchase commitments —
Capital^(d)	3,512		6,305		5,876				15,693
Fuel^(e)	1,117		1,400		764		4,586		7,867
Purchased power^(f)	270		536		549		2,054		3,409
Other^(g)	42		179		109		267		597
ARO settlements^(h)	202		674		1,283				2,159
Trusts —
Nuclear decommissioning⁽ⁱ⁾	5		11		11		88		115
Pension and other postretirement benefit plans^(j)	43		79						122
Total	$	6,178	$	11,208	$	9,806	$	19,011	$	46,203

(a)

All amounts are reflected based on final maturity dates except for amounts related to FFB borrowings and certain pollution control revenue bonds. As it relates to the FFB borrowings, the final maturity date is February 20, 2044; however, principal amortization is reflected beginning in 2020. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" for additional information. Georgia Power plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates at December 31, 2018, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. Long-term debt excludes capital lease amounts (shown separately).


(b)	See Notes 1 and 14 to the financial statements.


(c)	Excludes PPAs that are accounted for as leases and included in "Purchased power." See Note 8 to the financial statements under "Long-term Debt – Capital Leases – Georgia Power" and Note 9 to the financial statements under "Operating Leases" for additional information.

(d)

Georgia Power provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. These amounts exclude contractual purchase commitments for nuclear fuel, capital expenditures covered under LTSAs, and estimated capital expenditures for AROs, which are reflected in "Fuel," "Other," and "ARO settlements," respectively. At December 31, 2018, significant purchase commitments were outstanding in connection with the construction program. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and "Retail Regulatory Matters – Nuclear Construction" herein for additional information.

(e)


(f)	Estimated minimum long-term obligations for various PPA purchases from gas-fired, biomass, and wind-powered facilities and capacity payments related to Plant Vogtle Units 1 and 2. See Note 9 to the financial statements under "Fuel and Power Purchase Agreements" for additional information.


(g)	Includes LTSAs and contracts for the procurement of limestone. LTSAs include price escalation based on inflation indices.

(h)

Represents estimated costs for a five-year period associated with closing and monitoring ash ponds and landfills in accordance with the CCR Rule and the related state rule, which are reflected in Georgia Power's AROs. Material expenditures in future years for ARO settlements also will be required for ash ponds, nuclear decommissioning, and other liabilities and are reflected in Georgia Power's AROs. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 6 to the financial statements for additional information.


(i)	Projections of nuclear decommissioning trust fund contributions for Plant Hatch and Plant Vogtle Units 1 and 2 are based on the 2013 ARP. See Note 6 to the financial statements under "Nuclear Decommissioning" for additional information.

(j)

Georgia Power forecasts contributions to the pension and other postretirement benefit plans over a three-year period. Georgia Power anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from Georgia Power's corporate assets. See Note 11 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from Georgia Power's corporate assets.

II-123

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Mississippi Power Company 2018 Annual Report

OVERVIEW

Business Activities

Mississippi Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located within the State of Mississippi and to wholesale customers in the Southeast.

Many factors affect the opportunities, challenges, and risks of Mississippi Power's business of providing electric service. These factors include Mississippi Power's ability to maintain and grow energy sales and to operate in a constructive regulatory environment that provides timely recovery of prudently-incurred costs. These costs include those related to reliability, fuel, and stringent environmental standards, as well as ongoing capital and operations and maintenance expenditures and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future. Mississippi Power is scheduled to file a base rate case in the fourth quarter 2019 (Mississippi Power 2019 Base Rate Case).

As a result of the Mississippi PSC's stated intent to issue an order establishing a new docket for a global settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant (Kemper Settlement Docket), on June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility. At the time of project suspension, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap. In the aggregate, Mississippi Power had incurred charges of $3.07 billion ($1.89 billion after tax) for changes in the cost estimate above the cost cap through May 31, 2017.

Given the Mississippi PSC's stated intent regarding no additional rate increases for the Kemper County energy facility and the subsequent suspension of construction, cost recovery of the gasification portions was no longer probable. Therefore, Mississippi Power recorded a charge to income in June 2017 of $2.8 billion ($2.0 billion after tax) for the estimated costs associated with the gasification portions of the plant and lignite mine. During the third and fourth quarters 2017, Mississippi Power recorded further charges to income totaling $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as a charge associated with the Kemper Settlement Agreement discussed below.

On February 6, 2018, the Mississippi PSC voted to approve a settlement agreement related to cost recovery for the Kemper County energy facility among Mississippi Power, the MPUS, and certain intervenors (Kemper Settlement Agreement), which resolved all cost recovery issues, modified the CPCN to limit the Kemper County energy facility to natural gas combined cycle operation, and provided for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which included the impact of the Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6% excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of Mississippi Power's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax). Under the Kemper Settlement Agreement, retail customer rates reflect a reduction of approximately $26.8 million annually, effective with the first billing cycle of April 2018, and include no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2018 or at any future date.

In 2018, Mississippi Power recorded pre-tax charges to income of $37 million ($27 million after tax), primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. In addition, Mississippi Power recorded a credit to earnings of $95 million in the fourth quarter 2018 primarily resulting from the reduction of a valuation allowance for a state income tax net operating loss (NOL) carryforward associated with the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding salvage, net of dismantlement costs), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated to total $11 million in 2019 and $2 million to $4 million annually in 2020 through 2023. Mississippi Power is currently evaluating its options regarding the final disposition of the CO₂ pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. If Mississippi Power ultimately decides to remove the CO₂ pipeline, the cost of removal would have a material impact on Mississippi Power's financial statements. The ultimate outcome of these matters cannot be determined at this time.

II-124

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

See Note 2 to the financial statements under "Kemper County Energy Facility" and Note 10 to the financial statements for additional information.

On August 7, 2018 the Mississippi PSC approved settlement agreements between Mississippi Power and the MPUS with respect to the 2018 PEP filing and all unresolved PEP filings for prior years (PEP Settlement Agreement) and the 2018 ECO Plan filing (ECO Settlement Agreement). Rates under the PEP Settlement Agreement and the ECO Settlement Agreement resulted in annual revenue increases of approximately $21.6 million and $17 million, respectively, effective with the first billing cycle of September 2018 and are expected to continue through the conclusion of the Mississippi Power 2019 Base Rate Case.

In August 2018, the Mississippi PSC began an operations review of Mississippi Power, for which the final report is expected prior to the conclusion of the Mississippi Power 2019 Base Rate Case. Mississippi Power expects that the review will include, but not be limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time.

See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein and Note 2 to the financial statements under "Mississippi Power" for additional information.

Mississippi Power continues to focus on several key performance indicators. In recognition that Mississippi Power's long-term financial success is dependent upon how well it satisfies its customers' needs, Mississippi Power's retail base rate mechanism, 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%). Mississippi Power also focuses on broader measures of customer satisfaction, plant availability, system reliability, and net income.

Mississippi Power's financial success is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. Management uses customer satisfaction surveys to evaluate Mississippi Power's results and generally targets top-quartile performance.

See RESULTS OF OPERATIONS herein for information on Mississippi Power's financial performance.

Earnings

Mississippi Power's net income after dividends on preferred stock was $235 million in 2018 compared to a $2.59 billion net loss in 2017 and a $50 million net loss in 2016. The changes were primarily the result of pre-tax charges associated with the Kemper IGCC of $37 million, $3.36 billion, and $428 million, in 2018, 2017, and 2016, respectively. The increase in net income in 2018 was partially offset by lower tax benefits and a decrease in AFUDC. See Note 2 to the financial statements under "Kemper County Energy Facility" for additional information.

II-125

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

RESULTS OF OPERATIONS

A condensed statement of operations follows:



	Amount			Increase (Decrease) from Prior Year
	2018			2018			2017
	(in millions)
Operating revenues	$	1,265		$	78		$	24
Fuel	405			10			52
Purchased power	41			16			(9		)
Other operations and maintenance	313			22			(26		)
Depreciation and amortization	169			8			29
Taxes other than income taxes	107			3			(5		)
Estimated loss on Kemper IGCC	37			(3,325		)	2,934
Total operating expenses	1,072			(3,266		)	2,975
Operating income	193			3,344			(2,951		)
Allowance for equity funds used during construction	—			(72		)	(52		)
Interest expense, net of amounts capitalized	76			34			(32		)
Other income (expense), net	17			16			3
Income taxes (benefit)	(102		)	430			(428		)
Net income	236			2,824			(2,540		)
Dividends on preferred stock	1			(1		)	—
Net income after dividends on preferred stock	$	235		$	2,825		$	(2,540	)

Operating Revenues

Operating revenues for 2018 were $1.3 billion, reflecting a $78 million increase from 2017. Details of operating revenues were as follows:



	2018			2017
	(in millions)
Retail — prior year	$	854		$	859
Estimated change resulting from —
Rates and pricing	24			(7		)
Sales growth	4			4
Weather	12			(15		)
Fuel and other cost recovery	(5		)	13
Retail — current year	889			854
Wholesale revenues —
Non-affiliates	263			259
Affiliates	91			56
Total wholesale revenues	354			315
Other operating revenues	22			18
Total operating revenues	$	1,265		$	1,187
Percent change	6.6		%	2.1		%

Total retail revenues for 2018 increased $35 million, or 4.1%, compared to 2017 primarily due to the PEP and ECO Plan rate changes that became effective for the first billing cycle of September 2018, each resulting in retail revenue increases of $12 million. In addition, as a result of the PEP Settlement Agreement, Mississippi Power recognized revenues of $5 million previously

II-126

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

reserved in connection with the 2012 PEP lookback filing and deferred $17 million of revenue in 2017 following the complete amortization of certain regulatory assets related to the Kemper County energy facility. These increases were offset by a decrease of $16 million annually for base rates related to the Kemper County energy facility that became effective for the first billing cycle of April 2018 and the recognition in 2018 of regulatory liabilities of $5 million and $2 million, respectively, related to the equity ratio provisions of the PEP and ECO Settlement Agreements. Additionally, there was a $12 million increase as a result of colder weather in the first quarter and warmer weather in the second and third quarters in 2018 as compared to the corresponding periods in 2017 and a $5 million decrease in fuel and other cost recovery.

Total retail revenues for 2017 decreased $5 million, or 0.6%, compared to 2016 primarily due to a $15 million decrease as a result of milder weather in 2017 as compared to 2016 and the deferral of $17 million of revenue following the complete amortization of certain regulatory assets related to the Kemper County energy facility in July 2017. These decreases were partially offset by a $10 million net increase related to ECO Plan rate changes in the third quarter 2016 and the second quarter 2017 and an increase of $13 million in fuel cost recovery.

See Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan," " – Performance Evaluation Plan," and " – Kemper County Energy Facility – Rate Recovery" for additional information. See "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes related to sales and weather.

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

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



	2018		2017		2016
	(in millions)
Capacity and other	$	6	$	15	$	16
Energy	257		244		245
Total non-affiliated	$	263	$	259	$	261

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. In addition, Mississippi Power provides service under long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 17.3% of Mississippi Power's total operating revenues in 2018 and are generally subject to 10-year rolling cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers.

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

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

Wholesale revenues from sales to affiliates increased $35 million, or 62.5%, in 2018 compared to 2017 and increased $30 million, or 115.4%, in 2017 compared to 2016. The increases in 2018 and 2017 were primarily due to $19 million and $9 million, respectively, associated with higher natural gas prices and $16 million and $21 million, respectively, associated with increases in KWH sales due to the dispatch of Mississippi Power's lower cost generation resources to serve Southern Company system territorial load.

II-127

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2018 and the percent change from the prior year were as follows:



	Total KWHs	Total KWH Percent Change				Weather-Adjusted Percent Change
	2018	2018		2017		2018		2017
	(in millions)
Residential	2,113	8.7	%	(5.2	)%	1.4	%	1.4	%
Commercial	2,797	1.2		(2.7	)	(0.7	)	(0.1	)
Industrial	4,924	1.7		(1.3	)	1.7		(1.3	)
Other	37	(4.1	)	(1.6	)	(4.1	)	(1.6	)
Total retail	9,871	2.9		(2.5	)	0.9	%	(0.4	)%
Wholesale
Non-affiliated	3,980	8.4		(6.3	)
Affiliated	2,584	27.7		82.7
Total wholesale	6,564	15.3		14.0
Total energy sales	16,435	7.5	%	2.8	%

Changes in retail energy sales are generally the result of changes in electricity usage by customers, changes in weather, and changes in the number of customers. Retail energy sales increased 2.9% in 2018 as compared to the prior year. This increase was primarily the result of colder weather in the first quarter and warmer weather in the second and third quarters 2018 as compared to the corresponding periods in 2017. Weather-adjusted residential KWH sales increased in 2018 primarily due to increased customer usage. Weather-adjusted commercial KWH sales decreased primarily due to decreased customer usage slightly offset by customer growth. The increase in industrial KWH energy sales was primarily due to Hurricane Nate, which negatively impacted several large industrial customers in 2017.

Retail energy sales decreased 2.5% in 2017 as compared to the prior year. This decrease was primarily the result of milder weather in 2017 as compared to 2016. Weather-adjusted residential KWH sales increased in 2017 primarily due to increased customer usage. Weather-adjusted commercial KWH sales decreased primarily due to decreased customer usage largely offset by customer growth. The decrease in industrial KWH energy sales was primarily due to Hurricane Nate, which negatively impacted several large industrial customers.

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

Fuel and Purchased Power Expenses

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

II-128

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

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



	2018	2017	2016
Total generation (in millions of KWHs)	15,966	15,319	14,514
Total purchased power (in millions of KWHs)^(*)	1,210	724	1,098
Sources of generation (percent) –
Gas	93	92	91
Coal	7	8	9
Cost of fuel, generated (in cents per net KWH) –
Gas	2.65	2.69	2.41
Coal	3.50	3.64	3.91
Average cost of fuel, generated (in cents per net KWH)	2.72	2.77	2.55
Average cost of purchased power (in cents per net KWH)^(*)	3.39	3.50	3.07


(*)	Adjusted to include the impacts of station service in 2018 and test period energy produced in 2017 and 2016 for the Kemper County energy facility, which was accounted for in accordance with FERC guidance.

Fuel and purchased power expenses were $446 million in 2018, an increase of $26 million, or 6.2%, as compared to the prior year. The increase was primarily due to a $35 million increase in KWHs generated and purchased, partially offset by a $9 million decrease in the average cost of generation and purchased power.

Fuel and purchased power expenses were $420 million in 2017, an increase of $43 million, or 11.4%, as compared to the prior year. The increase was primarily due to a $36 million increase in the average cost of generation and purchased power and a net increase of $7 million in KWHs generated from gas generation.

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

Fuel

Fuel expense increased $10 million, or 2.5%, in 2018 compared to 2017 primarily due to a 5.2% increase in KWHs generated from gas generation. Fuel expense increased $52 million, or 15.2%, in 2017 compared to 2016 primarily due to an 11.6% higher cost of natural gas.

Purchased Power

Purchased power expense increased $16 million, or 64.0%, in 2018 compared to 2017. The increase was primarily the result of a 67% increase in the volume of KWHs purchased. Purchased power expense decreased $9 million, or 26.5%, in 2017 compared to 2016. The decrease was primarily the result of a 34% decrease in the volume of KWHs purchased, offset by a 13.9% increase in the average cost per KWH purchased compared to 2016. The changes in the volume of KWHs purchased primarily reflect the impact of test period energy offsets in 2017.

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

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $22 million, or 7.6%, in 2018 compared to the prior year. The increase was primarily due to a $15 million increase related to an employee attrition plan, a $12 million increase in planned generation outage cost, and a $7 million increase related to overhead line maintenance and vegetation management. These increases were partially offset by the deferral of $4 million of compensation costs in accordance with the PEP Settlement Agreement. See Note 2 to the financial statements under "Mississippi Power – Performance Evaluation Plan" for additional information.

Other operations and maintenance expenses decreased $26 million, or 8.2%, in 2017 compared to the prior year. The decrease was primarily due to a $10 million decrease in transmission and distribution expenses related to overhead line maintenance, an $8 million decrease in contractor services related to facilities, corporate advertising, and employee compensation and benefits, and an

II-129

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

$8 million decrease related to the combined cycle and the associated common facilities portion of the Kemper County energy facility.

Depreciation and Amortization

Depreciation and amortization increased $8 million, or 5.0%, in 2018 compared to 2017 primarily due to $8 million of amortization related to the ECO Plan and $6 million of depreciation for additional plant in service. These increases were partially offset by a decrease of $4 million in amortization of regulatory assets associated with Mercury and Air Toxics Standards (MATS) rule compliance.

Depreciation and amortization increased $29 million, or 22.0%, in 2017 compared to 2016 primarily due to $13 million of amortization related to the ECO Plan, $7 million of depreciation for additional plant in service, and $6 million in additional amortization of regulatory assets associated with MATS rule compliance.

See Note 5 to the financial statements under "Depreciation and Amortization" and Note 2 to the financial statements under "FERC Matters" and "Mississippi Power – Environmental Compliance Overview Plan" for additional information.

Estimated Loss on Kemper IGCC

In 2018, 2017, and 2016, charges of $37 million, $3.36 billion, and $428 million, respectively, associated with the Kemper IGCC were recorded. The 2018 pre-tax charge of $37 million primarily resulted from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. In June 2017, Mississippi Power suspended the gasifier portion of the project and recorded a charge to earnings for the remaining $2.8 billion book value of the gasifier portion of the project. Prior to the suspension, Mississippi Power recorded losses for revisions of estimated costs expected to be incurred on construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions (Cost Cap Exceptions).

See Note 2 to the financial statements under "Kemper County Energy Facility" for additional information.

Allowance for Equity Funds Used During Construction

AFUDC equity decreased $72 million, or 100.0%, in 2018 as compared to 2017 and $52 million, or 41.9%, in 2017 as compared to 2016 as a result of suspending construction of the Kemper IGCC in June 2017. See Note 2 to the financial statements under "Kemper County Energy Facility" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $34 million, or 81.0%, in 2018 compared to 2017. The increase was primarily associated with a $33 million net reduction in interest recorded in 2017 following a settlement with the IRS related to research and experimental (R&E) deductions. The increase also reflects a $29 million reduction in interest capitalized as a result of suspending construction of the Kemper IGCC in June 2017, offset by decreases of $12 million in interest expense as a result of lower average outstanding debt, $8 million related to uncertain tax positions, and $7 million due to the completion of Kemper IGCC carrying cost amortization in 2017.

Interest expense, net of amounts capitalized decreased $32 million, or 43.2%, in 2017 compared to 2016. The decrease was primarily associated with a $33 million net reduction in interest following a settlement with the IRS related to R&E deductions. Also contributing to the decrease was the amortization of $6 million in interest deferrals in accordance with an order the Mississippi PSC issued in December 2015 (In-Service Asset Rate Order) and a $7 million decrease in interest related to outstanding debt as a result of lower balances and lower rates. These decreases were partially offset by a $20 million reduction in interest capitalized as a result of suspending construction of the Kemper IGCC.

See Note 10 to the financial statements under "Section 174 Research and Experimental Deduction" for additional information.

Other Income (Expense), Net

Other income (expense), net increased $16 million in 2018 compared to 2017. The increase primarily reflects the $24 million settlement of Mississippi Power's Deepwater Horizon claim in May 2018, partially offset by a $7 million increase in charitable donations. See Note 3 to the financial statements under "General Litigation Matters – Mississippi Power" for additional information. Other income (expense), net increased $3 million in 2017 compared to 2016.

II-130

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

Income Taxes (Benefit)

Income tax benefits decreased $430 million, or 80.8%, in 2018 compared to 2017 primarily due to a $1.07 billion increase in income tax expense from higher pre-tax earnings primarily due to lower charges related to the Kemper County energy facility, net of the non-deductible AFUDC equity portion. This increase in income tax expense was partially offset by a $434 million decrease in income tax expense due to the impacts of the Tax Reform Legislation, including $407 million primarily associated with the revaluation of 2017 deferred tax assets related to the Kemper IGCC recorded in 2017 and $23 million associated with the lower federal income tax rate applicable in 2018, as well as $194 million related to the reduction in 2018 of a valuation allowance for a state income tax NOL carryforward recorded in 2017.

Income tax benefits increased $428 million, or 411.5%, in 2017 compared to 2016 primarily due to $809 million in tax benefits on the estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion and the related state valuation allowances, partially offset by $372 million resulting from Tax Reform Legislation. Tax Reform Legislation earnings impacts are primarily due to revaluing deferred tax assets related to the Kemper County energy facility.

See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" herein and Note 10 to the financial statements for additional information.

Effects of Inflation

Mississippi Power is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on Mississippi Power's results of operations has not been substantial in recent years.

FUTURE EARNINGS POTENTIAL

General

Mississippi Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located in southeast Mississippi and to wholesale customers in the Southeast. Prices for electricity provided by Mississippi Power to retail customers are set by the Mississippi PSC under cost-based regulatory principles. Retail rates and earnings are reviewed and may be adjusted periodically within certain limitations. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. See "FERC Matters" herein, 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.

The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of Mississippi Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Mississippi Power's business of providing electric service. These factors include Mississippi Power's ability to recover its prudently-incurred costs in a timely manner during a time of increasing costs and its ability to prevail against legal challenges associated with the Kemper County energy facility. Future earnings will be driven primarily by continued customer growth and the weak pace of growth in electricity use per customer, especially in residential and commercial markets. Earnings 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, both of which could contribute to a net reduction in customer usage. Earnings 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 other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Mississippi Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.

Mississippi Power's retail base rates are set under the PEP, a rate plan approved by the Mississippi PSC. Typically, two filings are made for each calendar year: the PEP projected filing, which is typically filed prior to the beginning of the year based on a projected revenue requirement, and the PEP lookback filing, which is filed after the end of the year and allows for review of the actual return compared to the allowed return range. Pursuant to the PEP Settlement Agreement, PEP proceedings are suspended until after the conclusion of the Mississippi Power 2019 Base Rate Case and Mississippi Power is not required to make any PEP filings for regulatory years 2018, 2019, and 2020. See "Retail Regulatory Matters" herein and Note 2 to the financial statements under "Mississippi Power – Performance Evaluation Plan" for more information.

On October 2, 2018, the Mississippi PSC approved the executed agreements between Mississippi Power and its largest retail customer, Chevron, for Mississippi Power to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi

II-131

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

through 2038. The new agreements are not expected to have a material impact on Mississippi Power's earnings; however, the co-generation assets located at the refinery are accounted for as a sales-type lease in accordance with the new lease accounting rules that became effective in 2019. These assets are also subject to a security interest granted to Chevron. See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information.

Mississippi Power provides service under long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 17.3% of Mississippi Power's total operating revenues in 2018 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.

Environmental Matters

Mississippi Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Mississippi Power maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future electric generating unit retirement and replacement decisions, 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 Mississippi Power's transmission and distribution systems. A major portion of these costs is expected to be recovered through retail and wholesale rates. The ultimate impact of environmental laws and regulations and the GHG goals discussed herein will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, and the outcome of pending and/or future legal challenges.

New or revised environmental laws and regulations could affect many areas of Mississippi Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be recovered in rates on a timely basis or through long-term wholesale agreements. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity, 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 for some may have the potential to ultimately affect their demand for electricity. See Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan" for additional information.

Through 2018, Mississippi Power has invested approximately $654 million in environmental capital retrofit projects to comply with environmental requirements, with annual totals of approximately $11 million, $9 million, and $17 million for 2018, 2017, and 2016, respectively. 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, Mississippi Power's current compliance strategy estimates capital expenditures of $73 million from 2019 through 2023, with annual totals of approximately $18 million, $20 million, $17 million, $5 million, and $13 million for 2019, 2020, 2021, 2022, and 2023, respectively. These estimates do not include any potential compliance costs associated with pending regulation of CO₂ emissions from fossil fuel-fired electric generating units. See "Global Climate Issues" herein for additional information. Mississippi Power also anticipates expenditures associated with ash pond closure and ground water monitoring under the CCR Rule, which are reflected in Mississippi Power's ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 6 to the financial statements for additional information.

Environmental Laws and Regulations

Air Quality

II-132

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

In 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to address impacts of SO₂ and NO_X emissions from fossil fuel-fired electric generating plants. CSAPR establishes emissions trading programs and budgets for certain states and allocates emissions allowances for sources in those states. In 2016, the EPA published a final rule establishing more stringent ozone season NO_X emissions budgets in Alabama and Mississippi. The outcome of ongoing CSAPR litigation concerning the 2016 CSAPR rule, to which Mississippi Power is a party, could have an impact on the State of Mississippi's ozone season NO_X emissions budget. Increases in either future fossil fuel-fired generation or the availability or cost of CSAPR allowances could have a negative financial impact on results of operations for Mississippi Power.

The EPA finalized regional haze regulations in 2005 and 2017. These regulations require states, tribal governments, 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 must submit a revised state implementation plan (SIP) to the EPA demonstrating continued reasonable progress towards achieving visibility improvement goals. These plans could require reductions in certain pollutants, such as particulate matter, SO₂, and NO_X, which could result in increased compliance costs. The EPA issued a limited approval of the regional progress SIP for the State of Mississippi because Mississippi must revise the best available retrofit technology (BART) provisions of its SIP. Therefore, Plant Daniel continues to be evaluated under the regional haze BART provisions. Mississippi Power is required to submit Plant Daniel's BART analysis to the State of Mississippi by summer 2019. Requirements for further reduction of these pollutants at Plant Daniel could increase compliance costs.

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 (e.g. coal, natural gas, oil, and nuclear generating plants) and manufacturing facilities. The regulation requires plant-specific studies to determine applicable CWIS changes to protect organisms that either get caught on the intake screens (impingement) or are drawn into the cooling system (entrainment). Mississippi Power is conducting these studies and currently anticipates applicable CWIS changes may include fish-friendly CWIS screens with fish return systems and minor additions of monitoring equipment at certain plants. However, the ultimate 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 National Pollutant Discharge Elimination System (NPDES) permit based on site-specific factors, and the outcome of any legal challenges.

In 2015, the EPA finalized the steam electric effluent limitations guidelines (ELG) rule (2015 ELG Rule) that set national standards for wastewater discharges from new and existing steam electric generating units generating greater than 50 MWs. The 2015 ELG Rule prohibits effluent discharges of certain waste streams and imposes stringent limits on flue gas desulfurization (scrubber) wastewater discharges. The revised technology-based limits and the CCR Rule require extensive changes to existing ash and wastewater management systems or the installation and operation of new ash and wastewater management systems. Compliance with the 2015 ELG Rule is expected to require capital expenditures and increased operational costs primarily for Mississippi Power's coal-fired electric generation. State environmental agencies will incorporate specific compliance applicability dates in the NPDES permitting process for each ELG waste stream no later than December 31, 2023. The EPA is scheduled to issue a new rulemaking by December 2019 that could revise the limitations and applicability dates of two of the waste streams regulated in the 2015 ELG Rule. The impact of any changes to the 2015 ELG Rule will depend on the content of the new rule and the outcome of any legal challenges.

In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) jointly published a final rule that revised the regulatory definition of waters of the United States (WOTUS) for all CWA programs. The rule significantly expanded the scope of federal jurisdiction over waterbodies (such as rivers, streams, canals, and wastewater treatment ponds), which could impact new generation projects and permitting and reporting requirements associated with the installation, expansion, and maintenance of transmission and distribution projects. The EPA and the Corps are expected to publish a final rule in 2019 to replace the 2015 WOTUS definition. The impact of any changes to the 2015 WOTUS rule will depend on the content of this final rule and the outcome of any legal challenges.

Coal Combustion Residuals

In 2015, the EPA finalized non-hazardous solid waste regulations for the disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments (ash ponds) at active generating power plants. The EPA's CCR Rule requires landfills and ash ponds to be evaluated against a set of performance criteria and potentially closed if minimum criteria are not met. Closure of existing landfills and ash ponds could require installation of equipment and infrastructure to manage CCR in accordance with the CCR Rule. Based on cost estimates for closure and monitoring of landfills and ash ponds pursuant to the CCR Rule, Mississippi

II-133

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

Power recorded AROs for each CCR unit in 2015. As further analysis was performed and closure details were developed, Mississippi Power has continued to periodically update these cost estimates, as discussed further below.

On August 21, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision suggesting the EPA should regulate previously-excluded inactive ash ponds located at retired generation facilities and questioning both the ability of unlined ash ponds to continue operating no matter the performance criteria results and the classification of clay-lined landfills and ash ponds. These developments could impact the expected timing of Mississippi Power's landfill and ash pond closure activities, but the extent of any impact will depend on the outcome of ongoing litigation, anticipated EPA rulemaking action to establish further guidance, and the outcome of any legal challenges.

During 2018, Mississippi Power recorded increases of approximately $16 million to its AROs related to the CCR Rule. The increases include approximately $11 million based on information from feasibility studies performed on an ash pond at Plant Greene County, which is co-owned with Alabama Power, and approximately $5 million related to increases in post-closure care for Plant Watson's ash pond and landfill. The Alabama Power studies for Plant Greene County indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close the ash pond under the planned closure-in-place methodology. As the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material. Mississippi Power expects to periodically update its ARO cost estimates.

In 2016, the Mississippi PSC granted a CPCN to Mississippi Power authorizing certain projects associated with complying with the CCR Rule. Additionally in this order, the Mississippi PSC also authorized Mississippi Power to recover any costs associated with the CPCN, including future monitoring costs, through the ECO clause. Absent continued recovery of ARO costs through regulated rates, Mississippi Power's results of operations, cash flows, and financial condition could be materially impacted. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 6 to the financial statements for additional information regarding Mississippi Power's AROs.

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

Environmental Remediation

Mississippi Power 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, Mississippi Power may also incur substantial costs to clean up affected sites. Mississippi Power has authority from the Mississippi PSC to recover approved environmental compliance costs through established regulatory mechanisms. Mississippi Power recognizes a liability for environmental remediation costs only when it determines a loss is probable and reasonably estimable.

Global Climate Issues

On August 31, 2018, the EPA published a proposed rule known as the Affordable Clean Energy (ACE) Rule, which is intended to replace a regulation enacted in 2015 known as the Clean Power Plan (CPP), that would limit CO₂ emissions from existing fossil fuel-fired electric generating units. The CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule would require states to develop GHG unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of January 1, 2019, Mississippi Power has ownership interests in six fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to Mississippi Power is currently unknown and will depend on changes between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal challenges.

II-134

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

Power's 2017 GHG emissions were approximately 8 million metric tons of CO₂ equivalent. The preliminary estimate of Mississippi Power's 2018 GHG emissions on the same basis is approximately 8 million metric tons of CO₂ equivalent.

FERC Matters

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 2016, Mississippi Power reached a settlement agreement with its wholesale customers, which was subsequently approved by the FERC, for an increase in wholesale base revenues under the MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking under the In-Service Asset Rate Order. This regulatory treatment primarily included (i) recovery of the operational Kemper County energy facility assets providing service to customers and other related costs, (ii) amortization of the Kemper County energy facility-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper County energy facility-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper County energy facility CWIP from rate base with a corresponding increase in accrual of AFUDC, which totaled approximately $22 million through the suspension of Kemper IGCC start-up activities.

Mississippi Power expects to reach a subsequent settlement agreement with its wholesale customers and will make a filing with the FERC during the first quarter 2019. The settlement agreement is intended to be consistent with the Kemper Settlement Agreement, including the impact of the Tax Reform Legislation. The ultimate outcome of this matter cannot be determined at this time.

In September 2017, Mississippi Power and Cooperative Energy executed a Shared Service Agreement (SSA), as part of the MRA tariff, under which Mississippi Power and Cooperative Energy will share in providing electricity to all Cooperative Energy delivery points, in lieu of the current arrangement under which each delivery point is specifically assigned to either entity. The SSA accepted by the FERC in October 2017 became effective on January 1, 2018 and may be cancelled by Cooperative Energy with 10 years notice after December 31, 2020. The SSA provides Cooperative Energy the option to decrease its use of Mississippi Power's generation services under the MRA tariff, subject to annual and cumulative caps and a one-year notice requirement. In the event Cooperative Energy elects to reduce these services, the related reduction in Mississippi Power's revenues is not expected to be significant through 2020.

Fuel Cost Recovery

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. Effective with the first billing cycle for January 2018, fuel rates increased $11 million annually for wholesale MRA customers and $1 million annually for wholesale MB customers. Effective January 1, 2019, the wholesale MRA fuel rate decreased $16 million annually and the wholesale MB fuel rate decreased by an immaterial amount. At December 31, 2018, over recovered wholesale MRA fuel costs included in other regulatory liabilities, current on the balance sheet were approximately $6 million compared to an immaterial amount at December 31, 2017. Under recovered wholesale MB fuel costs included in the balance sheets were immaterial at December 31, 2018 and 2017.

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 cash flow.

II-135

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

Open Access Transmission Tariff

On May 10, 2018, AMEA and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies (including Mississippi Power) claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Mississippi Power's) open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requested that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Mississippi Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through December 31, 2018, the estimated maximum potential refund is not expected to be material to Mississippi Power's results of operations or cash flows. The ultimate outcome of this matter cannot be determined at this time.

Cooperative Energy Power Supply Agreement

In 2008, Mississippi Power entered into a 10-year power supply agreement (PSA) with Cooperative Energy for approximately 152 MWs, which became effective in 2011. Following certain plant retirements, the PSA capacity was reduced to 86 MWs. On February 5, 2018, Mississippi Power and Cooperative Energy executed an amendment to extend the PSA through March 31, 2021, effective April 1, 2018, which increased total capacity by 286 MWs.

Cooperative Energy also has a 10-year network integration transmission service agreement (NITSA) with SCS for transmission service to certain delivery points on Mississippi Power's transmission system that became effective in 2011. As a result of the PSA amendment, Cooperative Energy and SCS amended the terms of the NITSA, which the FERC approved, to provide for the purchase of incremental transmission capacity for service beginning April 1, 2018 through March 31, 2021.

Retail Regulatory Matters

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, energy efficiency programs, 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. See Note 2 to the financial statements under "Mississippi Power" for additional information.

Operations Review

Performance Evaluation Plan

In 2011, Mississippi Power submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. Later in 2011, the MPUS disputed certain items in the 2010 PEP lookback filing. In 2012, the Mississippi PSC issued an order canceling Mississippi Power's PEP lookback filing for 2011. In 2013, the MPUS contested Mississippi Power's PEP lookback filing for 2012, which indicated a refund due to customers of $5 million. In 2014 through 2018, Mississippi Power submitted its annual PEP lookback filings for the prior years, which for each of 2013, 2014, and 2017 indicated no surcharge or refund and for each of 2015 and 2016 indicated a $5 million surcharge. Additionally, in July 2016, in November 2016, and in November 2017, Mississippi Power submitted its annual projected PEP filings for 2016, 2017, and 2018, respectively, which for 2016 and 2017 indicated no change in rates and for 2018 indicated a rate increase of 4%, or $38 million in annual revenues. The Mississippi PSC suspended each of these filings to allow more time for review.

II-136

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

On February 7, 2018, Mississippi Power revised its annual projected PEP filing for 2018 to reflect the impacts of the Tax Reform Legislation. The revised filing requested an increase of $26 million in annual revenues, based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%. On July 27, 2018, Mississippi Power and the MPUS entered into the PEP Settlement Agreement, which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement became effective with the first billing cycle of September 2018. The PEP Settlement Agreement provides for an increase of approximately $21.6 million in annual base retail revenues, which excludes certain compensation costs contested by the MPUS, as well as approximately $2 million which was subsequently approved for recovery through the 2018 Energy Efficiency Cost Rider as discussed below. Under the PEP Settlement Agreement, Mississippi Power is deferring the contested compensation costs for 2018 and 2019 as a regulatory asset, which totaled $4 million as of December 31, 2018 and is included in other regulatory assets, deferred on the balance sheet. The Mississippi PSC is currently expected to rule on the appropriate treatment for such costs in connection with the Mississippi Power 2019 Base Rate Case. The ultimate outcome of this matter cannot be determined at this time.

Pursuant to the PEP Settlement Agreement, Mississippi Power's performance-adjusted allowed ROE is 9.31% and its allowed equity ratio is capped at 51%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power retained $44 million of excess accumulated deferred income taxes resulting from the Tax Reform Legislation until the conclusion of the Mississippi Power 2019 Base Rate Case. Further, Mississippi Power agreed to seek equity contributions sufficient to restore its equity ratio to 50% by December 31, 2018. Since Mississippi Power's actual average equity ratio for 2018 was more than 1% lower than the 50% target, Mississippi Power deferred the corresponding difference in its revenue requirement of approximately $4 million as a regulatory liability for resolution in the Mississippi Power 2019 Base Rate Case. Pursuant to the PEP Settlement Agreement, PEP proceedings are suspended until after the conclusion of the Mississippi Power 2019 Base Rate Case and Mississippi Power is not required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolved all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power recognized revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.

Energy Efficiency

In 2013, the Mississippi PSC approved an energy efficiency and conservation rule requiring electric and gas utilities in Mississippi serving more than 25,000 customers to implement energy efficiency programs and standards. Quick Start Plans, which include a portfolio of energy efficiency programs that are intended to provide benefits to a majority of customers, were extended by an order issued by the Mississippi PSC in July 2016, until the time the Mississippi PSC approves a comprehensive portfolio plan program. The ultimate outcome of this matter cannot be determined at this time.

On May 8, 2018, the Mississippi PSC issued an order approving Mississippi Power's revised annual projected Energy Efficiency Cost Rider 2018 compliance filing, which increased annual retail revenues by approximately $3 million effective with the first billing cycle for June 2018.

On February 5, 2019, the Mississippi PSC issued an order approving Mississippi Power's Energy Efficiency Cost Rider 2019 compliance filing, which included a slight decrease in annual retail revenues, effective with the first billing cycle in March 2019.

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. The Mississippi PSC approved $41 million and $17 million of costs that were reclassified to regulatory assets associated with the fuel conversion of Plant Watson and Plant Greene County, respectively, for amortization over five-year periods that began in July 2016 and July 2017, respectively. As a result, these decisions are not expected to have a material impact on Mississippi Power's financial statements.

In August 2016, the Mississippi PSC approved Mississippi Power's revised ECO Plan filing for 2016, which requested the maximum 2% annual increase in revenues, or approximately $18 million, primarily related to the Plant Daniel Units 1 and 2 scrubbers placed in service in 2015. The revised rates became effective with the first billing cycle for September 2016. Approximately $22 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2017 filing, along with related carrying costs.

In May 2017, the Mississippi PSC approved Mississippi Power's ECO Plan filing for 2017, which requested the maximum 2% annual increase in revenues, or approximately $18 million, primarily related to the carryforward from the prior year. The rates became effective with the first billing cycle for June 2017. Approximately $26 million, plus carrying costs, of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2018 filing.

II-137

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

On February 14, 2018, Mississippi Power submitted its ECO Plan filing for 2018, including the effects of the Tax Reform Legislation, which requested the maximum 2% annual increase in revenues, or approximately $17 million, primarily related to the carryforward from the prior year.

On August 3, 2018, Mississippi Power and the MPUS entered into the ECO Settlement Agreement, which provides for an increase of approximately $17 million in annual base retail revenues and was approved by the Mississippi PSC on August 7, 2018. Rates under the ECO Settlement Agreement became effective with the first billing cycle of September 2018 and will continue in effect until modified by the Mississippi PSC. These revenues are expected to be sufficient to recover the costs included in Mississippi Power's request for 2018, as well as the remaining deferred amounts, totaling $26 million at December 31, 2018, along with the related carrying costs. In accordance with the ECO Settlement Agreement, ECO Plan proceedings are suspended until after the conclusion of the Mississippi Power 2019 Base Rate Case and Mississippi Power is not required to make any ECO Plan filings for 2018, 2019, and 2020, with any necessary adjustments to be reflected in the Mississippi Power 2019 Base Rate Case. The ECO Settlement Agreement contains the same terms as the PEP Settlement Agreement described herein with respect to allowed ROE and equity ratio. At December 31, 2018, Mississippi Power has recorded $2 million in other regulatory liabilities, deferred on the balance sheet related to the actual December 31, 2018 average equity ratio differential from target applicable to the ECO Plan.

Fuel Cost Recovery

Mississippi Power establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. Mississippi Power is required to file for an adjustment to the retail fuel cost recovery factor annually. In January 2017, the Mississippi PSC approved the 2017 retail fuel cost recovery factor, effective February 2017 through January 2018, which resulted in an annual revenue increase of $55 million. On January 16, 2018, the Mississippi PSC approved the 2018 retail fuel cost recovery factor, effective February 2018 through January 2019, which resulted in an annual revenue increase of $39 million. At December 31, 2018, the amount of over recovered retail fuel costs included in the balance sheet in other accounts payable was approximately $8 million compared to $6 million under recovered at December 31, 2017. On January 10, 2019, the Mississippi PSC approved the 2019 retail fuel cost recovery factor, effective February 2019, which results in a $35 million decrease in annual revenues as a result of lower expected fuel costs.

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. On May 8, 2018, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2018, which included a rate increase of 0.8%, or $7 million, effective with the first billing cycle for June 2018.

Kemper County Energy Facility

Overview

The Kemper County energy facility was designed to utilize IGCC technology with an expected output capacity of 582 MWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper County energy facility. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper County energy facility construction, Mississippi Power constructed approximately 61 miles of CO₂ pipeline infrastructure for the transport of captured CO₂ for use in enhanced oil recovery.

Schedule and Cost Estimate

In 2012, the Mississippi PSC issued an order (2012 MPSC CPCN Order), confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper County energy facility. The certificated cost estimate of the Kemper County energy facility included in the 2012 MPSC CPCN Order was $2.4 billion, net of approximately $0.57 billion in Cost Cap Exceptions. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper County energy facility was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper County energy facility in service in August 2014. The combined cycle and associated common facilities portions of the Kemper County energy facility were dedicated as Plant Ratcliffe on April 27, 2018.

II-138

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

On June 21, 2017, the Mississippi PSC stated its intent to issue an order, which occurred on July 6, 2017, directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper County energy facility. The order established the Kemper Settlement Docket. On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper County energy facility, given the uncertainty as to its future.

At the time of project suspension in June 2017, the total cost estimate for the Kemper County energy facility was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE received in April 2016 (Additional DOE Grants). In the aggregate, Mississippi Power had recorded charges to income of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017.

Given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility and the subsequent suspension, cost recovery of the gasifier portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasification portions of the plant and lignite mine. During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as the charge associated with the Kemper Settlement Agreement discussed below.

In 2018, Mississippi Power recorded pre-tax charges to income of $37 million ($27 million after tax), primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. In addition, Mississippi Power recorded a credit to earnings of $95 million in the fourth quarter 2018 primarily resulting from the reduction of a valuation allowance for a state income tax NOL carryforward associated with the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding salvage, net of dismantlement costs), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated to total $11 million in 2019 and $2 million to $4 million annually in 2020 through 2023. Mississippi Power is currently evaluating its options regarding the final disposition of the CO₂ pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. If Mississippi Power ultimately decides to remove the CO₂ pipeline, the cost of removal would have a material impact on Mississippi Power's financial statements. The ultimate outcome of these matters cannot be determined at this time.

See Note 10 to the financial statements for additional information.

Rate Recovery

Kemper Settlement Agreement

In 2015, the Mississippi PSC issued the In-Service Asset Rate Order regarding the Kemper County energy facility assets that were commercially operational and providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million which went into effect on December 17, 2015.

On February 6, 2018, the Mississippi PSC voted to approve the Kemper Settlement Agreement, which resolved all cost recovery issues, modified the CPCN to limit the Kemper County energy facility to natural gas combined cycle operation, and provided for an annual revenue requirement of approximately $99.3 million for costs related to the Kemper County energy facility, which included the impact of the Tax Reform Legislation. The revenue requirement is based on (i) a fixed ROE for 2018 of 8.6% excluding any performance adjustment, (ii) a ROE for 2019 calculated in accordance with PEP, excluding the performance adjustment, (iii) for future years, a performance-based ROE calculated pursuant to PEP, and (iv) amortization periods for the related regulatory assets and liabilities of eight years and six years, respectively. The revenue requirement also reflects a disallowance related to a portion of Mississippi Power's investment in the Kemper County energy facility requested for inclusion in rate base, which was recorded in the fourth quarter 2017 as an additional charge to income of approximately $78 million ($85 million net of accumulated depreciation of $7 million) pre-tax ($48 million after tax).

Under the Kemper Settlement Agreement, retail customer rates reflect a reduction of approximately $26.8 million annually, effective with the first billing cycle of April 2018, and include no recovery for costs associated with the gasifier portion of the Kemper County energy facility in 2018 or at any future date.

II-139

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

Reserve Margin Plan

On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP), as required by the Mississippi PSC's order in the Kemper Settlement Docket. Under the RMP, Mississippi Power proposed alternatives that would reduce its reserve margin, with the most economic of the alternatives being the two-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. A decision by the Mississippi PSC that does not include recovery of the remaining book value of any generating units retired could have a material impact on Mississippi Power's financial statements. The ultimate outcome of this matter cannot be determined at this time.

Lignite Mine and CO₂ Pipeline Facilities

Mississippi Power owns the lignite mine and equipment and mineral reserves located around the Kemper County energy facility site. The mine started commercial operation in June 2013.

In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is responsible for the mining operations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018 and is expected to be substantially completed in 2020, with monitoring expected to continue through 2027. See Note 6 to the financial statements and Note 7 to the financial statements under "Mississippi Power" for additional information.

In addition, Mississippi Power constructed the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery and entered into an agreement with Denbury Onshore (Denbury) to purchase the captured CO₂. The agreement with Denbury was terminated in December 2018 and did not have a material impact on Mississippi Power's results of operations. Mississippi Power is currently evaluating its options regarding the final disposition of the CO₂ pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. If Mississippi Power ultimately decides to remove the CO₂pipeline, the cost of removal would have a material impact on Mississippi Power's financial statements. The ultimate outcome of this matter cannot be determined at this time.

For additional information on the Kemper County energy facility, see Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility."

Government Grants

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. Through December 31, 2018, Mississippi Power received total DOE grants of $387 million, of which $382 million reduced the construction costs of the Kemper County energy facility and $5 million reimbursed Mississippi Power for expenses associated with DOE reporting. On December 12, 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the grants received. Mississippi Power and the DOE are currently in discussions regarding the requested closeout and property disposition, which may require payment to the DOE for a portion of certain property that is to be retained by Mississippi Power. The ultimate outcome of this matter cannot be determined at this time; however, it could have a material impact on Mississippi Power's financial statements.

Income Tax Matters

Federal Tax Reform Legislation

In December 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduced the federal corporate income tax rate to 21%, retained normalization provisions for public utility property and existing renewable energy incentives, and repealed the corporate alternative minimum tax. In addition, under the Tax Reform Legislation, NOLs generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income of the subsequent tax year. The projected reduction of Southern Company's consolidated income tax liability resulting from the tax rate reduction also delays the expected

II-140

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

utilization of existing tax credit carryforwards. See Note 10 to the financial statements for information on Southern Company's joint consolidated income tax allocation agreement.

Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provided for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes and their application under GAAP, Mississippi Power considered all amounts recorded in the financial statements as a result of the Tax Reform Legislation "provisional" as discussed in SAB 118 and subject to revision prior to filing its 2017 tax return in the fourth quarter 2018. Mississippi Power recognized tax expense of $372 million in 2017. Following the filing of its 2017 tax return, Mississippi Power recorded tax benefits of $35 million to adjust the provisional amount for a total net tax expense of $337 million as a result of the Tax Reform Legislation. In addition, in total, Mississippi Power recorded an $11 million increase in regulatory assets and a $395 million increase in regulatory liabilities as a result of the Tax Reform Legislation and $1 million of stranded excess deferred tax balances in AOCI at December 31, 2017 were adjusted through retained earnings in 2018. As of December 31, 2018, Mississippi Power considered the measurement of impacts from the Tax Reform Legislation on deferred income tax assets and liabilities, primarily due to the impact of the reduction of the corporate income tax rate, to be complete.

However, the IRS continues to issue regulations that provide further interpretation and guidance on the law and each state's adoption of the provisions contained in the Tax Reform Legislation remains uncertain. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and the Mississippi PSC. The ultimate impact of this matter cannot be determined at this time. See Note 2 to the financial statements for additional information regarding the PEP Settlement Agreement and the ECO Settlement Agreement, which reflect certain impacts of the Tax Reform Legislation. Also see FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 10 to the financial statements under "Current and Deferred Income Taxes" for additional information.

Bonus Depreciation

Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the PATH Act. The PATH Act allowed for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. Based on provisional estimates, bonus depreciation is expected to result in positive cash flows of approximately $10 million for the 2018 tax year and Mississippi Power does not expect material positive cash flows from bonus depreciation for the 2019 tax year. See Note 10 to the financial statements under "Current and Deferred Income Taxes" for additional information. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

Mississippi Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of other natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings 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 would have a material effect on Mississippi Power's financial statements. See Notes 2 and 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

To mitigate customer rate impacts associated with rising costs and declining sales, Mississippi Power management approved an employee attrition plan on July 13, 2018. In 2018, Mississippi Power recorded $16 million in expenses related to this plan.

II-141

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

own 100% of a generating unit. On January 15, 2019, Gulf Power provided notice to Mississippi Power that Gulf Power will retire its share of the 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. The ultimate outcome of these matters remains subject to completion of Mississippi Power's evaluations and applicable regulatory approvals, including the FERC and the Mississippi PSC, and cannot now be determined. See Note 15 to the financial statements under "Southern Company's Sale of Gulf Power" for information regarding the sale of Gulf Power.

Litigation

On November 21, 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three current members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi. 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. They also allege that Mississippi Power underpaid customers in the refund process because it applied the wrong interest rate to the payments. 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.

Mississippi Power believes these legal challenges have no merit; however, an adverse outcome in either of these proceedings could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. Mississippi Power will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.

See Note 2 to the financial statements under "Kemper County Energy Facility" for additional information.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Mississippi Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Notes 1, 5, and 6 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on Mississippi Power's results of operations and related disclosures. 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.

Utility Regulation

Mississippi Power is subject to retail regulation by the Mississippi PSC and wholesale regulation by the FERC. These regulatory agencies set the rates Mississippi Power is permitted to charge customers based on allowable costs. As a result, Mississippi Power applies 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 has a further effect on Mississippi Power's 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 Mississippi Power; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and other postretirement benefits have less of a direct impact on Mississippi Power's results of operations and financial condition than they would on a non-regulated company.

As reflected in Note 2 to the financial statements under "Mississippi Power – Regulatory Assets and Liabilities," 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

II-142

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact Mississippi Power's financial statements.

Kemper County Energy Facility Closure Costs

For periods prior to the second quarter 2017, significant accounting estimates included Kemper County energy facility estimated construction costs, project completion date, and rate recovery. In the aggregate, Mississippi Power had recorded charges to income of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017, of which $305 million ($188 million after tax) occurred in 2017 and $428 million ($264 million after tax) occurred in 2016.

On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant; therefore, Mississippi Power suspended the operation and start-up of the gasifier portion of the Kemper County energy facility on June 28, 2017.

As a result of these events, cost recovery of the gasification portions became no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which included estimated costs associated with the gasification portions of the plant and lignite mine. During the third and fourth quarters of 2017, Mississippi Power recorded charges to income of $242 million ($206 million after tax), including $164 million for ongoing project costs, estimated mine and gasifier-related costs, and certain termination costs during the suspension period prior to conclusion of the Kemper Settlement Docket, as well as a charge of $78 million associated with the Kemper Settlement Agreement. The estimated construction costs and project completion date were no longer considered significant accounting estimates for 2017 following the suspension and related charges to earnings. In addition, the Kemper Settlement Agreement was approved by the Mississippi PSC on February 6, 2018 and resolved all related cost recovery issues.

In 2018, Mississippi Power recorded pre-tax charges to income of $37 million ($27 million after tax), primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding salvage, net of dismantlement costs), may be incurred through the first half of 2020. During the fourth quarter 2018, Mississippi Power began evaluating its options regarding the final disposition of the CO₂ pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. If Mississippi Power ultimately decides to remove the CO₂ pipeline, the cost of removal would have a material impact on Mississippi Power's financial statements. In addition, in December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the grants received. Mississippi Power and the DOE are currently in discussions regarding the requested closeout and property disposition, which may require payment to the DOE for a portion of certain property that is to be retained by Mississippi Power and could have a material impact on Mississippi Power's financial statements. Given the significant judgment and uncertainty involved in estimating these remaining costs associated with the abandonment and closure activities for the mine and gasifier-related assets at the Kemper County energy facility, Mississippi Power considers the related liabilities to be critical accounting estimates.

See Note 2 to the financial statements under "Kemper County Energy Facility" for additional information. The ultimate outcome of these matters cannot be determined at this time.

Asset Retirement Obligations

The liability for AROs primarily relates to facilities that are subject to the CCR Rule, principally ash ponds. In addition, Mississippi Power has AROs related to various landfill sites, underground storage tanks, water wells, mine reclamation, and asbestos removal.

Mississippi Power also has identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the 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

II-143

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

information becomes available to support a reasonable estimation of the retirement obligation. In 2018, Mississippi Power incurred $16 million in ARO revisions, including $11 million at Plant Greene County, which is co-owned with Alabama Power.

Given the significant judgment involved in estimating AROs, Mississippi Power considers the liabilities for AROs to be critical accounting estimates.

Pension and Other Postretirement Benefits

Mississippi Power's calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return 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 Mississippi Power believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefit costs and obligations.

Key elements in determining Mississippi Power's pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on Southern Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. Southern Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to Southern Company's target asset allocation. For purposes of determining Mississippi Power's liability related to the pension and other postretirement benefit plans, Southern Company discounts the future related cash flows using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments.

A 25 basis point change in any significant assumption (discount rate, salary increases, or long-term rate of return on plan assets) would result in a $1 million or less change in total annual benefit expense, a $19 million or less change in the projected obligation for the pension plan, and a $2 million or less change in the projected obligation for other post retirement benefit plans.

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

Contingent Obligations

Mississippi Power is subject to a number of federal and state laws and regulations as well as other factors and conditions that subject it 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. Mississippi Power periodically evaluates its exposure to such risks and records 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 Mississippi Power's results of operations, cash flows, or financial condition.

Recently Issued Accounting Standards

See Note 1 to the financial statements under "Recently Adopted Accounting Standards" for additional information.

In 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Mississippi Power adopted the new standard effective January 1, 2019.

Mississippi Power elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby the requirements of ASU 2016-02 are applied on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Mississippi Power elected the package of practical expedients provided by ASU 2016-02

II-144

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Mississippi Power 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. Mississippi Power also made accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and combined lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.

Mississippi Power completed the implementation of a new application to track and account for its leases and updated its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Mississippi Power completed its lease inventory and determined its most significant leases involve equipment and railcar leases. In the first quarter 2019, adoption of ASU 2016-02 did not have a material impact on Mississippi Power's balance sheet or statement of income.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Earnings for all periods presented were negatively affected by charges associated with the Kemper IGCC. See FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility" herein and Note 2 to the financial statements for additional information.

Mississippi Power's financial condition remained stable at December 31, 2018. Mississippi Power's cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, and debt maturities. Capital expenditures and other investing activities include investments 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. Operating cash flows provide a substantial portion of Mississippi Power's cash needs. For the three-year period from 2019 through 2021, Mississippi Power's projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. Mississippi Power plans to finance future cash needs in excess of its operating cash flows primarily through external securities issuances, borrowings from financial institutions, including commercial paper to the extent Mississippi Power is eligible to participate, and equity contributions from Southern Company. Mississippi Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.

Mississippi Power's investments in the qualified pension plan decreased in value as of December 31, 2018 as compared to December 31, 2017. No contributions to the qualified pension plan were made for the year ended December 31, 2018 and no mandatory contributions to the qualified pension plan are anticipated during 2019. See Note 11 to the financial statements under "Pension Plans" for additional information.

Net cash provided from operating activities totaled $804 million for 2018, an increase of $301 million as compared to 2017. The increase in cash provided from operating activities in 2018 was primarily related to increased income tax refunds in 2018 primarily related to the tax abandonment of the Kemper IGCC. Net cash provided from operating activities totaled $503 million for 2017, an increase of $274 million as compared to 2016. The increase in cash provided from operating activities in 2017 was primarily due to tax refunds associated with the Section 174 R&E settlement, largely offset by a decrease in income taxes related to the Kemper County energy facility and the Tax Reform Legislation.

Net cash used for investing activities in 2018, 2017, and 2016 totaled $232 million, $504 million, and $697 million, respectively. The cash used for investing activities in 2018 was primarily due to gross property additions related to other production, distribution, transmission, and steam production. The cash used for investing activities in 2017 and 2016 was primarily due to gross property additions related to the Kemper County energy facility. The cash used for investing activities in 2016 was partially offset by the receipt of Additional DOE Grants.

Net cash used for financing activities totaled $527 million in 2018 primarily due to redemption of preferred stock, long-term debt, short-term borrowings, and senior notes, partially offset by the issuance of senior notes and short-term borrowings. Net cash provided from financing activities totaled $25 million in 2017 primarily from capital contributions from Southern Company, largely offset by redemptions of long-term debt and short-term borrowings. Net cash provided from financing activities totaled $594 million in 2016 primarily due to long-term debt financings and capital contributions from Southern Company, partially offset by a decrease in short-term borrowings and redemptions of long-term debt.

Significant balance sheet changes in 2018 included increases of $442 million in long-term debt primarily due to the issuance of senior notes, a net change of $475 million in accumulated deferred income taxes primarily due to the tax abandonment of the

II-145

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

Kemper IGCC, and a decrease of $949 million in securities due within one year primarily due to the repayment of a $900 million unsecured term loan. See "Financing Activities" herein and Notes 8 and 10 to the financial statements for additional information.

Mississippi Power's ratio of common equity to total capitalization plus short-term debt was 50% and 39% at December 31, 2018 and 2017, respectively. The increase was primarily due to repayment of debt obligations in 2018. See Note 8 to the financial statements for additional information.

Sources of Capital

Mississippi Power plans to obtain the funds to meet its future capital needs from operating cash flows, external securities issuances, borrowings from financial institutions, including commercial paper to the extent Mississippi Power is eligible to participate, and equity contributions from Southern Company. However, the amount, type, and timing of any future financing, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors.

The issuance of securities by Mississippi Power is subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, Mississippi Power files registration statements with the SEC under the Securities Act of 1933, as amended. The amounts of securities authorized by the FERC, as well as the securities registered under the Securities Act of 1933, as amended, are continuously monitored and appropriate filings are made to ensure flexibility in raising capital. Any future financing through secured debt would also require approval by the Mississippi PSC.

Mississippi Power obtains 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 Mississippi Power are not commingled with funds of any other company in the Southern Company system.

Mississippi Power's current liabilities sometimes exceed 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. At December 31, 2018, Mississippi Power had approximately $293 million of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2018 were $100 million, all of which is unused. In October 2018, Mississippi Power amended its one-year credit arrangements in an aggregate amount of $100 million to extend the maturity dates from 2018 to 2019.

See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information.

All of these bank credit arrangements contain covenants that limit debt levels and typically contain cross acceleration provisions to other indebtedness (including guarantee obligations) of Mississippi Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2018, Mississippi Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.

Subject to applicable market conditions, Mississippi Power expects to renew or replace its credit arrangements as needed, prior to expiration. In connection therewith, Mississippi Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

A portion of the $100 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's revenue bonds. The amount of variable rate revenue bonds outstanding requiring liquidity support at December 31, 2018 was approximately $40 million.

Short-term borrowings are included in notes payable in the balance sheets. Details of short-term borrowing were as follows:



	Short-term Debt at the End of the Period				Short-term Debt During the Period ^(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
December 31, 2018	$	—	—	%	$	68	2.0	%	$	300
December 31, 2017	$	4	3.8	%	$	18	3.0	%	$	36
December 31, 2016	$	23	2.6	%	$	112	2.0	%	$	500


(*)	Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2018, 2017, and 2016.

II-146

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

Mississippi Power believes the need for working capital can be adequately met by utilizing lines of credit, short-term bank notes, commercial paper to the extent Mississippi Power is eligible to participate, and operating cash flows.

Financing Activities

In March 2018, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $100 million was repaid in the third quarter 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured floating rate term loan.

In July 2018, Mississippi Power purchased and held approximately $43 million aggregate principal amount of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002. Mississippi Power may reoffer these bonds to the public at a later date.

In October 2018, Mississippi Power completed the redemption of all 334,210 outstanding shares of its preferred stock (as well as related depositary shares), with an aggregate par value of approximately $33.4 million; all $30 million aggregate principal amount outstanding of its Series G 5.40% Senior Notes due July 1, 2035; and all $125 million aggregate principal amount outstanding of its Series 2009A 5.55% Senior Notes due March 1, 2019.

In December 2018, Southern Company made equity contributions totaling $17 million to Mississippi Power.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Mississippi Power plans, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

Credit Rating Risk

At December 31, 2018, Mississippi Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

On October 2, 2018, the Mississippi PSC approved executed agreements between Mississippi Power and its largest retail customer, Chevron, for Mississippi Power to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The agreements grant Chevron a security interest in the co-generation assets, with a net book value of approximately $101 million at December 31, 2018, 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.

There are certain contracts that have required or could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission. At December 31, 2018, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $283 million.

Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power (affiliate companies of Mississippi 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 Mississippi Power to access capital markets and would be likely to impact the cost at which it does so.

On February 28, 2018, Fitch removed Mississippi Power from rating watch negative and revised its rating outlook from stable to positive.

On March 14, 2018, S&P upgraded the senior unsecured long-term debt rating of Mississippi Power to A- from BBB+. The outlook remained negative.

As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Mississippi Power, may be negatively impacted. The PEP Settlement Agreement is expected to help mitigate these potential adverse impacts by allowing Mississippi Power to retain the excess deferred taxes resulting from the Tax Reform Legislation until the conclusion of the Mississippi Power 2019 Base Rate Case. In addition, Mississippi Power has committed to seek equity contributions sufficient to restore its equity ratio to the 50% target. See Note 2 to the financial statements under "Mississippi Power" for additional information.

II-147

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

Market Price Risk

Due to cost-based rate regulation and other various cost recovery mechanisms, Mississippi Power continues to have limited exposure to market volatility in interest rates, commodity fuel prices, and prices of electricity. To manage the volatility attributable to these exposures, Mississippi Power nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Mississippi Power's policies in areas such as counterparty exposure and risk management practices. Mississippi Power'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 that include, but are not limited to, market valuation, value at risk, stress testing, and sensitivity analysis.

To mitigate future exposure to a change in interest rates, Mississippi Power may enter into derivatives that have been designated as hedges. The weighted average interest rate on $340 million of long-term variable interest rate exposure at December 31, 2018 was 3.32%. If Mississippi Power sustained a 100 basis point change in interest rates for all long-term variable interest rate exposure, the change would have an immaterial effect on annualized interest expense at December 31, 2018. See Note 1 to the financial statements under "Financial Instruments" and Note 14 to the financial statements for additional information.

To mitigate residual risks relative to movements in electricity prices, Mississippi Power enters 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. Mississippi Power continues to manage retail fuel-hedging programs implemented per the guidelines of the Mississippi PSC and wholesale fuel-hedging programs under agreements with wholesale customers. Mississippi Power had no material change in market risk exposure for the year ended December 31, 2018 when compared to the year ended December 31, 2017.



	2018 Changes			2017 Changes
	Fair Value
	(in millions)
Contracts outstanding at the beginning of the period, assets (liabilities), net	$	(7	)	$	(7	)
Contracts realized or settled	3			8
Current period changes^(*)	(2		)	(8		)
Contracts outstanding at the end of the period, assets (liabilities), net	$	(6	)	$	(7	)


(*)	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 at December 31, 2018 and 2017 were as follows:



	2018	2017
	mmBtu Volume
	(in millions)
Natural gas options	3	—
Natural gas swaps	60	53
Total hedge volume	63	53

For natural gas hedges, the weighted average swap contract cost above market prices was approximately $0.10 per mmBtu at December 31, 2018 and $0.14 per mmBtu at December 31, 2017. The options outstanding were immaterial for the reporting periods presented. The costs associated with natural gas hedges are recovered through Mississippi Power's ECM clause.

At December 31, 2018 and 2017, substantially all of Mississippi Power's energy-related derivative contracts were designated as regulatory hedges and were related to Mississippi Power's fuel-hedging program. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as they are recovered through the ECM clause.

II-148

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

Mississippi Power uses 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. See Note 13 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts, which are all Level 2 of the fair value hierarchy, at December 31, 2018 were as follows:



	Fair Value Measurements December 31, 2018
	Total			Maturity
	Fair Value			Year 1			Years 2&3
	(in millions)
Level 1	$	—		$	—		$	—
Level 2	(6		)	(2		)	(4		)
Level 3	—			—			—
Fair value of contracts outstanding at end of period	$	(6	)	$	(2	)	$	(4	)

Mississippi Power is exposed to market price risk in the event of nonperformance by counterparties to the energy-related derivative contracts. Mississippi Power only enters 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, Mississippi Power does 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.

Capital Requirements and Contractual Obligations

The construction program of Mississippi Power is currently estimated to total $222 million for 2019, $230 million for 2020, $216 million for 2021, $220 million for 2022, and $184 million for 2023. The construction program includes capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $18 million, $20 million, $17 million, $5 million, and $13 million for 2019, 2020, 2021, 2022, and 2023, respectively. These estimated expenditures do not include any potential compliance costs associated with pending regulation of CO₂ emissions from fossil fuel-fired electric generating units. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations" and "– Global Climate Issues" herein for additional information.

Mississippi Power also anticipates costs associated with closure and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in Mississippi Power's ARO liabilities. These costs, which are expected to change and could change materially as underlying assumptions are refined and the cost and the method and timing of compliance activities continue to be evaluated, are currently estimated to be $9 million, $9 million, $12 million, $14 million, and $15 million for the years 2019, 2020, 2021, 2022, and 2023, respectively. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 6 to the financial statements for additional information.

In addition, as discussed in Note 11 to the financial statements, Mississippi Power provides postretirement benefits to substantially all employees and funds trusts to the extent required by the FERC.

Funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, derivative obligations, pension and other post-retirement benefit plans, leases, other purchase commitments, and ARO settlements are detailed in the contractual obligations table that follows. See Notes 1, 6, 8, 9, 11, and 14 to the financial statements for additional information.

II-149

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Mississippi Power Company 2018 Annual Report

Contractual Obligations

Contractual obligations at December 31, 2018 were as follows:



	2019		2020- 2021		2022- 2023		After 2023		Total
	(in millions)
Long-term debt^(a) —
Principal	$	—	$	577	$	—	$	983	$	1,560
Interest	70		130		80		577		857
Financial derivative obligations^(b)	3		5		—		—		8
Operating leases^(c)	3		3		2		2		10
Purchase commitments —
Capital^(d)	222		410		352		—		984
Fuel^(e)	378		368		199		136		1,081
Long-term service agreements^(f)	27		57		70		250		404
Purchased power^(g)	11		35		36		435		517
ARO settlements^(h)	9		21		29		—		59
Pension and other postretirement benefits plans⁽ⁱ⁾	8		15		—		—		23
Total	$	731	$	1,621	$	768	$	2,383	$	5,503

(a)

All amounts are reflected based on final maturity dates. Mississippi Power plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates at December 31, 2018, as reflected in the statements of capitalization. Fixed rates include, where applicable, the effects of interest rate derivatives employed to manage interest rate risk. For additional information, see Note 8 to the financial statements.


(b)	Derivative obligations are for energy-related derivatives. For additional information, see Notes 1 and 14 to the financial statements.


(c)	See Note 9 to the financial statements for additional information.

(d)

Mississippi Power provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. At December 31, 2018, significant purchase commitments were outstanding in connection with the construction program. These amounts exclude capital expenditures covered under LTSAs and estimated capital expenditures for AROs, which are reflected separately. See FUTURE EARNINGS POTENTIAL – "Environmental Matters" for additional information.

(e)

Includes commitments to purchase coal and natural gas, 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. Amounts reflected for natural gas purchase commitments have been estimated based on the NYMEX future prices at December 31, 2018.


(f)	LTSAs include price escalation based on inflation indices.


(g)	Estimated minimum long-term commitments for the purchase of solar energy. Energy costs associated with solar PPAs are recovered through the fuel clause. See Notes 2 and 9 to the financial statements for additional information.

(h)

Represents estimated costs for a five-year period associated with closing and monitoring ash ponds in accordance with the CCR Rule, which are reflected in Mississippi Power's ARO liabilities. Material expenditures in future years for ARO settlements also will be required for ash ponds and other liabilities reflected in Mississippi Power's AROs. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein and Note 6 to the financial statements for additional information.

(i)

Mississippi Power forecasts contributions to the pension and other postretirement benefit plans over a three-year period. Mississippi Power anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from Mississippi Power's corporate assets. See Note 11 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from Mississippi Power's corporate assets.

II-150

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Power Company and Subsidiary Companies 2018 Annual Report

OVERVIEW

Business Activities

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.

During 2018, Southern Power acquired and placed in service the 20-MW Gaskell West 1 solar facility, placed in service the 148-MW Cactus Flats wind facility, acquired and began construction of the 100-MW Wild Horse Mountain and the 200-MW Reading wind facilities, and continued construction of the expansion of the 385-MW Mankato natural gas facility. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.

Also during 2018, Southern Power completed the following sales of noncontrolling interests and sales of assets resulting in approximately $2.6 billion in proceeds:


•	On May 22, 2018, Southern Power sold a noncontrolling 33% equity interest in SP Solar, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, for approximately $1.2 billion.


•	On December 4, 2018, Southern Power sold all of its equity interests in Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) to NextEra Energy for $203 million.


•	On December 11, 2018, Southern Power sold a noncontrolling tax equity interest in SP Wind, a holding company owning a portfolio of eight operating wind facilities, for approximately $1.2 billion.

In addition, on November 5, 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of approximately $650 million. The completion of the disposition is subject to the expansion unit reaching commercial operation as well as various other customary conditions to closing, including FERC and state commission approvals, and the sale is expected to close mid-2019. The ultimate outcome of this matter cannot be determined at this time.

At December 31, 2018, Southern Power's generation fleet, which is owned in part with its various partners, totaled 11,888 MWs of nameplate capacity in commercial operation (including 4,508 MWs of nameplate capacity owned by its subsidiaries and including Plant Mankato, which is classified as held for sale in the financial statements). The average remaining duration of Southern Power's total portfolio of wholesale contracts is approximately 14 years, which reduces remarketing risk for Southern Power. With the inclusion of the PPAs and investments associated with renewable and natural gas facilities currently under construction, Southern Power has an average investment coverage ratio, at December 31, 2018, of 93% through 2023 and 91% through 2028 (including Plant Mankato, which is classified as held for sale in the financial statements).

Southern Power's future earnings will be materially decreased as a result of the asset and non-controlling interest sales described above. In addition, Southern Power's future earnings will depend on the parameters of the wholesale market and the efficient operation of its wholesale generating assets, as well as Southern Power's ability to execute its growth strategy and to develop and construct generating facilities. In addition, Southern Power's future earnings may be impacted by the availability of federal and state solar ITCs and wind PTCs on its renewable energy projects, which could be impacted by future tax legislation. See FUTURE EARNINGS POTENTIAL – "General," "Acquisitions," "Construction Projects," and "Income Tax Matters" herein and Notes 10 and 15 to the financial statements for additional information.

To evaluate operating results and to ensure Southern Power's ability to meet its contractual commitments to customers, Southern Power continues to focus on several key performance indicators, including, but not limited to, peak season equivalent forced outage rate, contract availability, and net income.

See RESULTS OF OPERATIONS herein for information on Southern Power's financial performance.

Earnings

Southern Power's 2018 net income was $187 million, an $884 million decrease from 2017, primarily attributable to $743 million of tax benefits recognized in 2017 and $79 million in tax expense recognized in 2018, both related to the Tax Reform Legislation. Also contributing to the decrease were asset impairment charges in 2018 totaling $156 million ($120 million pre-tax for the

II-151

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report

Florida Plants and $36 million pre-tax for turbine equipment held for development projects, which together totaled $117 million after tax), partially offset by approximately $65 million in state income tax benefits arising from reorganizations of legal entities that own and operate certain of Southern Power's solar and wind facilities.

Southern Power's 2017 net income was $1.1 billion, a $733 million increase from 2016, primarily attributable to $743 million in tax benefits recognized in 2017 related to the Tax Reform Legislation. Also contributing to the change were increases in operating expenses and interest expense related to Southern Power's growth strategy and continuous construction program, largely offset by increased renewable energy sales.

In addition, tax benefits from wind PTCs significantly impacted Southern Power's net income in 2018 and 2017. Tax benefits from solar ITCs related to the acquisition and construction of new facilities also significantly impacted Southern Power's net income in 2017 and 2016. See Note 10 to the financial statements under "Effective Tax Rate" for additional information.

RESULTS OF OPERATIONS

A condensed statement of income follows:



	Amount			Increase (Decrease) from Prior Year
	2018			2018			2017
	(in millions)
Operating revenues	$	2,205		$	130		$	498
Fuel	699			78			165
Purchased power	176			27			47
Other operations and maintenance	395			9			32
Depreciation and amortization	493			(10		)	151
Taxes other than income taxes	46			(2		)	25
Asset impairment	156			156			—
Gain on disposition	(2		)	(2		)	—
Total operating expenses	1,963			256			420
Operating income	242			(126		)	78
Interest expense, net of amounts capitalized	183			(8		)	74
Other income (expense), net	23			22			(5		)
Income taxes (benefit)	(164		)	775			(744		)
Net income	246			(871		)	743
Net income attributable to noncontrolling interests	59			13			10
Net income attributable to Southern Power	$	187		$	(884	)	$	733

Operating Revenues

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

Natural Gas and Biomass Capacity and Energy Revenue

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

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

II-152

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report

Solar and Wind Energy Revenue

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

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

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



	2018		2017		2016
			(in millions)
PPA capacity revenues	$	580	$	599	$	541
PPA energy revenues	1,140		970		694
Total PPA revenues	1,720		1,569		1,235
Non-PPA revenues	472		494		330
Other revenues	13		12		12
Total operating revenues	$	2,205	$	2,075	$	1,577

Operating revenues for 2018 were $2.2 billion, reflecting a $130 million, or 6%, increase from 2017. The increase in operating revenues was primarily due to the following:


•	PPA capacity revenues decreased $19 million, or 3%, primarily due to decreases of $16 million from the contractual expiration of an affiliate natural gas PPA and $5 million from the Florida Plants sold in December 2018.

•

PPA energy revenues increased $170 million, or 18%, primarily due to a $142 million increase in sales related to existing natural gas facilities driven by an $88 million increase in the average cost of fuel and a $54 million increase in the volume of KWHs sold due to customer load, a $12 million increase related to PPAs associated with new renewable facilities, and a $16 million increase related to PPAs associated with existing renewable facilities primarily due to an increase in the volume of KWHs sold.


•	Non-PPA revenues decreased $22 million, or 4%, primarily due to a $56 million decrease in the volume of KWHs sold from uncovered natural gas capacity through short-term sales, partially offset by a $35 million increase in the market price of energy.

Operating revenues for 2017 were $2.1 billion, reflecting a $498 million, or 32%, increase from 2016. The increase in operating revenues was primarily due to the following:


•	PPA capacity revenues increased $58 million, or 11%, primarily due to additional customer capacity requirements and a new PPA related to Plant Mankato acquired in late 2016.

•

PPA energy revenues increased $276 million, or 40%, primarily due to a $213 million increase in renewable energy sales arising from new solar and wind facilities and a $50 million increase in sales related to existing natural gas PPAs primarily due to an $85 million increase in the average cost of fuel, partially offset by a $35 million decrease in the volume of KWHs sold primarily due to reduced customer load.


•	Non-PPA revenues increased $164 million, or 50%, primarily due to a $156 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, as well as an $8 million increase in the market price of energy.

II-153

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report

Fuel and Purchased Power Expenses

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



	Total KWHs	Total KWH % Change	Total KWHs	Total KWH % Change
	2018		2017
	(in billions of KWHs)
Generation	46		44
Purchased power	4		5
Total generation and purchased power	50	2%	49	23%
Total generation and purchased power, excluding solar, wind, and tolling agreements	29	4%	28	22%

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

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

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



	2018		2017		2016
			(in millions)
Fuel	$	699	$	621	$	456
Purchased power	176		149		102
Total fuel and purchased power expenses	$	875	$	770	$	558

In 2018, total fuel and purchased power expenses increased $105 million, or 14%, compared to 2017. Fuel expense increased $78 million, or 13%, primarily due to a $60 million increase associated with the volume of KWHs generated, excluding solar, wind, and tolling agreements, primarily due to customer load, and an $18 million increase associated with the average cost of natural gas per KWH generated. Purchased power expense increased $27 million, or 18%, primarily due to a $43 million increase associated with the average cost of purchased power, primarily in the first quarter 2018, partially offset by a $16 million decrease associated with the volume of KWHs purchased.

In 2017, total fuel and purchased power expenses increased $212 million, or 38%, compared to 2016. Fuel expense increased $165 million, or 36%, primarily due to an $83 million increase associated with the volume of KWHs generated, excluding solar, wind, and tolling agreements, and an $82 million increase associated with the average cost of natural gas per KWH generated. Purchased power expense increased $47 million, or 46%, primarily due to a $37 million increase associated with the volume of KWHs purchased and an $11 million increase associated with the average cost of purchased power.

Other Operations and Maintenance Expenses

In 2018, other operations and maintenance expenses increased $9 million, or 2%, compared to 2017. The increase was primarily due to scheduled outage and maintenance expenses. In 2017, other operations and maintenance expenses increased $32 million, or 9%, compared to 2016. The increase was primarily due to increases of $56 million associated with new facilities, $21 million in business development and support expenses, and $6 million in employee compensation, all associated with Southern Power's overall growth. These 2017 increases were partially offset by decreases of $35 million associated with scheduled outage and maintenance expenses and $15 million in non-outage operations and maintenance expenses.

II-154

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report

Depreciation and Amortization

In 2018, depreciation and amortization decreased $10 million, or 2%, compared to 2017, primarily due to the cessation of depreciation on the Florida Plants and Plant Mankato that were classified as held for sale in May and November 2018, respectively. In 2017, depreciation and amortization increased $151 million, or 43%, compared to 2016, primarily due to additional depreciation related to new solar, wind, and natural gas facilities placed in service. See Note 5 to the financial statements under "Depreciation and Amortization – Southern Power" and Note 15 to the financial statements under "Southern Power" and "Assets Held for Sale" for additional information.

Taxes Other Than Income Taxes

In 2018, taxes other than income taxes decreased $2 million, or 4%, compared to 2017. In 2017, taxes other than income taxes were $48 million compared to $23 million in 2016, primarily due to additional property taxes on new facilities.

Asset Impairment

In 2018, asset impairment charges were $156 million. In the second quarter 2018, a $119 million asset impairment charge was recorded in contemplation of the sale of the Florida Plants. In addition, in the third quarter 2018, a $36 million asset impairment charge was recorded on wind turbine equipment held for development projects. There were no asset impairment charges recorded in 2017 or 2016. See Note 15 to the financial statements under "Southern Power – Sales of Natural Gas Plants" and " – Development Projects" for additional information.

Interest Expense, Net of Amounts Capitalized

In 2018, interest expense, net of amounts capitalized decreased $8 million, or 4%, compared to 2017. The decrease was primarily due to an increase in capitalized interest associated with construction projects. In 2017, interest expense, net of amounts capitalized increased $74 million, or 63%, compared to 2016. The increase was primarily due to an increase of $44 million in interest expense related to an increase in average outstanding long-term debt, primarily to fund Southern Power's growth strategy and continuous construction program, as well as a $30 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities.

Other Income (Expense), Net

In 2018, other income (expense), net increased $22 million compared to 2017 primarily due to a $14 million gain from a joint-development wind project, which is attributable to Southern Power's partner in the project and fully offset within noncontrolling interests. In 2017, other income (expense), net decreased $5 million compared to 2016.

Income Taxes (Benefit)

In 2018, income tax benefit was $164 million compared to $939 million for 2017, a decrease of $775 million, primarily attributable to a $743 million tax benefit in 2017 and a $79 million tax expense in 2018, both related to the remeasurement of accumulated deferred income taxes in accordance with the Tax Reform Legislation. In addition, income tax benefits associated with solar ITCs decreased by $58 million as a result of fewer solar facilities being placed in service in 2018 as compared to 2017. These decreases were partially offset by $65 million of income tax benefits related to certain changes in state apportionment rates arising from reorganizations of Southern Power's legal entities that own and operate certain of its solar and wind facilities and a decrease of $47 million of income tax expense as a result of lower pre-tax earnings and the lower federal tax rate.

In 2017, income tax benefit was $939 million compared to $195 million for 2016 of which $743 million of the increase was related to the Tax Reform Legislation. The remaining increase in tax benefit was primarily due to an increase of $89 million in PTCs from wind generation in 2017 and other state income taxes, significantly offset by a decrease in tax benefits associated with lower ITCs from solar facilities placed in service.

See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" herein and Notes 1 and 10 to the financial statements under "Income and Other Taxes" and "Effective Tax Rate," respectively, for additional information.

Net Income Attributable to Noncontrolling Interests

In 2018, net income attributable to noncontrolling interests increased $13 million, or 28%, compared to 2017. The increase was primarily due to $20 million of net income allocations due to the sale of a noncontrolling 33% equity interest in SP Solar and $14 million of other income allocations attributable to a joint-development wind project, partially offset by a reduction of $19 million due to HLBV income allocations between Southern Power and tax equity partners for partnerships entered into during 2018. In

II-155

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report

2017, noncontrolling interests increased $10 million, or 28%, compared to 2016 primarily due to additional net income allocations from new solar partnerships.

Effects of Inflation

Southern Power is party to long-term contracts reflecting market-based rates, including inflation expectations. Any adverse effect of inflation on Southern Power's results of operations has not been substantial in recent years.

FUTURE EARNINGS POTENTIAL

General

The results of operations for the past three years are not necessarily indicative of Southern Power's future earnings potential. Southern Power completed multiple sales of noncontrolling interests and assets in 2018 as described below. These sales will materially decrease future earnings and cash flows to Southern Power. See below for a summary of the 2018 disposition activity. The level of Southern Power's future earnings also depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power's competitive wholesale business. These factors include: Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Power's market areas; the successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its growth strategy through the development or acquisition of renewable facilities and other energy projects.

On May 22, 2018, Southern Power completed the sale of a noncontrolling 33% equity interest in SP Solar, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, to Global Atlantic Financial Group Limited (Global Atlantic) for an aggregate purchase price of approximately $1.2 billion. Accordingly, Global Atlantic will receive 33% of all cash distributions paid by SP Solar. Southern Power continues to consolidate the assets and liabilities of SP Solar with Global Atlantic's share of partnership earnings included in net income attributable to noncontrolling interests in the consolidated statements of income, which was $20 million for the period from May 22, 2018 to December 31, 2018.

Southern Power completed the sale of all of its equity interests in the Florida Plants to NextEra Energy on December 4, 2018, for an aggregate purchase price of $203 million. Pre-tax net income for the Florida Plants was $49 million and $37 million for the period from January 1, 2018 to December 4, 2018 and for the year ended December 31, 2017, respectively.

On December 11, 2018, Southern Power completed the sale of a noncontrolling tax equity interest in SP Wind, which owns a portfolio of eight operating wind facilities, to three financial investors, for approximately $1.2 billion. The tax equity investors together will generally receive 40% of the cash distributions from available cash and will receive a 99% allocation of tax attributes, including PTCs. Southern Power continues to consolidate the assets and liabilities of SP Wind with the investors' shares of partnership earnings reflected in net income attributable to noncontrolling interests in the consolidated statements of income.

On November 5, 2018, Southern Power entered into an agreement with Northern States Power to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of approximately $650 million. The completion of the disposition is subject to the expansion unit reaching commercial operation as well as various other customary conditions to closing, including working capital and timing adjustments. Pre-tax net income for Plant Mankato was immaterial for the years ended December 31, 2018 and 2017. This transaction is subject to FERC and state commission approvals and is expected to close mid-2019. The ultimate outcome of this matter cannot be determined at this time.

Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, as well as renewable portfolio standards, which may impact future earnings. Other factors that could influence future earnings include weather, transmission constraints, cost of generation from units within the power pool, and operational limitations.

Power Sales Agreements

General

Southern Power has PPAs with some of Southern Company's 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 in the event that S&P or Moody's downgrades the credit ratings of the respective company to an unacceptable credit rating or if the counterparty is not rated or fails to maintain a minimum coverage ratio.

II-156

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report

On January 29, 2019, Pacific Gas & Electric Company (PG&E) filed petitions to reorganize under Chapter 11 of the U.S. Bankruptcy Code. Southern Power, together with its noncontrolling partners, owns four solar facilities where PG&E is the energy off-taker for approximately 207 MWs of capacity under long-term PPAs. PG&E is also the transmission provider for these facilities and two of Southern Power's other solar facilities. Southern Power has evaluated the recoverability of its investments in these solar facilities under various scenarios, including selling the related energy into the competitive markets, and has concluded they are not impaired. At December 31, 2018, Southern Power had outstanding accounts receivables due from PG&E of $1 million related to the PPAs and $36 million related to the transmission interconnections (of which $17 million is classified in other deferred charges and assets). Southern Power does not expect a material impact to its financial statements if, as a result of the bankruptcy proceedings, PG&E does not perform in accordance with the PPAs or the terms of the PPAs are renegotiated; however, the ultimate outcome of this matter cannot be determined at this time.

Southern Power is working to maintain and expand its share of the wholesale markets. Southern Power expects there to be new demand for capacity that will develop in the 2019-2021 timeframe. The amount of available demand and timing will vary across the wholesale markets. Southern Power calculates an investment coverage ratio for its generating assets, which includes those assets owned in part with its various partners, based on the ratio of investment under contract to total investment using the respective generation 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 wind and natural gas facilities currently under construction, as well as other capacity and energy contracts, Southern Power has an average investment coverage ratio of 93% through 2023 and 91% through 2028, with an average remaining contract duration of approximately 14 years (including Plant Mankato, which is classified as held for sale in the financial statements). See "Acquisitions" and "Construction Projects" herein for additional information.

Natural Gas and Biomass

Southern Power's electricity sales from natural gas and biomass generating units 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 (renewables) generating facilities are also made pursuant to 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 solar and wind generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.

Environmental Matters

Southern Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Southern Power maintains a comprehensive environmental compliance strategy to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with

II-157

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report

environmental laws and regulations may impact results of operations, cash flows, and financial condition. Compliance costs may result from the installation of additional environmental controls. The ultimate impact of the environmental laws and regulations discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, fuel prices, and the outcome of pending and/or future legal challenges.

New or revised environmental laws and regulations could affect many areas of Southern Power's operations. 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 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 aesthetic 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 electric generating facility. The impact of such laws and regulations on Southern Power and subsequent recovery through PPA provisions cannot be determined at this time.

Environmental Laws and Regulations

Air Quality

In 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to address impacts of SO₂ and NO_X emissions from fossil fuel-fired electric generating plants. CSAPR establishes emissions trading programs and budgets for certain states and allocates emissions allowances for sources in those states. In 2016, the EPA published a final rule establishing more stringent ozone season NO_X emissions budgets in Alabama and Texas. The EPA also removed North Carolina from this particular CSAPR program. Georgia's ozone season NO_Xemissions budget remained unchanged. Increases in either future fossil fuel-fired generation or the availability or cost of CSAPR allowances could have a negative financial impact on results of operations for Southern Power.

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 (e.g. coal, natural gas, oil, and nuclear generating plants) and manufacturing facilities. The regulation requires plant-specific studies to determine applicable CWIS changes to protect organisms that either get caught on the intake screens (impingement) or are drawn into the cooling system (entrainment). Southern Power is conducting these studies and currently anticipates such changes will be limited to minor additions of monitoring equipment at certain of its electric generating plants. However, the ultimate 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 National Pollutant Discharge Elimination System (NPDES) permit based on site-specific factors, and the outcome of any legal challenges.

In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) jointly published a final rule that revised the regulatory definition of waters of the United States (WOTUS) for all CWA programs. The rule significantly expanded the scope of federal jurisdiction over waterbodies (such as rivers, streams, canals, and wastewater treatment ponds), which could impact new generation projects. The EPA and the Corps are expected to publish a final rule in 2019 to replace the 2015 WOTUS definition. The impact of any changes to the 2015 WOTUS rule will depend on the content of this final rule and the outcome of any legal challenges.

Global Climate Issues

On December 20, 2018, the EPA published a proposed review of the Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units final rule (2015 NSPS rule). The EPA's final 2015 NSPS rule set standards of performance for new, modified, and reconstructed electric utility generating units which included stationary combustion turbines and fossil-fired steam boilers. This proposal reduces the stringency of the 2015 NSPS rule by not basing the new and reconstructed fossil-fired steam boiler standards on partial carbon capture and sequestration. The impact of any changes to this rule will depend on the content of the final rule and the outcome of any legal challenges.

The EPA's GHG reporting rule requires annual reporting of GHG emissions expressed in terms of metric tons of CO₂ equivalent emissions for a company's operational control of facilities. Based on ownership or financial control of facilities, Southern Power's 2017 GHG emissions were approximately 13 million metric tons of CO₂ equivalent. The preliminary estimate of Southern Power's 2018 GHG emissions on the same basis is approximately 14 million metric tons of CO₂ equivalent.

II-158

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report

Income Tax Matters

Consolidated Income Taxes

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

Southern Power currently has unutilized federal ITC and PTC carryforwards totaling approximately $2.1 billion, and thus has utilized tax equity partnerships where the tax partner will take significantly all of the respective federal tax benefits on a prospective basis. These tax equity partnerships are consolidated in Southern Power's financial statements using the HLBV methodology to allocate partnership gains and losses. See Note 1 to the financial statements for additional information.

Federal Tax Reform Legislation

In December 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduced the federal corporate income tax rate to 21%, retained existing renewable energy incentives, and repealed the corporate alternative minimum tax. In addition, under the Tax Reform Legislation, NOLs generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income of the subsequent tax year. The projected reduction of Southern Company's consolidated income tax liability resulting from the tax rate reduction also delays the expected utilization of existing tax credit carryforwards.

Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provided for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes and their application under GAAP, Southern Power considered all amounts recorded in the financial statements as a result of the Tax Reform Legislation "provisional" as discussed in SAB 118 and subject to revision prior to filing its 2017 tax return in the fourth quarter 2018. Southern Power recognized tax benefits of $743 million in 2017. Following the filing of its 2017 tax return, Southern Power recorded tax expense of $79 million to adjust the provisional amount for a total net tax benefit of $664 million as a result of the Tax Reform Legislation. As of December 31, 2018, Southern Power considered the measurement of impacts from the Tax Reform Legislation on deferred income tax assets and liabilities, primarily due to the impact of the reduction of the corporate income tax rate, to be complete.

However, the IRS continues to issue regulations that provide further interpretation and guidance on the law and each state's adoption of the provisions contained in the Tax Reform Legislation remains uncertain. The ultimate impact of this matter cannot be determined at this time. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC. See Note 10 to the financial statements under "Current and Deferred Income Taxes" for additional information.

Tax Credits

The Tax Reform Legislation retained the renewable energy incentives that were included in the PATH Act. The PATH Act allows for 30% ITC for solar projects that commence construction by December 31, 2019; 26% ITC for solar projects that commence construction in 2020; 22% ITC for solar projects that commence construction in 2021; and a permanent 10% ITC for solar projects that commence construction on or after January 1, 2022. In addition, the PATH Act allows for 100% PTC for wind projects that commenced construction in 2016; 80% PTC for wind projects that commenced construction in 2017; 60% PTC for wind projects that commence construction in 2018; and 40% PTC for wind projects that commence construction in 2019. Wind projects commencing construction after 2019 will not be entitled to any PTCs. Southern Power has received ITCs related to its investment in new solar facilities acquired or constructed and receives PTCs related 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. In 2018, Southern Power sold noncontrolling tax equity interests in SP Wind and Cactus Flats, which both qualify for PTCs, and Gaskell West 1, which qualifies for ITCs. Under these partnerships, the tax equity investors will receive 99% of the PTC and ITC tax benefits and, therefore, Southern Power's tax benefits will be materially reduced. At December 31, 2018,

II-159

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report

Southern Power had approximately $2.1 billion of unutilized ITCs and PTCs, which are currently expected to be fully utilized by 2022, but could be further delayed. See Note 1 to the financial statements under "Income and Other Taxes" and Note 10 to the financial statements under "Current and Deferred Income Taxes – 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.

Bonus Depreciation

Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the PATH Act. The PATH Act allowed for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. Southern Power is not expecting material cash flows from bonus depreciation for the 2018 or 2019 tax years. However, any cash flows resulting from bonus depreciation would also be impacted by Southern Power's use of tax equity partnerships. See Note 10 to the financial statements under "Current and Deferred Income Taxes" for additional information. The ultimate outcome of these matters cannot be determined at this time.

Acquisitions

During 2018, Southern Power acquired and completed the project below and acquired the Wild Horse Mountain and Reading wind facilities discussed under "Construction Projects" herein. See Note 15 to the financial statements under "Southern Power" for additional information.



Project Facility	Resource	Seller, Acquisition Date	Approximate Nameplate Capacity (MW)	Location	Ownership Percentage		Actual COD	PPA Counterparties	PPA Contract Period
Gaskell West 1	Solar	Recurrent Energy Development Holdings, LLC, January 26, 2018	20	Kern County, CA	100% of Class B	(*)	March 2018	Southern California Edison	20 years


(*)	Southern Power owns 100% of the class B membership interests under a tax equity partnership.

The Gaskell West 1 facility did not have operating revenues or activities prior to being placed in service during March 2018.

Construction Projects

Construction Projects Completed and/or in Progress

During 2018, in accordance with its growth strategy, Southern Power started, continued, or completed construction of the projects set forth in the table below.



Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Ownership Percentage		Actual / Expected COD	PPA Counterparties	PPA Contract Period
Construction Projects Completed During the Year Ended December 31, 2018
Cactus Flats ^(a)	Wind	148	Concho County, TX	100% of Class B		July 2018	General Motors, LLC and General Mills Operations, LLC	12 years and 15 years
Projects Under Construction at December 31, 2018
Mankato expansion ^(b)	Natural Gas	385	Mankato, MN	100	%	Second quarter 2019	Northern States Power Company	20 years
Wild Horse Mountain ^(c)	Wind	100	Pushmataha County, OK	100	%	Fourth quarter 2019	Arkansas Electric Cooperative	20 years
Reading ^(d)	Wind	200	Osage and Lyon Counties, KS	100	%	Second quarter 2020	Royal Caribbean Cruises LTD	12 years


(a)	In July 2017, Southern Power purchased 100% of the Cactus Flats facility. In August 2018, Southern Power closed on a tax equity partnership and now owns 100% of the class B membership interests.


(b)	In November 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato, including this expansion currently under construction. See "Sales of Natural Gas Plants" below.

II-160

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report


(c)	In May 2018, Southern Power purchased 100% of the Wild Horse Mountain facility. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the class B membership interests. The ultimate outcome of this matter cannot be determined at this time.


(d)	In August 2018, Southern Power purchased 100% of the membership interests of the Reading facility from the joint development arrangement with Renewable Energy Systems Americas, Inc. described below. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the class B membership interests. The ultimate outcome of this matter cannot be determined at this time.

Total aggregate construction costs for projects under construction at December 31, 2018, excluding acquisition costs, are expected to be between $575 million and $640 million for the Plant Mankato expansion, Wild Horse Mountain, and Reading facilities. At December 31, 2018, total costs of construction incurred for these projects was $289 million, and is included in CWIP, except for the Plant Mankato expansion, which is included in assets held for sale in the financial statements. See Note 15 to the financial statements under "Southern Power" and "Assets Held for Sale" for additional information.

Development Projects

During 2017, Southern Power purchased wind turbine equipment to be used for various development and construction projects. Any wind projects using this equipment and reaching commercial operation by the end of 2021 are expected to qualify for 80% PTCs.

During 2016, Southern Power entered into a joint development agreement with Renewable Energy Systems Americas, Inc. (RES) to develop and construct wind projects. Concurrent with the agreement, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of these projects. Several wind projects using this equipment, as well as other purchased equipment, have successfully originated, directly or indirectly, from the partnership with RES and are expected to reach commercial operation before the end of 2020, thus qualifying for 100% PTCs.

Southern Power continues to evaluate and refine the deployment of the wind turbine equipment to potential joint development and construction projects as well as the amount of MW capacity to be constructed. During the third quarter 2018, as a result of a review of various options for probable dispositions of wind turbine equipment not deployed to development or construction projects, Southern Power recorded a $36 million asset impairment charge on the equipment.

Subsequent to December 31, 2018 and as part of management's continuous review of disposition options, approximately $53 million of this equipment is being marketed for sale and will be classified as held for sale.

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

Sales of Renewable Facility Interests

On May 22, 2018, Southern Power completed the sale of a noncontrolling 33% equity interest in SP Solar, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, to Global Atlantic for approximately $1.2 billion. Since Southern Power retains control of the limited partnership through its wholly-owned general partner, the sale was recorded as an equity transaction and Southern Power will continue to consolidate SP Solar in its financial statements. On the date of the transaction, the noncontrolling interest was increased by $511 million to reflect 33% of the carrying value of the partnership. This difference, partially offset by the tax impact and other related transaction charges, also resulted in a $410 million decrease to Southern Power's common stockholder's equity.

On December 11, 2018, Southern Power completed the sale of a noncontrolling tax equity interest in SP Wind, which owns a portfolio of eight operating wind facilities, to three financial investors for approximately $1.2 billion. The tax equity investors together will generally receive 40% of the cash distributions from available cash and will receive 99% of the tax attributes, including future production tax credits. Since Southern Power retains control of SP Wind, Southern Power will continue to consolidate SP Wind in its financial statements.

Sales of Natural Gas Plants

On December 4, 2018, Southern Power completed the sale of all of its equity interests in the Florida Plants to NextEra Energy for $203 million. In contemplation of this sale transaction, Southern Power recorded an asset impairment charge of approximately $119 million ($89 million after tax) in May 2018. Pre-tax net income for the Florida Plants was $49 million and $37 million for the period from January 1, 2018 to December 4, 2018 and for the year ended December 31, 2017, respectively.

On November 5, 2018, Southern Power entered into an agreement with Northern States Power to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of approximately $650 million. The completion of the disposition is subject to the expansion unit reaching commercial operation as well as various other customary conditions to closing, including working capital and timing adjustments. The ultimate purchase price will decrease $66,667 per day for each day after June 1, 2019 that the expansion has not achieved commercial operation, not to exceed $15 million. Pre-tax net income for Plant Mankato was immaterial for the years ended December 31, 2018 and 2017. This

II-161

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report

transaction is subject to FERC and state commission approvals and is expected to close mid-2019. The assets and liabilities of Plant Mankato are classified as held for sale as of December 31, 2018.

See Note 15 to the financial statements under "Southern Power" and "Assets Held for Sale" for additional information. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of other natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

Southern Power indirectly owns a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas. Prior to the facility being placed in service in 2016, certain solar panels were damaged during installation by the construction contractor, McCarthy Building Companies, Inc. (McCarthy), and certain solar panels were damaged by a hail event that also occurred during construction. In connection therewith, Southern Power is withholding payments of approximately $26 million from the construction contractor, which has placed a lien on the Roserock facility for the same amount. In May 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, (State Court lawsuit) against XL Insurance America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from the hail storm and McCarthy's installation practices. On June 1, 2018, the court in the State Court lawsuit granted Roserock's motion for partial summary judgment, finding that the insurers were in breach of contract and in violation of the Texas Insurance Code for failing to pay any monies owed for the hail claim. In addition to the State Court lawsuit, lawsuits were filed between Roserock and McCarthy, as well as other parties, and that litigation has been consolidated in the U.S. District Court for the Western District of Texas. Southern Power intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Power prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Notes 1, 4, and 10 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on Southern Power's results of operations and related disclosures. 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.

Revenue Recognition

Southern Power's revenue recognition depends on appropriate classification and documentation of transactions in accordance with GAAP. In general, Southern Power's power sale transactions, which include PPAs, can be classified in one of four categories: leases, non-derivatives or normal sale derivatives, derivatives designated as cash flow hedges, and derivatives not designated as hedges. For more information on derivative transactions, see FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein and Notes 1 and 14 to the financial statements. Southern Power's revenues are dependent upon significant judgments used to determine the appropriate transaction classification, which must be documented upon the inception of each contract.

Lease Transactions

Southern Power considers the following factors to determine whether the sales contract is a lease:


•	Assessing whether specific property is explicitly or implicitly identified in the agreement;

II-162

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report


•	Determining whether the fulfillment of the arrangement is dependent on the use of the identified property; and


•	Assessing whether the arrangement conveys to the purchaser the right to use the identified property.

If the contract meets the above criteria for a lease, Southern Power performs further analysis as to whether the lease is classified as operating, financing, or sales-type. All of Southern Power's power sales contracts that are determined to be leases are accounted for as operating leases and the capacity revenue is recognized on a straight-line basis over the term of the contract and is included in Southern Power's operating revenues. Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered.

Non-Derivative and Normal Sale Derivative Transactions

If the power sales contract is not classified as a lease, Southern Power further considers the following factors to determine proper classification:


•	Assessing whether the contract meets the definition of a derivative;


•	Assessing whether the contract meets the definition of a capacity contract;


•	Assessing the probability at inception and throughout the term of the individual contract that the contract will result in physical delivery; and


•	Ensuring that the contract quantities do not exceed available generating capacity (including purchased capacity).

Contracts that do not meet the definition of a derivative or are designated as normal sales (i.e. capacity contracts which provide for the sale of electricity that involve physical delivery in quantities within Southern Power's available generating capacity) are accounted for as executory contracts. For contracts that have a capacity charge, the revenue is generally recognized in the period that it becomes billable. Revenues related to energy and ancillary services are recognized in the period the energy is delivered or the service is rendered. See Note 4 to the financial statements for additional information.

Cash Flow Hedge Transactions

Southern Power further considers the following in designating other derivative contracts for the sale of electricity as cash flow hedges of anticipated sale transactions:


•	Identifying the hedging instrument, the forecasted hedged transaction, and the nature of the risk being hedged; and


•	Assessing hedge effectiveness at inception and throughout the contract term.

These contracts are accounted for on a fair value basis and are recorded in AOCI over the life of the contract. Realized gains and losses are then recognized in operating revenues as incurred.

Derivative (Non-Hedge) Transactions

Contracts for sales of electricity, which meet the definition of a derivative and that either do not qualify or are not designated as normal sales or as cash flow hedges, are accounted for on a fair value basis and are recorded in operating revenues.

Impairment of Long-Lived Assets and Intangibles

Southern Power's investments in long-lived assets are primarily generation assets, whether in service or under construction. Southern Power's intangible assets arise from certain acquisitions and consist of acquired PPAs, which are amortized to revenue over the term of the respective PPAs. Southern Power evaluates the carrying value of these assets whenever indicators of potential impairment exist. 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 inability of a customer to perform under the terms of the contract, or the inability to deploy wind turbine equipment to a development project. 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. 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. A high degree of judgment is required in developing estimates related to these evaluations, which are based on projections of various factors, including the following:


•	Future demand for electricity based on projections of economic growth and estimates of available generating capacity;


•	Future power and natural gas prices, which have been quite volatile in recent years; and


•	Future operating costs.

II-163

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report

In addition, when assets are identified as held for sale, an impairment loss is recognized to the extent that the carrying value of the assets or asset group exceeds the asset fair value less cost to sell. In 2018, an impairment charge of $119 million was recorded for the Florida Plants concurrent with the assets being identified as held for sale as a result of a signed purchase and sale agreement. Also in 2018, an impairment charge of $36 million was recorded for wind turbine equipment that is no longer likely to be deployed to a wind generation project.

Acquisition Accounting

Southern Power may acquire generation assets as part of its overall growth strategy. At the time of an acquisition, Southern Power will assess if these assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, Southern Power includes operating results from the date of acquisition in its consolidated 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 Southern Power may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions, and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred by Southern Power for potential or successful acquisitions are expensed as incurred.

Contingent consideration primarily relates to fixed amounts due to the seller once the facility is placed in service. For contingent consideration with variable payments, Southern Power fair values the arrangement with any changes recorded in the consolidated statements of income. See Note 13 to the financial statements for additional fair value information and Note 15 to the financial statements for additional information on recent acquisitions.

Accounting for Income Taxes

On behalf of Southern Power, Southern Company files a consolidated federal income tax return and 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 no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. Certain deductions and credits can be limited at the consolidated or combined level resulting in NOL and tax credit carryforwards that would not otherwise result on a stand-alone basis. Utilization of NOL and tax credit carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of Southern Power's, as well as Southern Company's, current financial position and results of operations, including currently available information about future years, to estimate when future taxable income will be realized.

Given the significant judgment involved in estimating NOL and tax credit carryforwards and multi-state apportionments for all subsidiaries, Southern Power considers federal and state deferred income tax liabilities and assets to be critical accounting estimates.

Recently Issued Accounting Standards

See Note 1 to the financial statements under "Recently Adopted Accounting Standards" for additional information.

II-164

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report

and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Southern Power adopted the new standard effective January 1, 2019.

Southern Power elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby the requirements of ASU 2016-02 are applied on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Southern Power elected the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Southern Power expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption. Southern Power also made accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and combined lessee lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes, while lessor lease and non-lease components are accounted for separately.

Southern Power completed the implementation of a new application to track and account for its leases and updated its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Southern Power completed its lease inventory and determined its most significant leases as a lessee involve real estate. In the first quarter 2019, the adoption of ASU 2016-02 resulted in recording lease liabilities and right-of-use assets on Southern Power's balance sheet each totaling approximately $0.4 billion, with no impact on Southern Power's statement of income.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power's financial condition remained stable at December 31, 2018. Southern Power's cash requirements primarily consist of funding ongoing business operations, common stock dividends, distributions to noncontrolling interests, capital expenditures, and debt maturities. Capital expenditures and other investing activities may include investments in acquisitions or new construction associated with Southern Power's overall growth strategy and to maintain the existing generation fleet's performance. Operating cash flows, which may include the utilization of tax credits, will only provide a portion of Southern Power's cash needs. For the three-year period from 2019 through 2021, Southern Power's projected common stock dividends, distributions to noncontrolling interests, capital expenditures, and debt maturities are expected to exceed operating cash flows. Southern Power plans to finance 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. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit agreements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Contractual Obligations" herein for additional information on lines of credit.

Southern Power also 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 a HLBV methodology to allocate partnership gains and losses. During 2018, Southern Power obtained tax equity funding for the Gaskell West 1 solar project, the Cactus Flats wind project, and the SP Wind portfolio and received proceeds of approximately $26 million, $122 million, and $1.2 billion, respectively.

On December 4, 2018, Southern Power completed the sale of all of its equity interests in the Florida Plants to NextEra Energy for $203 million. On November 5, 2018, Southern Power entered into an agreement with Northern States Power to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of approximately $650 million. The completion of the disposition is subject to the expansion unit reaching commercial operation as well as various other customary conditions to closing, and is expected to close mid-2019. The ultimate outcome of this matter cannot be determined at this time.

Net cash provided from operating activities totaled $631 million in 2018, a decrease of $524 million compared to 2017. The decrease was primarily due to lower income tax refunds as a result of taxable gains arising from the sales of noncontrolling interests in SP Solar and SP Wind, as well as the sale of the Florida Plants. At December 31, 2018, Southern Power had $2.1 billion of unutilized ITCs and PTCs which are expected to be fully utilized by 2022. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Tax Credits" herein for additional information. Net cash provided from operating activities totaled $1.2 billion in 2017, an increase of $816 million compared to 2016 primarily due to income tax refunds received and an increase in energy sales from new solar and wind facilities, partially offset by an increase in interest paid.

II-165

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report

Net cash used for investing activities totaled $227 million, $1.6 billion, and $4.8 billion in 2018, 2017, and 2016, respectively, and decreased in 2018 primarily due to fewer acquisitions and completion of construction of renewable facilities during 2017 and 2018. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein and Note 15 to the financial statements for additional information.

Net cash used for financing activities totaled $363 million in 2018 primarily due to returns of capital to Southern Company, payments of common stock dividends, and distributions to noncontrolling interests, partially offset by capital contributions from noncontrolling interests. Net cash used for financing activities totaled $502 million in 2017 primarily due to payments of common stock dividends and distributions to noncontrolling interests. Net cash provided from financing activities totaled $4.7 billion in 2016 primarily due to the issuance of additional senior notes and capital contributions from Southern Company and noncontrolling interests.

Significant balance sheet changes include a $745 million decrease in plant in service and a $576 million increase in assets held for sale primarily due to completed and planned plant divestitures and a $355 million increase in deferred income taxes primarily due to $551 million related to the sales of noncontrolling interests in SP Solar and SP Wind and $129 million in additional unutilized PTCs, partially offset by a $333 million decrease in the federal NOL carryforward.

Sources of Capital

Southern Power plans to obtain the funds required for acquisitions, construction, development, debt maturities, and other purposes from operating cash flows, external securities issuances, borrowings from financial institutions, tax equity partnership contributions, divestitures, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. With respect to the public offering of securities, Southern Power (excluding its subsidiaries) issues and offers debt registered on registration statements filed with the SEC under the Securities Act of 1933, as amended.

Southern Power's current liabilities sometimes exceed current assets due to the use of short-term debt as a funding source and construction payables, as well as fluctuations in cash needs due to seasonality. Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility (as defined below), borrowings from financial institutions, equity contributions from Southern Company, external securities issuances, and operating cash flows.

Southern Power obtains its own financing separately without any credit support from Southern Company or any other affiliate. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of Southern Power are not commingled with funds of any other company in the Southern Company system. To meet liquidity and capital resource requirements, Southern Power had cash and cash equivalents of approximately $181 million at December 31, 2018.

Southern Power's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes, including maturing debt. Southern Power's subsidiaries are not issuers under the commercial paper program. Short-term borrowings are included in notes payable on the consolidated balance sheets.

II-166

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report

Details of short-term borrowings were as follows:



	Short-term Borrowings at the End of the Period			Short-term Borrowings During the Period ^(*)
	Amount Outstanding		Weighted Average Interest Rate	Average Amount Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
December 31, 2018
Commercial paper	$	—	—%	$	77	2.2%	$	304
Short-term bank debt	100		3.1%	111		2.7%	200
Total	$	100	3.1%	$	188	2.5%
December 31, 2017
Commercial paper	$	105	2.0%	$	215	1.4%	$	419
Short-term bank debt	—		—%	17		2.1%	209
Total	$	105	2.0%	$	232	1.4%
December 31, 2016
Commercial paper	$	—	—%	$	56	0.8%	$	310
Total	$	—	—%	$	56	0.8%


(*)	Average and maximum amounts are based upon daily balances during the twelve-month periods ended December 31, 2018, 2017, and 2016.

In addition to the short-term borrowings of Southern Power included in the table above, at December 31, 2016, Southern Power subsidiaries assumed credit agreements (Project Credit Facilities) with the acquisition of certain solar facilities, which were non-recourse to the Southern Power parent company, the proceeds of which were used to finance project costs related to such solar facilities. The Project Credit Facilities were fully repaid in January 2017. For the year ended December 31, 2016, the Project Credit Facilities had a maximum amount outstanding of $828 million and an average amount outstanding of $566 million at a weighted average interest rate of 2.1% and had total amounts outstanding of $209 million at a weighted average interest rate of 2.1% at December 31, 2016.

Company Credit Facilities

At December 31, 2018, Southern Power had a committed credit facility (Facility) of $750 million expiring in 2022, of which $23 million has been used for letters of credit and $727 million remains unused. Southern Power's subsidiaries are not borrowers under the Facility. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. A portion of the unused credit under the Facility is allocated to provide liquidity support for Southern Power's commercial paper program. Subject to applicable market conditions, Southern Power expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information.

The Facility, as well as Southern Power's term loan agreements, contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 65% and contains a cross-default provision that is restricted only to indebtedness of Southern Power. For the purposes of this definition, debt would exclude any project debt incurred by certain subsidiaries of Southern Power to the extent such debt is non-recourse to Southern Power, and capitalization would exclude the capital stock or other equity attributable to such subsidiary. Southern Power is currently in compliance with all of these covenants.

Southern Power also has a $120 million continuing letter of credit facility for standby letters of credit. In December 2018, Southern Power amended the letter of credit facility, which, among other things, extended the expiration date from 2019 to 2021. At December 31, 2018, $103 million has been used for letters of credit, primarily as credit support for PPA requirements, and $17 million was unused. Southern Power's subsidiaries are not parties to this letter of credit facility.

In addition, at December 31, 2018 and 2017, Southern Power had $103 million and $113 million, respectively, of cash collateral posted related to PPA requirements.

II-167

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report

Financing Activities

Senior Notes

In June 2018, Southern Power repaid $350 million aggregate principal amount of Series 2015A 1.50% Senior Notes due June 1, 2018.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

Other Debt

In May 2018, Southern Power repaid $420 million aggregate principal amount of long-term floating rate bank loans.

Also in May 2018, Southern Power entered into two short-term floating rate bank loans, each for an aggregate principal amount of $100 million, which bear interest based on one-month LIBOR, and proceeds being used for general corporate purposes. In November 2018, Southern Power repaid one of these short-term loans.

Credit Rating Risk

Southern Power does 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 to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission.

The maximum potential collateral requirements under these contracts at December 31, 2018 were as follows:



Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	29
At BBB- and/or Baa3	$	338
At BB+ and/or Ba1^(*)	$	980


(*)	Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million.

Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power (affiliate companies of Southern 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 Southern Power to access capital markets and would be likely to impact the cost at which it does so.

In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade.

On September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and certain of its subsidiaries (including Southern Power).

Market Price Risk

Southern Power is exposed to market risks, primarily commodity price risk, interest rate risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, Southern Power nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Southern Power's policies in areas such as counterparty exposure and risk management practices. Southern Power'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 consolidated balance sheets as either assets or liabilities and are presented on a gross basis. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities.

II-168

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report

At December 31, 2018, Southern Power had $525 million of long-term variable rate notes outstanding. If Southern Power sustained a 100 basis point change in interest rates for its variable interest rate exposure, the change would affect annualized interest expense by approximately $5 million at December 31, 2018. Since a significant portion of outstanding indebtedness bears interest at fixed rates, Southern Power is not aware of any facts or circumstances that would significantly affect exposure on existing indebtedness in the near term. However, the impact on future financing costs cannot be determined at this time.

Southern Power had foreign currency denominated debt of €1.1 billion at December 31, 2018. Southern Power has mitigated its exposure to foreign currency exchange rate risk through the use of foreign currency swaps converting all interest and principal payments to fixed-rate U.S. dollars.

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.

For the years ended December 31, 2018 and 2017, the changes in fair value of energy-related derivative contracts associated with both power and natural gas positions were as follows:



	2018			2017
	(in millions)
Contracts outstanding at the beginning of period, assets (liabilities), net	$	(10	)	$	16
Contracts realized or settled	10			(17		)
Current period changes^(*)	(4		)	(9		)
Contracts outstanding at the end of period, assets (liabilities), net	$	(4	)	$	(10	)


(*)	Current period changes also include changes in the fair value of new contracts entered into during the period, if any.

For the years ending December 31, 2018 and 2017, the changes in contracts outstanding were attributable to both the volume and the prices of power and natural gas as follows:



	2018			2017
Power – net sold
MWH (in millions)	2.5			3.0
Weighted average contract cost per MWH above (below) market prices (in dollars)	$	(0.23	)	$	(2.67	)
Natural Gas – net purchased
Commodity - mmBtu (in millions)	15.0			14.4
Commodity - weighted average contract cost per mmBtu above (below) market prices (in dollars)	$	0.22		$	0.12

Gains and losses on energy-related derivatives designated as cash flow hedges which are used by Southern Power to hedge anticipated purchases and sales are initially deferred in OCI before being recognized in income in the same period as the hedged transactions are reflected in earnings. Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the consolidated statements of income as incurred.

Southern Power uses 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. See Note 13 to the financial statements for further discussion of fair value measurements. The energy-related derivative contracts outstanding at December 31, 2018 mature through 2020.

Southern Power is exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Power only enters into agreements and material transactions with counterparties that have investment grade credit ratings by S&P and Moody's or with counterparties who have posted collateral to cover potential credit exposure. Southern Power has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Power's exposure to counterparty credit risk. Therefore, Southern Power does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. See Note 1 to the financial statements under "Financial Instruments" and Note 14 to the financial statements for additional information.

Capital Requirements and Contractual Obligations

The capital program of Southern Power is subject to periodic review and revision and is currently estimated to total $0.9 billion over the next five years through 2023. This includes committed construction, capital improvements, and work to be performed

II-169

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Power Company and Subsidiary Companies 2018 Annual Report

under LTSAs, totaling approximately $300 million for each of 2019 and 2020 and an average of approximately $100 million each year from 2021 through 2023. In addition, Southern Power has a further $2.3 billion in planned expenditures for plant acquisitions and placeholder growth, or approximately $0.5 billion per year on average for 2019 through 2023. Planned expenditures for plant acquisitions and placeholder growth may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Actual construction costs may vary from these estimates because of numerous factors such as: changes in business conditions; changes in the expected environmental compliance program; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in FERC rules and regulations; changes in load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note 15 to the financial statements under "Southern Power" for additional information.

Southern Power forecasts contributions to the pension and other postretirement benefit plans over a three-year period. Southern Power anticipates no mandatory contributions to the qualified pension plan during the next three years. See Note 11 to the financial statements for additional information.

Funding requirements related to obligations associated with scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, and other purchase commitments are detailed in the contractual obligations table that follows. See Notes 1, 8, 9, and 14 to the financial statements for additional information.

Contractual Obligations

Contractual obligations at December 31, 2018 were as follows:



	2019		2020- 2021		2022- 2023		After 2023		Total
	(in millions)
Long-term debt^(a) —
Principal	$	600	$	1,125	$	967	$	2,339	$	5,031
Interest	179		310		250		1,409		2,148
Financial derivative obligations^(b)	6		2		—		—		8
Operating leases^(c)	23		48		50		874		995
Purchase commitments —
Capital^(d)	252		461		144		—		857
Fuel^(e)	601		744		369		32		1,746
Purchased power^(f)	41		83		—		—		124
Other^(g)	168		309		221		1,471		2,169
Total	$	1,870	$	3,082	$	2,001	$	6,125	$	13,078

(a)

All amounts are reflected based on final maturity dates and include the effects of interest rate derivatives employed to manage interest rate risk and effects of foreign currency swaps employed to manage foreign currency exchange rate risk. Included in debt principal is an $18 million gain related to the foreign currency hedge of €1.1 billion. Southern Power plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.


(b)	For additional information, see Notes 1 and 14 to the financial statements.


(c)	Operating lease commitments include certain land leases for solar and wind facilities that may be subject to annual price escalation based on indices. See Note 9 to the financial statements for additional information.

(d)

Southern Power provides estimated capital expenditures for a five-year period, including capital expenditures associated with environmental regulations. Excluded from these amounts are planned expenditures for plant acquisitions and placeholder growth of $2.3 billion. Also excluded from these amounts are capital expenditures covered under LTSAs which are reflected in "Other." See Note (g) below. At December 31, 2018, significant purchase commitments were outstanding in connection with the construction program. No ARO settlements are projected during the five-year period.


(e)	Primarily includes commitments to purchase, transport, and store natural gas. Amounts reflected are based on contracted cost and may contain provisions for price escalation. Amounts reflected for natural gas purchase commitments are based on various indices at the time of delivery and have been estimated based on the NYMEX future prices at December 31, 2018.


(f)	Purchased power commitments will be resold under a third party agreement at cost.


(g)	Includes commitments related to LTSAs, operation and maintenance agreements, and transmission. LTSAs include price escalation based on inflation indices. Transmission commitments are based on the Southern Company system's current tariff rate for point-to-point transmission.

II-170

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Company Gas and Subsidiary Companies 2018 Annual Report

OVERVIEW

Business Activities

Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas. Subsequent to the dispositions of Elizabethtown Gas, Elkton Gas, and Florida City Gas discussed herein under "Merger, Acquisition, and Disposition Activities," Southern Company Gas has natural gas distribution utilities in four states – Illinois, Georgia, Virginia, and Tennessee. Southern Company Gas is also involved in several other complementary businesses.

Southern Company Gas manages its business through four reportable segments – gas distribution operations, gas pipeline investments, wholesale gas services, which includes Sequent, a natural gas asset optimization company, and gas marketing services, which includes SouthStar, a provider of energy-related products and services to natural gas markets – and one non-reportable segment, all other. During the fourth quarter 2018, Southern Company Gas changed its reportable segments to further align with the way its new Chief Operating Decision Maker reviews operating results and has reclassified prior years' data to conform to the new reportable segment presentation. This change resulted in a new reportable segment, gas pipeline investments, which was formerly included in gas midstream operations. Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including a 50% interest in SNG, two significant pipeline construction projects, and a 50% joint ownership interest in the Dalton Pipeline. Gas distribution operations, wholesale gas services, and gas marketing services continue to remain as separate reportable segments and reflect the impact of the Southern Company Gas Dispositions. The all other non-reportable segment includes segments below the quantitative threshold for separate disclosure, including the storage and fuels operations that were formerly included in gas midstream operations, and other subsidiaries that fall below the quantitative threshold for separate disclosure. See Notes 5, 7, and 16 to the financial statements for additional information.

Many factors affect the opportunities, challenges, and risks of Southern Company Gas' business. These factors include the ability to maintain safety, to maintain constructive regulatory environments, to maintain and grow natural gas sales and number of customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, environmental standards, safety, reliability, resilience, natural gas, and capital expenditures, including updating and expanding the natural gas distribution systems. The natural gas distribution utilities have various regulatory mechanisms that address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Southern Company Gas for the foreseeable future. Nicor Gas filed a rate case on November 9, 2018 and Atlanta Gas Light is required to file a rate case no later than June 1, 2019. These rate cases are both expected to conclude in 2019; however, the ultimate outcome of these matters cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Rate Proceedings" herein and Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" for additional information.

Merger, Acquisition, and Disposition Activities

In 2016, Southern Company Gas completed the Merger, pursuant to which Southern Company Gas became a wholly-owned subsidiary of Southern Company. Southern Company accounted for the Merger using the acquisition method of accounting whereby the assets acquired and liabilities assumed were recognized at fair value as of the acquisition date. Pushdown accounting was applied to create a new cost basis for Southern Company Gas' assets, liabilities, and equity as of the acquisition date. Accordingly, the successor financial statements reflect the new basis of accounting, and successor and predecessor period financial results (separated by a heavy black line) are presented, but are not comparable. As a result of the application of acquisition accounting, certain discussions herein include disclosure of the predecessor and successor periods. See Note 15 to the financial statements under "Southern Company Merger with Southern Company Gas" for additional information.

In 2016, Southern Company Gas completed its purchase of Piedmont's 15% interest in SouthStar for $160 million and paid $1.4 billion to acquire a 50% equity interest in SNG, which is the owner of a 7,000-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. The investment in SNG is accounted for using the equity method. In March 2017, Southern Company Gas made an additional $50 million contribution to maintain its 50% equity interest in SNG. See Note 7 to the financial statements under "Southern Company Gas" and Note 15 to the financial statements under "Southern Company Gas – Investment in SNG" for additional information.

During 2018, Southern Company Gas completed the following sales, resulting in approximately $2.7 billion in aggregate proceeds:


•	On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $365 million, which includes the final working capital adjustment.

II-171

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

This disposition resulted in a net loss of $67 million, which includes $34 million of income tax expense. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded in 2018.

•

On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion, which includes the final working capital and other adjustments. This disposition resulted in a pre-tax gain that was entirely offset by $205 million of income tax expense, resulting in no material net income impact.

•

On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy for a total cash purchase price of $587 million, which includes the final working capital adjustment less indebtedness assumed at closing. This disposition resulted in a net gain of $16 million, which includes $103 million of income tax expense.

The after-tax gain and loss on these dispositions included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. See Note 15 to the financial statements under "Southern Company Gas" herein for additional information.

Operating Metrics

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

Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. With the exception of Nicor Gas, Southern Company Gas has various regulatory mechanisms, such as weather normalization and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its utilities' respective service territory. However, the operating revenues from utility customers in Illinois and gas marketing services customers primarily in Georgia and Illinois can be impacted by warmer- or colder-than-normal weather. Southern Company Gas utilizes weather hedges to limit the negative income impacts in the event of warmer-than-normal weather, while retaining a significant portion of the positive benefits of colder-than-normal weather for these businesses.

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

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

See RESULTS OF OPERATIONS herein for additional information on these operating metrics.

II-172

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

Seasonality of Results

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



	Percent Generated During Heating Season
	Operating Revenues		Net Income
Successor - 2018	68.7	%	96.0	%
Successor - 2017	67.3	%	73.7	%
Successor - July 1, 2016 through December 31, 2016	67.1	%	96.5	%
Predecessor - January 1, 2016 through June 30, 2016	70.0	%	138.9	%

Earnings

Net income attributable to Southern Company Gas for the successor year ended December 31, 2018 was $372 million, representing a $129 million, or 53.1%, increase over the previous year. Excluding a $121 million decrease related to the Southern Company Gas Dispositions, net income attributable to Southern Company Gas increased $251 million. This increase was primarily due to lower income tax expense, increased commercial activity at wholesale gas services, increased operating revenues from infrastructure replacement programs and base rate changes at gas distribution operations, and higher earnings from Southern Company Gas' investment in SNG. These increases were partially offset by higher other operations and maintenance expenses primarily due to increased compensation and benefit costs and disposition-related costs, higher depreciation on continued infrastructure investments at gas distribution operations, additional interest expense on new debt issuances, and an increase in charitable donations.

Net income attributable to Southern Company Gas for the successor year ended December 31, 2017 was $243 million, which included net income of $53 million from Southern Company Gas' investment in SNG and $44 million generated from Southern Company Gas' continued investment in infrastructure replacement programs and base rate increases at Atlanta Gas Light, Elizabethtown Gas, and Virginia Natural Gas, less the associated increases in depreciation. Net income also reflects $130 million of additional tax expense resulting from the revaluation of deferred tax assets of $93 million related to the Tax Reform Legislation and $37 million associated with State of Illinois income tax legislation enacted in the third quarter 2017 and new income tax apportionment factors in several states resulting from Southern Company Gas' inclusion in the consolidated Southern Company state tax filings. Also included in net income was $17 million of additional expense resulting from the pushdown of acquisition accounting.

See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" herein and Notes 10 and 15 to the financial statements for additional information.

Net income attributable to Southern Company Gas for the successor period of July 1, 2016 through December 31, 2016 was $114 million, which included $26 million in earnings from the SNG investment, net of related interest expense, partially offset by $12 million of additional expense resulting from the impact of the pushdown of acquisition accounting and $27 million of Merger-related expenses.

Net income attributable to Southern Company Gas for the predecessor period of January 1, 2016 through June 30, 2016 was $131 million, which included $41 million of Merger-related expenses and $14 million of net income attributable to the SouthStar noncontrolling interest, which Southern Company Gas purchased in October 2016. Net income for the predecessor period reflected higher revenues from continued investment in infrastructure programs, partially offset by warm weather, net of hedging, and low earnings from wholesale gas services due to mark-to-market losses.

II-173

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

RESULTS OF OPERATIONS

Operating Results

A condensed income statement for Southern Company Gas follows:



	Successor							Predecessor
	Year Ended December 31,			Year Ended December 31,		July 1, 2016 through December 31,		January 1, 2016 through June 30,
	2018			2017		2016		2016
	(in millions)							(in millions)
Operating revenues	$	3,909		$	3,920	$	1,652	$	1,905
Cost of natural gas	1,539			1,601		613		755
Cost of other sales	12			29		10		14
Other operations and maintenance	981			945		480		452
Depreciation and amortization	500			501		238		206
Taxes other than income taxes	211			184		71		99
Goodwill impairment	42			—		—		—
Gain on dispositions, net	(291		)	—		—		—
Merger-related expenses	—			—		41		56
Total operating expenses	2,994			3,260		1,453		1,582
Operating income	915			660		199		323
Earnings from equity method investments	148			106		60		2
Interest expense, net of amounts capitalized	228			200		81		96
Other income (expense), net	1			44		12		3
Earnings before income taxes	836			610		190		232
Income taxes	464			367		76		87
Net Income	372			243		114		145
Net income attributable to noncontrolling interest^(*)	—			—		—		14
Net Income Attributable to Southern Company Gas	$	372		$	243	$	114	$	131


(*)	Includes Piedmont's 15% interest in SouthStar, which was acquired by Southern Company Gas in 2016. See Note 7 to the financial statements under "Southern Company Gas" for additional information.

The Southern Company Gas Dispositions were completed by July 29, 2018 and represent the primary variance driver for the 2018 changes. Detailed variance explanations are provided herein. See Note 15 to the financial statements under "Southern Company Gas" for additional information on the Southern Company Gas Dispositions.

Operating Revenues

Operating revenues for the successor year ended December 31, 2018 were $3.9 billion, reflecting an $11 million decrease from 2017. Operating revenues for the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016 were $3.9 billion and $1.7 billion, respectively. For the predecessor period of January 1, 2016 through June 30, 2016, operating revenues were $1.9 billion.

II-174

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

For the successor year ended December 31, 2018, details of operating revenues were as follows:



	(in millions)			(% change)
Operating revenues – prior year	$	3,920
Estimated change resulting from –
Infrastructure replacement programs and base rate changes	31			0.8
Gas costs and other cost recovery	3			0.1
Weather	13			0.3
Wholesale gas services	138			3.5
Southern Company Gas Dispositions^(*)	(228		)	(5.8	)
Other	32			0.8
Operating revenues – current year	$	3,909		(0.3	)%


(*)	Includes a $154 million decrease related to natural gas revenues, including alternative revenue programs, and a $74 million decrease related to other revenues. See Note 15 to the financial statements under "Southern Company Gas" for additional information.

Revenues from infrastructure replacement programs and base rate changes increased in 2018 primarily due to a $48 million increase at Nicor Gas, partially offset by a $12 million decrease at Atlanta Gas Light. These amounts include gas distribution operations' continued investments recovered through infrastructure replacement programs and base rate increases less revenue reductions for the impacts of the Tax Reform Legislation. See Note 2 to the financial statements under "Southern Company Gas" for additional information.

Revenues increased due to colder weather in 2018 compared to 2017. See "Heating Degree Days" herein for additional information.

Revenues from wholesale gas services increased in 2018 primarily due to increased commercial activity, partially offset by derivative losses. See "Segment Information – Wholesale Gas Services" herein for additional information.

Other revenues increased in 2018 primarily due to a $15 million increase from the Dalton Pipeline being placed in service in August 2017 and a $14 million increase in Nicor Gas' revenue taxes.

For the successor year ended December 31, 2017, natural gas revenues included recovery of $1.6 billion in cost of natural gas and $6 million in net revenues from wholesale gas services, net of $21 million of amortization associated with assets established in the application of acquisition accounting. Also included in natural gas revenues for the successor year ended December 31, 2017 were $99 million in additional revenues generated from gas distribution operations as a result of continued investment in infrastructure replacement programs and increases in base rate revenues at Atlanta Gas Light, Elizabethtown Gas, and Virginia Natural Gas. Natural gas revenues were partially offset by a $13 million negative impact of warmer-than-normal weather, net of hedging.

For the successor period of July 1, 2016 through December 31, 2016, natural gas revenues included recovery of $613 million in cost of natural gas and $24 million in net revenues from wholesale gas services, net of $5 million of amortization associated with assets established in the application of acquisition accounting. Natural gas revenues were partially offset by a $5 million negative impact of warmer-than-normal weather, net of hedging.

For the predecessor period of January 1, 2016 through June 30, 2016, natural gas revenues included recovery of $755 million in cost of natural gas and $32 million in net losses from wholesale gas services. Natural gas revenues were partially offset by a $7 million negative impact of warmer-than-normal weather, net of hedging.

Heating Degree Days

During Heating Season, natural gas usage and operating revenues are generally higher. Weather typically does not have a significant net income impact other than during the Heating Season. The following table presents the Heating Degree Days information for Illinois and Georgia, the primary locations where Southern Company Gas' operations are impacted by weather.

II-175

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report



	Years Ended December 31,				2018 vs. normal		2018 vs. 2017		2017 vs. 2016
	Normal^(*)	2018	2017	2016	colder		colder		colder (warmer)
	(in thousands)
Illinois	5,813	6,101	5,246	5,243	5.0	%	16.3	%	0.1	%
Georgia	2,539	2,588	1,970	2,175	1.9	%	31.4	%	(9.4	)%


(*)	Normal represents the 10-year average from January 1, 2008 through December 31, 2017 for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, based on information obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center.

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 are reflected in the chart below.



	Successor									Predecessor
	Year Ended December 31,			Year Ended December 31,			July 1, 2016 through December 31,			January 1, 2016 through June 30,
	2018			2017			2016			2016
	(in millions)									(in millions)
Gas Distribution Operations:
Pre-tax	$	2		$	(4	)	$	(1	)	$	(7	)
After tax	1			(2		)	(1		)	(5		)

Gas Marketing Services:
Pre-tax	(2		)	(9		)	(4		)	—
After tax	(1		)	(5		)	(3		)	—

Customer Count

The following table provides the number of customers served by Southern Company Gas at December 31, 2018, 2017, and 2016:



	2018		2017		2016
	(in thousands, except market share %)
Gas distribution operations^(a)	4,248		4,623		4,586
Gas marketing services
Energy customers^(b)	697		774		656
Market share of energy customers in Georgia	29.0	%	29.2	%	29.6	%


(a)	Includes total customers of approximately 407,000 and 402,000 at December 31, 2017 and 2016, respectively, related to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold in 2018. See Note 15 to the financial statements under "Southern Company Gas – Sale of Elizabethtown Gas and Elkton Gas" and " – Sale of Florida City Gas" for additional information.


(b)	Includes customers in Ohio contracted through an annual auction process to serve for a 12-month period beginning April 1 of each year. At December 31, 2018 and 2017, there were approximately 70,000 and 140,000 contracted customers, respectively. At December 31, 2016, there were no contracted customers.

Southern Company Gas anticipates overall customer growth trends at the remaining four natural gas distribution utilities in gas distribution operations to continue as it expects continued improvement in the new housing market and low natural gas prices. Southern Company Gas uses a variety of targeted marketing programs to attract new customers and to retain existing customers.

Cost of Natural Gas

Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, gas distribution operations charges its utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. Gas distribution operations defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred natural gas costs are reflected as regulatory assets and accrued natural gas costs are reflected as regulatory liabilities. Therefore, gas costs recovered through natural gas revenues generally equal

II-176

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. Cost of natural gas at gas distribution operations represented 83.2% of the total cost of natural gas for 2018.

For the successor year ended December 31, 2018, cost of natural gas was $1.5 billion, a decrease of $62 million, or 3.9%, compared to 2017 substantially all as a result of the Southern Company Gas Dispositions.

For the successor year ended December 31, 2017, cost of natural gas was $1.6 billion, which reflected an increase in natural gas pricing of 26.3% compared to 2016, partially offset by lower demand for natural gas.

For the successor period of July 1, 2016 through December 31, 2016 and the predecessor period of January 1, 2016 through June 30, 2016, cost of natural gas was $613 million and $755 million, respectively, which reflected low demand for natural gas driven by warm weather during those periods.

Volumes of Natural Gas Sold

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



	Year Ended December 31,			2018 vs. 2017		2017 vs. 2016
	2018	2017	2016	% Change		% Change
Gas distribution operations (mmBtu in millions)
Firm	721	667	670	8.1	%	(0.4	)%
Interruptible	95	95	96	—	%	(1.0	)%
Total	816	762	766	7.1	%	(0.5	)%
Wholesale gas services (mmBtu in millions/day)
Daily physical sales	6.7	6.4	7.4	4.7	%	(13.5	)%
Gas marketing services (mmBtu in millions)
Firm:
Georgia	37	32	34	15.6	%	(5.9	)%
Illinois	13	12	12	8.3	%	—	%
Other	20	18	12	11.1	%	50.0	%
Interruptible large commercial and industrial	14	14	14	—	%	—	%
Total	84	76	72	10.5	%	5.6	%

Cost of Other Sales

Cost of other sales related to Pivotal Home Solutions, which was sold on June 4, 2018. See Note 15 to the financial statements under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

Other Operations and Maintenance Expenses

For the successor year ended December 31, 2018, other operations and maintenance expenses increased $36 million, or 3.8%, compared to the prior year. Excluding a $39 million decrease related to the Southern Company Gas Dispositions, other operations and maintenance expenses increased $75 million. This increase was primarily due to a $53 million increase in compensation and benefit costs, including a $12 million one-time increase for the adoption of a new paid time off policy to align with the Southern Company system, a $28 million increase in disposition-related costs, and an $11 million expense for a litigation settlement to facilitate the sale of Pivotal Home Solutions. These increases were partially offset by a $27 million decrease in bad debt expense primarily at Nicor Gas, which was offset by a decrease in revenues as a result of the related regulatory recovery mechanism. See Note 3 to the financial statements under "General Litigation Matters – Southern Company Gas" for additional information on the litigation settlement.

For the successor year ended December 31, 2017 and the successor period of July 1, 2016 through December 31, 2016, other operations and maintenance expenses were $945 million and $480 million, respectively, and primarily reflected compensation and benefit costs and professional services, including pipeline compliance and maintenance and legal services.

II-177

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

For the predecessor period of January 1, 2016 through June 30, 2016, other operations and maintenance expenses were $452 million and included pipeline compliance and maintenance costs and compensation and benefit costs.

Depreciation and Amortization

For the successor year ended December 31, 2018, depreciation and amortization decreased $1 million, or 0.2%, compared to the prior year. Excluding a $37 million decrease related to the Southern Company Gas Dispositions, depreciation and amortization increased $36 million. This increase was primarily due to continued infrastructure investments at gas distribution operations, partially offset by lower amortization of intangible assets as a result of fair value adjustments in acquisition accounting at gas marketing services.

For the successor year ended December 31, 2017, depreciation and amortization was $501 million and included $38 million of additional amortization of intangible assets as a result of fair value adjustments in acquisition accounting, primarily at gas marketing services, and $28 million in additional depreciation at gas distribution operations, primarily due to continued investment in infrastructure programs.

For the successor period of July 1, 2016 through December 31, 2016, depreciation and amortization was $238 million and included $23 million of additional amortization of intangible assets as a result of fair value adjustments in acquisition accounting, primarily at gas marketing services, as well as depreciation at gas distribution operations due to continued investment in infrastructure programs.

For the predecessor period of January 1, 2016 through June 30, 2016, depreciation and amortization was $206 million and reflected depreciation related to additional assets placed in service at gas distribution operations due to continued investment in infrastructure programs.

See Notes 2 and 15 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" and "Southern Company Merger with Southern Company Gas," respectively, for additional information on infrastructure programs and the application of acquisition accounting.

Taxes Other Than Income Taxes

For the successor year ended December 31, 2018, taxes other than income taxes increased $27 million, or 14.7%, compared to the prior year. Excluding a $4 million decrease related to the Southern Company Gas Dispositions, taxes other than income taxes increased $31 million. This increase primarily reflects a $13 million increase in revenue tax expenses as a result of higher natural gas revenues, a $12 million increase in Nicor Gas' invested capital tax that reflects a $7 million credit in 2017 to establish a related regulatory asset, and a $4 million increase in property taxes.

For the successor year ended December 31, 2017, the successor period of July 1, 2016 through December 31, 2016, and the predecessor period of January 1, 2016 through June 30, 2016, taxes other than income taxes were $184 million, $71 million, and $99 million, respectively, which consisted primarily of revenue tax expenses, property taxes, and payroll taxes.

Goodwill Impairment

For the successor year ended December 31, 2018, a goodwill impairment charge of $42 million was recorded in contemplation of the sale of Pivotal Home Solutions. See Notes 1 and 15 to the financial statements under "Goodwill and Other Intangible Assets and Liabilities" and "Southern Company Gas – Sale of Pivotal Home Solutions," respectively, for additional information.

Gain on Dispositions, Net

For the successor year ended December 31, 2018, gain on dispositions, net was $291 million and was associated with the Southern Company Gas Dispositions. The income tax expense on these gains included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously.

Merger-Related Expenses

There were no Merger-related expenses in the successor years ended December 31, 2018 and 2017.

For the successor period of July 1, 2016 through December 31, 2016, Merger-related expenses were $41 million, including $18 million in rate credits provided to the customers of Elizabethtown Gas and Elkton Gas as conditions of the Merger, $20 million for additional compensation-related expenses, and $3 million for financial advisory fees, legal expenses, and other Merger-related costs.

II-178

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

For the predecessor period of January 1, 2016 through June 30, 2016, Merger-related expenses were $56 million, including $31 million for financial advisory fees, legal expenses, and other Merger-related costs, and $25 million for additional compensation-related expenses.

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

Earnings from Equity Method Investments

For the successor year ended December 31, 2018, earnings from equity method investments increased $42 million, or 39.6%, compared to the prior year. The increase was primarily due to higher earnings from Southern Company Gas' equity method investment in SNG from new rates effective September 2018 and lower operations and maintenance expenses due to the timing of pipeline maintenance.

For the successor year ended December 31, 2017, earnings from equity method investments were $106 million, reflecting $88 million in earnings from Southern Company Gas' investment in SNG, including $33 million related to a non-cash charge recorded by SNG to establish a regulatory liability associated with the Tax Reform Legislation, and $18 million in earnings from all other investments.

For the successor period of July 1, 2016 through December 31, 2016, earnings from equity method investments were $60 million, reflecting $56 million in earnings from Southern Company Gas' investment in SNG and $4 million in earnings from all other investments.

For the predecessor period of January 1, 2016 through June 30, 2016, earnings from equity method investments were not material.

See Notes 7 and 15 to the financial statements under "Southern Company Gas – Equity Method Investments – SNG" and "Southern Company Gas – Investment in SNG," respectively, for additional information on Southern Company Gas' investment in SNG.

Interest Expense, Net of Amounts Capitalized

For the successor year ended December 31, 2018, interest expense, net of amounts capitalized increased $28 million, or 14.0%, compared to the prior year. The increase was primarily due to $21 million of additional interest expense related to new debt issuances and a $4 million reduction in capitalized interest primarily due to the Dalton Pipeline being placed in service in August 2017.

For the successor year ended December 31, 2017, interest expense, net of amounts capitalized was $200 million, which includes the $38 million fair value adjustment on long-term debt in acquisition accounting. Interest expense also reflects debt issuances and redemptions during the period and the recognition of previously deferred interest related to regulatory infrastructure programs.

For the successor period of July 1, 2016 through December 31, 2016, interest expense, net of amounts capitalized was $81 million, which includes the $19 million fair value adjustment on long-term debt in acquisition accounting. Interest expense also reflects debt issuances and redemptions during the period and the recognition of previously deferred interest related to regulatory infrastructure programs.

For the predecessor period of January 1, 2016 through June 30, 2016, interest expense, net of amounts capitalized was $96 million, reflecting debt issuances and redemptions during the period and the recognition of previously deferred interest related to regulatory infrastructure programs.

See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Unrecognized Ratemaking Amounts" herein for additional information on the unrecognized costs related to the infrastructure programs. Also see FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein and Note 8 to the financial statements for additional information on outstanding debt.

Other Income (Expense), Net

For the successor year ended December 31, 2018, other income (expense), net decreased $43 million, or 97.7%, compared to the prior year. Excluding a $3 million decrease related to the Southern Company Gas Dispositions, other income (expense), net decreased $40 million. This decrease was primarily due to a $23 million increase in charitable donations and a $13 million decrease in gains from the settlement of contractor litigation claims.

For the successor year ended December 31, 2017, other income (expense), net was $44 million and primarily related to a $20 million gain from the settlement of contractor litigation claims, $8 million of AFUDC, a $6 million tax gross-up on contributions

II-179

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

in aid of construction, and $4 million of interest income. See Note 2 to the financial statements under "Southern Company Gas – PRP Settlement" for additional information on contractor litigation claims.

For the successor period of July 1, 2016 through December 31, 2016, other income (expense), net was $12 million and primarily related to the tax gross-up of contributions in aid of construction received from customers.

For the predecessor period of January 1, 2016 through June 30, 2016, other income (expense), net was not material.

Income Taxes

For the successor year ended December 31, 2018, income taxes increased $97 million, or 26.4%, compared to the prior year. Excluding a $329 million increase related to the Southern Company Gas Dispositions, including tax expense on the goodwill for which a deferred tax liability had not been previously provided, income taxes decreased $232 million. This decrease was primarily due to a lower federal income tax rate and the flowback of excess deferred taxes as a result of the Tax Reform Legislation. In addition, 2017 included additional tax expense of $130 million from the revaluation of deferred tax assets associated with the Tax Reform Legislation, the enactment of the State of Illinois income tax legislation, and new income tax apportionment factors in several states.

For the successor year ended December 31, 2017, income taxes were $367 million. The effective tax rate in 2017 reflects additional expense from the revaluation of deferred tax assets of $93 million associated with the Tax Reform Legislation and $37 million associated with State of Illinois income tax legislation enacted in the third quarter 2017 and new income tax apportionment factors in several states resulting from Southern Company Gas' inclusion in the consolidated Southern Company state tax filings.

For the successor period of July 1, 2016 through December 31, 2016 and the predecessor period of January 1, 2016 through June 30, 2016, income taxes were $76 million and $87 million, respectively. The effective tax rates during these periods reflect certain nondeductible Merger-related expenses.

See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" herein and Note 10 to the financial statements for additional information.

Effects of Inflation

Southern Company Gas is subject to rate regulation that is generally based on the recovery of historical and projected costs. The effects of inflation can create an economic loss since the recovery of costs could be in dollars that have less purchasing power. Any adverse effect of inflation on Southern Company Gas' results of operations has not been substantial in recent years.

Performance and Non-GAAP Measures

Prior to the Merger, Southern Company Gas evaluated segment performance using EBIT, which includes operating income, earnings from equity method investments, and other income (expense), net. EBIT excludes interest expense, net of amounts capitalized and income taxes (benefit), which were evaluated on a consolidated basis for those periods. EBIT is used herein to discuss the results of Southern Company Gas' segments for the predecessor period as EBIT was the primary measure of segment profit or loss for that period. Subsequent to the Merger, Southern Company Gas changed its segment performance measure from EBIT to net income to better align with the performance measure utilized by Southern Company. EBIT for the successor periods presented herein is considered a non-GAAP measure. Southern Company Gas presents consolidated EBIT, which is considered a non-GAAP measure for all periods presented. The presentation of consolidated EBIT is believed to provide useful supplemental information regarding a consolidated measure of profit or loss. Southern Company Gas further believes the presentation of segment EBIT for the successor periods is useful as it allows for a measure of comparability to other companies with different capital and legal structures, which accordingly may be subject to different interest rates and effective tax rates. The applicable reconciliations of net income to consolidated EBIT and segment EBIT are provided herein.

Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues less cost of natural gas, cost of other sales, and revenue tax expense. Adjusted operating margin excludes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, goodwill impairment, gain on dispositions, net, and Merger-related expenses, which are included in the calculation of operating income as calculated in accordance with GAAP and reflected in the statements of income. The presentation of adjusted operating margin is believed to provide useful information regarding the contribution resulting from base rate changes, infrastructure replacement programs and capital projects, and customer growth at gas distribution operations since the cost of natural gas and revenue tax expense can vary significantly and are generally billed directly to customers. Southern Company Gas further believes that utilizing adjusted operating margin at gas pipeline investments, wholesale gas services, and gas marketing services allows it to focus on a direct measure of performance before overhead costs. The applicable reconciliation of operating income to adjusted operating margin is provided herein.

II-180

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

EBIT and adjusted operating margin should not be considered alternatives to, or more meaningful indicators of, Southern Company Gas' operating performance than net income attributable to Southern Company Gas or operating income as determined in accordance with GAAP. In addition, Southern Company Gas' adjusted operating margin may not be comparable to similarly titled measures of other companies.

Detailed variance explanations of Southern Company Gas' financial performance are provided herein.

Reconciliations of operating income to adjusted operating margin and net income attributable to Southern Company Gas to EBIT are as follows:



	Successor									Predecessor
	Year Ended December 31,			Year Ended December 31,			July 1, 2016 through December 31,			January 1, 2016 through June 30,
	2018			2017			2016			2016
	(in millions)									(in millions)
Operating Income	$	915		$	660		$	199		$	323
Other operating expenses^(a)	1,443			1,630			830			813
Revenue taxes^(b)	(111		)	(98		)	(31		)	(56		)
Adjusted Operating Margin	$	2,247		$	2,192		$	998		$	1,080


(a)	Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, goodwill impairment, gain on dispositions, net, and Merger-related expenses.


(b)	Nicor Gas' revenue tax expenses, which are passed through directly to customers.



	Successor						Predecessor
	Year Ended December 31,		Year Ended December 31,		July 1, 2016 through December 31,		January 1, 2016 through June 30,
	2018		2017		2016		2016
	(in millions)						(in millions)
Net Income Attributable to Southern Company Gas	$	372	$	243	$	114	$	131
Net income attributable to noncontrolling interest	—		—		—		14
Income taxes	464		367		76		87
Interest expense, net of amounts capitalized	228		200		81		96
EBIT	$	1,064	$	810	$	271	$	328

II-181

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

Segment Information

Adjusted operating margin, operating expenses, and Southern Company Gas' primary performance metric for each segment are illustrated in the tables below.



	Successor
	Year ended December 31, 2018									Year ended December 31, 2017
	Adjusted Operating Margin^(a)			Operating Expenses^(a)(b)			Net Income (Loss)^(b)			Adjusted Operating Margin^(a)			Operating Expenses^(a)			Net Income (Loss)
	(in millions)									(in millions)
Gas distribution operations	$	1,794		$	890		$	334		$	1,834		$	1,189		$	353
Gas pipeline investments	32			12			103			17			7			(22		)
Wholesale gas services	134			64			38			5			56			(57		)
Gas marketing services	263			244			(40		)	313			200			84
All other	33			131			(63		)	35			92			(115		)
Intercompany eliminations	(9		)	(9		)	—			(12		)	(12		)	—
Consolidated	$	2,247		$	1,332		$	372		$	2,192		$	1,532		$	243


(a)	Adjusted operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers.


(b)	Operating expenses for gas distribution operations and gas marketing services include the gain on dispositions, net. Net income for gas distribution operations and gas marketing services includes the gain on dispositions, net and the associated income tax expense. See Note 15 to the financial statements under "Southern Company Gas" for additional information.



	Successor									Predecessor
	July 1, 2016 through December 31, 2016									January 1, 2016 through June 30, 2016
	Adjusted Operating Margin^(*)			Operating Expenses^(*)			Net Income (Loss)			Adjusted Operating Margin^(*)			Operating Expenses^(*)			EBIT
	(in millions)									(in millions)
Gas distribution operations	$	817		$	592		$	77		$	911		$	558		$	353
Gas pipeline investments	3			2			29			3			—			3
Wholesale gas services	24			26			—			(36		)	33			(68		)
Gas marketing services	139			112			19			190			81			109
All other	19			71			(11		)	16			89			(69		)
Intercompany eliminations	(4		)	(4		)	—			(4		)	(4		)	—
Consolidated	$	998		$	799		$	114		$	1,080		$	757		$	328


(*)	Adjusted operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers.

Gas Distribution Operations

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

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

II-182

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy. See Note 15 to the financial statements under "Southern Company Gas" for additional information.

2018 vs. 2017

Net income decreased $19 million, or 5.4%, compared to the prior year, which includes a $40 million decrease in adjusted operating margin, a $299 million decrease in operating expenses, and a $22 million decrease in other income (expense), net resulting in a $237 million increase in EBIT. The decrease in net income also includes a $25 million increase in interest expense, net of amounts capitalized and a $231 million increase in income tax expense.

Excluding a $90 million decrease attributable to the utilities sold during 2018, adjusted operating margin increased $50 million, which primarily reflects additional revenue from infrastructure investments and colder weather in 2018, partially offset by lower rates and revenue deferrals for regulatory liabilities associated with the Tax Reform Legislation impacts. Excluding a $391 million decrease attributable to the utilities sold during 2018 that includes the related gains on the sales, operating expenses increased $92 million. This increase reflects $40 million of additional depreciation primarily due to additional assets placed in service, $37 million of additional other operations and maintenance expenses primarily due to increased compensation and benefit costs, partially offset by a decrease in bad debt expense, and $15 million of additional taxes other than income taxes primarily due to a $12 million increase in Nicor Gas' invested capital tax. Excluding a $3 million decrease attributable to the utilities sold during 2018, other income (expense), net decreased $20 million, which primarily reflects a $13 million decrease in gains from the settlement of contractor litigation claims. The increase in interest expense reflects $14 million of additional interest expense primarily from the issuance of first mortgage bonds at Nicor Gas. Excluding a $290 million decrease attributable to the utilities sold in 2018, income tax expense decreased $59 million, primarily due to lower pretax earnings, a lower federal income tax rate, and the flowback of excess deferred taxes as a result of the Tax Reform Legislation.

Successor Year Ended December 31, 2017

Net income of $353 million includes $1.8 billion in adjusted operating margin, $1.2 billion in operating expenses, and $39 million in other income (expense), net, which resulted in EBIT of $684 million. Net income also includes $153 million in interest expense, net of amounts capitalized and $178 million in income tax expense. Adjusted operating margin reflects $99 million in additional revenue from continued investment in infrastructure replacement programs and base rate increases at Atlanta Gas Light, Elizabethtown Gas, and Virginia Natural Gas. Adjusted operating margin was also affected by increased customer growth, partially offset by the negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect a $28 million increase in depreciation associated with additional assets placed in service, as well as benefit and compensation costs, legal expenses, and pipeline compliance and maintenance expenses. Other income (expense), net reflects a $20 million gain from the settlement of contractor litigation claims. Interest expense reflects the impact of intercompany promissory notes executed in December 2016 and the issuance of first mortgage bonds at Nicor Gas in August 2017 and November 2017. Income tax expense includes a $22 million benefit as a result of the Tax Reform Legislation.

See Note 2 to the financial statements under "Southern Company Gas – PRP Settlement" for additional information on contractor litigation claims. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein and Note 8 to the financial statements for additional information on debt issuances. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" herein and Note 10 to the financial statements for additional information.

Successor Period of July 1, 2016 through December 31, 2016

Net income of $77 million includes $817 million in adjusted operating margin, $592 million in operating expenses, and $8 million in other income (expense), net, resulting in EBIT of $233 million. Net income also includes $105 million in interest expense, net of amounts capitalized and $51 million in income tax expense. Adjusted operating margin reflects revenue from continued investment in infrastructure replacement programs, partially offset by the impact of warm weather, net of hedging. Operating expenses reflect the depreciation associated with additional assets placed in service, the related expenses associated with pipeline compliance and maintenance activities, and $18 million of rate credits provided to the customers of Elizabethtown Gas and Elkton Gas as conditions of the Merger. See Note 15 to the financial statements under "Southern Company Merger with Southern Company Gas" for additional information.

II-183

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

Predecessor Period of January 1, 2016 through June 30, 2016

EBIT of $353 million includes $911 million in adjusted operating margin and $558 million in operating expense. Adjusted operating margin reflects increased revenue from continued investment in infrastructure replacement programs and the impact of customer usage and growth, partially offset by the impact of warm weather, net of hedging. Operating expenses reflect the depreciation associated with additional assets placed in service.

Gas Pipeline Investments

Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including SNG, Atlantic Coast Pipeline, PennEast Pipeline, and Dalton Pipeline. See Note 7 to the financial statements under "Southern Company Gas" for additional information.

2018 vs. 2017

Net income increased $125 million compared to the prior year, which includes a $15 million increase in adjusted operating margin primarily due to the Dalton Pipeline being placed in service in August 2017, a $5 million increase in operating expenses primarily due to increased depreciation and property tax expense related to the Dalton Pipeline, and a $42 million increase in earnings from equity method investments primarily at SNG, resulting in a $52 million increase in EBIT. The increase in net income also includes an $8 million increase in interest expense, net of amounts capitalized primarily due to a reduction in capitalized interest after the Dalton Pipeline was placed in service and an $81 million decrease in income tax expense primarily due to a lower federal income tax rate in 2018 and additional tax expense recorded in 2017 associated with the Tax Reform Legislation, partially offset by higher pretax earnings.

Successor Year Ended December 31, 2017

Net loss of $22 million includes $17 million in adjusted operating margin, $7 million in operating expenses, and $103 million in earnings from equity method investments, consisting primarily of Southern Company Gas' equity interest in SNG, including $33 million related to a non-cash charge recorded by SNG to establish a regulatory liability associated with the Tax Reform Legislation, which resulted in EBIT of $113 million. Also included in net income are $26 million in interest expense, net of amounts capitalized and $109 million in income tax expense. Income tax expense includes $66 million resulting from the revaluation of deferred income tax assets associated with the Tax Reform Legislation and $7 million related to the allocation of new income tax apportionment factors in several states resulting from Southern Company Gas' inclusion in the consolidated Southern Company state tax filings. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" herein and Note 10 to the financial statements for additional information.

Successor Period of July 1, 2016 through December 31, 2016

Net income of $29 million includes $3 million in adjusted operating margin, $2 million in operating expenses, and $59 million in earnings from equity method investments, consisting primarily of Southern Company Gas' 2016 acquired equity interest in SNG, resulting in EBIT of $60 million. Also included in net income are $10 million in interest expense, net of amounts capitalized and $21 million in income tax expense.

Predecessor Period of January 1, 2016 through June 30, 2016

Earnings before interest and taxes for the predecessor period of January 1, 2016 through June 30, 2016 was $3 million.

Wholesale Gas Services

Wholesale gas services is involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services, and wholesale gas marketing. Southern Company Gas has positioned the business to generate positive economic earnings on an annual basis even under low volatility market conditions that can result from a number of factors. When market price volatility increases, wholesale gas services is well positioned to capture significant value and generate stronger results. Operating expenses primarily reflect employee compensation and benefits.

2018 vs. 2017

Net income increased $95 million, or 166.7%, compared to the prior year, which includes a $129 million increase in adjusted operating margin, an $8 million increase in operating expenses, a $1 million increase in interest income, and a $21 million decrease in other income (expense), net resulting in a $101 million increase in EBIT. The increase in net income also includes a $2 million increase in interest expense, net of amounts capitalized and a $4 million increase in income tax expense. Details of the increase in adjusted operating margin are provided in the table below. The increase in operating expenses primarily reflects higher

II-184

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

compensation and benefit expense. The decrease in other income (expense), net primarily reflects increased charitable donations. The increase in income tax expense reflects higher pretax earnings, partially offset by a lower federal income tax rate.

Successor Year Ended December 31, 2017

Net loss of $57 million includes $5 million in adjusted operating margin, $56 million in operating expenses, and $1 million in other income (expense), net, which resulted in a loss before interest and taxes of $50 million. Also included are $7 million in interest expense, net of amounts capitalized. Adjusted operating margin reflects a decrease of $21 million due to fair value adjustments to certain assets and liabilities in the application of acquisition accounting. Also reflected in adjusted operating margin is revenue from commercial activity partially offset by mark-to-market losses. Income tax expense includes $21 million resulting from the revaluation of deferred income tax assets associated with the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" herein and Note 10 to the financial statements for additional information.

Successor Period of July 1, 2016 through December 31, 2016

Net income includes $24 million in adjusted operating margin, $26 million in operating expenses, and $2 million in other income (expense), net, resulting in no EBIT. Also included are $3 million in interest expense, net of amounts capitalized and $3 million in income tax benefit. Adjusted operating margin reflects a decrease of $5 million due to fair value adjustments to certain assets and liabilities in the application of acquisition accounting. Also reflected in adjusted operating margin are mark-to-market gains due to changes in natural gas prices in the fourth quarter 2016 and losses from commercial activity due to low volatility in natural gas prices and warm weather. Operating expenses reflect low incentive compensation expense due to low earnings.

Predecessor Period of January 1, 2016 through June 30, 2016

Loss before interest and taxes of $68 million includes $(36) million in adjusted operating margin, $33 million in operating expense, and $1 million in other income (expense), net. Adjusted operating margin reflects mark-to-market losses and LOCOM adjustments as a result of changes in natural gas prices and revenues from commercial activity driven by changes in price volatility. Operating expenses reflect lower incentive compensation expense as compared to the same period in the prior year due to lower earnings.

The following table illustrates the components of wholesale gas services' adjusted operating margin for the periods presented:



	Successor									Predecessor
	Year Ended December 31,			Year Ended December 31,			July 1, 2016 through December 31,			January 1, 2016 through June 30,
	2018			2017			2016			2016
	(in millions)									(in millions)
Commercial activity recognized	$	254		$	116		$	(15	)	$	34
Gain (loss) on storage derivatives	9			23			(20		)	(38		)
Gain (loss) on transportation and forward commodity derivatives	(119		)	(113		)	64			(31		)
LOCOM adjustments, net of current period recoveries	(7		)	—			—			(1		)
Purchase accounting adjustments to fair value inventory and contracts	(3		)	(21		)	(5		)	—
Adjusted operating margin	$	134		$	5		$	24		$	(36	)

Change in Commercial Activity

The commercial activity at wholesale gas services includes recognition of storage and transportation values that were generated in prior periods, which reflect the impact of prior period hedge gains and losses as associated physical transactions occur. The increase in commercial activity in 2018 compared to the prior year was primarily due to natural gas price volatility that was generated by favorable weather and a corresponding increase in power generation volumes coupled with decreased natural gas supply.

Change in Storage and Transportation Derivatives

Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the U.S. The volatility of natural gas commodity prices has a significant impact on Southern Company Gas' customer rates, long-term competitive position against other energy sources, and the ability of wholesale gas

II-185

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

services to capture value from locational and seasonal spreads. Forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions in 2018 resulted in storage derivative gains. Transportation and forward commodity losses in 2018 are primarily the result of widening transportation spreads due to favorable weather, which impacted forward prices at natural gas receipt and delivery points primarily in the Northeast and Midwest regions.

The natural gas that Southern Company Gas purchases and injects into storage is accounted for at the LOCOM value utilizing gas daily or spot prices at the end of the year. A LOCOM adjustment, net of current period recoveries of $7 million, was recorded during 2018 and LOCOM adjustments for all other periods presented were immaterial. See Note 1 to the financial statements under "Natural Gas for Sale" for additional information.

Withdrawal Schedule and Physical Transportation Transactions

The expected natural gas withdrawals from storage and expected offset to prior hedge losses/gains associated with the transportation portfolio of wholesale gas services are presented in the following table, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Wholesale gas services' expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt, and delivery charges, and exclude estimated profit sharing under asset management agreements. Further, the amounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and delivery points, and forward natural gas prices at December 31, 2018. A portion of wholesale gas services' storage inventory and transportation capacity is economically hedged with futures contracts, which results in the realization of substantially fixed net operating revenues.



	Storage Withdrawal
	Total storage^(a)	Expected net operating losses^(b)			Physical Transportation Transactions – Expected Net Operating Gains^(c)
	(in mmBtu in millions)	(in millions)			(in millions)
2019	48	$	(8	)	$	12
2020 and thereafter	—	—			107
Total at December 31, 2018	48	$	(8	)	$	119


(a)	At December 31, 2018, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $2.90 per mmBtu.


(b)	Represents expected operating losses from planned storage withdrawals associated with existing inventory positions and could change as wholesale gas services adjusts its daily injection and withdrawal plans in response to changes in future market conditions and forward NYMEX price fluctuations.


(c)	Represents the periods associated with the transportation derivative net gains during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative gains and losses that were previously recognized.

Gas Marketing Services

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

On June 4, 2018, Southern Company Gas completed the sale of Pivotal Home Solutions to American Water Enterprises LLC. See Note 15 under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

2018 vs. 2017

Net income decreased $124 million, or 147.6%, compared to the prior year, which includes a $50 million decrease in adjusted operating margin, a $44 million increase in operating expenses, and a $1 million increase in other income (expense), net resulting in a $93 million decrease in EBIT. The decrease in net income also includes a $1 million increase in interest expense, net of amounts capitalized and a $30 million increase in income tax expense.

Excluding a $57 million decrease attributable to Pivotal Home Solutions, adjusted operating margin increased $7 million, which primarily reflects colder weather in 2018, customer growth, and favorable retail price spreads. Excluding a $42 million increase attributable to Pivotal Home Solutions that includes the loss on disposition and the goodwill impairment charge, operating expense increased $2 million. Excluding a $39 million increase attributable to Pivotal Home Solutions, income tax expense decreased $9 million driven by a lower federal income tax rate, partially offset by higher pretax earnings.

II-186

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

Successor Year Ended December 31, 2017

Net income of $84 million includes $313 million in adjusted operating margin and $200 million in operating expenses, which resulted in EBIT of $113 million. Net income also includes $5 million in interest expense, net of amounts capitalized and $24 million in income tax expense. Adjusted operating margin reflects a $9 million negative impact of warmer-than-normal weather, net of hedging, and $4 million in unrealized hedge losses, net of recoveries. Operating expenses includes $40 million in additional amortization of intangible assets established in the application of acquisition accounting. Income tax expense includes a $19 million benefit as a result of the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" herein and Note 10 to the financial statements for additional information.

Successor Period of July 1, 2016 through December 31, 2016

Net income of $19 million includes $139 million in adjusted operating margin and $112 million in operating expenses, resulting in EBIT of $27 million Net income also includes $1 million in interest expense, net of amounts capitalized and $7 million in income tax expense. Adjusted operating margin reflects a reduction of $5 million due to fair value adjustments to certain assets and liabilities in the application of acquisition accounting. Also reflected in adjusted operating margin are unrealized hedge gains and LOCOM adjustments. Operating expenses reflect $23 million in additional amortization of intangible assets, partially offset by a $2 million reduction in operations and maintenance expenses due to fair value adjustments to certain assets and liabilities in the application of acquisition accounting. See Note 1 to the financial statements under "Natural Gas for Sale" for additional information on LOCOM adjustments and Note 15 to the financial statements under "Southern Company Merger with Southern Company Gas" for additional information on the Merger.

Predecessor Period of January 1, 2016 through June 30, 2016

EBIT of $109 million includes $190 million in adjusted operating margin and $81 million in operating expenses. Adjusted operating margin reflects $9 million in unrealized hedge gains. Operating expenses reflect lower bad debt, marketing, and depreciation and amortization, compared to the same period in the prior year. Earnings also include $14 million attributable to noncontrolling interest.

All Other

All other includes Southern Company Gas' storage and fuels operations and its investment in Triton, AGL Services Company, and Southern Company Gas Capital, as well as various corporate operating expenses that are not allocated to the reportable segments and interest income (expense) associated with affiliate financing arrangements.

2018 vs. 2017

Net loss decreased $52 million, or 45.2%, compared to the prior year, which includes a $2 million decrease in adjusted operating margin, a $39 million increase in operating expenses, a $3 million increase in interest income, and a $5 million decrease in other income (expense), net resulting in a $43 million decrease in EBIT. The decrease in net loss also includes an $8 million decrease in interest expense, net of amounts capitalized and an $87 million decrease in income tax expense. The increase in operating expenses primarily reflects a $28 million increase in disposition-related costs and a $12 million increase in compensation expenses resulting from the adoption of a new paid time off policy. The decrease in income tax expense primarily reflects the 2017 increase in income tax expense related to the revaluation of deferred tax assets associated with the Tax Reform Legislation, the enactment of the State of Illinois income tax legislation, new income tax apportionment factors in several states, and a lower federal income tax rate in 2018. The decrease also reflects lower pretax earnings in 2018 compared to 2017.

Successor Year Ended December 31, 2017

Net loss of $115 million includes $35 million in adjusted operating margin and $92 million in operating expenses. Operating expenses included $26 million of integration-related costs. Interest expense, net of amounts capitalized was $9 million due to intercompany promissory notes that were executed in December 2016. Income tax expense was $56 million and includes $46 million resulting from the revaluation of deferred tax assets associated with the Tax Reform Legislation and $30 million associated with State of Illinois tax legislation enacted during the third quarter 2017 and new income tax apportionment factors in several states resulting from Southern Company Gas' inclusion in the consolidated Southern Company state tax filings, partially offset by income tax benefit on the pre-tax loss. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein for additional financing information and FUTURE EARNINGS POTENTIAL – "Income Tax Matters" herein and Note 10 to the financial statements for additional information.

II-187

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

Successor Period of July 1, 2016 through December 31, 2016

Operating expenses included Merger-related expenses of $41 million primarily comprised of compensation-related expenses, financial advisory fees, legal expenses, and other Merger-related costs and $8 million in expenses associated with certain benefit arrangements.

Predecessor Period of January 1, 2016 through June 30, 2016

For the predecessor period of January 1, 2016 through June 30, 2016, operating expenses included Merger-related expenses of $56 million. These expenses are primarily comprised of financial advisory and legal expenses as well as additional compensation-related expenses, including acceleration of share-based compensation expenses, and change-in-control compensation charges. See Note 15 to the financial statements under "Southern Company Merger with Southern Company Gas" for additional information.

Segment Reconciliations

Reconciliations of net income attributable to Southern Company Gas to EBIT for the years ended December 31, 2018 and 2017 and the period of July 1, 2016 through December 31, 2016, and operating income to adjusted operating margin for all periods presented, are in the following tables. See Note 16 to the financial statements under "Southern Company Gas" for additional segment information.



	Successor
	Year Ended December 31, 2018
	Gas Distribution Operations		Gas Pipeline Investments		Wholesale Gas Services		Gas Marketing Services			All Other			Intercompany Elimination		Consolidated
	(in millions)
Net Income (Loss) Attributable to Southern Company Gas	$	334	$	103	$	38	$	(40	)	$	(63	)	$	—	$	372
Income taxes (benefit)	409		28		4		54			(31		)	—		464
Interest expense, net of amounts capitalized	178		34		9		6			1			—		228
EBIT	$	921	$	165	$	51	$	20		$	(93	)	$	—	$	1,064



	Successor
	Year Ended December 31, 2017
	Gas Distribution Operations		Gas Pipeline Investments			Wholesale Gas Services			Gas Marketing Services		All Other			Intercompany Elimination		Consolidated
	(in millions)
Net Income (Loss) Attributable to Southern Company Gas	$	353	$	(22	)	$	(57	)	$	84	$	(115	)	$	—	$	243
Income taxes	178		109			—			24		56			—		367
Interest expense, net of amounts capitalized	153		26			7			5		9			—		200
EBIT	$	684	$	113		$	(50	)	$	113	$	(50	)	$	—	$	810

II-188

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report



	Successor
	July 1, 2016 through December 31, 2016
	Gas Distribution Operations		Gas Pipeline Investments		Wholesale Gas Services			Gas Marketing Services		All Other			Intercompany Elimination		Consolidated
	(in millions)
Net Income (Loss) Attributable to Southern Company Gas	$	77	$	29	$	—		$	19	$	(11	)	$	—	$	114
Income taxes (benefit)	51		21		(3		)	7		—			—		76
Interest expense, net of amounts capitalized	105		10		3			1		(38		)	—		81
EBIT	$	233	$	60	$	—		$	27	$	(49	)	$	—	$	271



	Successor
	Year Ended December 31, 2018
	Gas Distribution Operations			Gas Pipeline Investments		Wholesale Gas Services		Gas Marketing Services		All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	904		$	20	$	70	$	19	$	(98	)	$	—		$	915
Other operating expenses^(a)	1,001			12		64		244		131			(9		)	1,443
Revenue tax expense^(b)	(111		)	—		—		—		—			—			(111		)
Adjusted Operating Margin	$	1,794		$	32	$	134	$	263	$	33		$	(9	)	$	2,247



	Successor
	Year Ended December 31, 2017
	Gas Distribution Operations			Gas Pipeline Investments		Wholesale Gas Services			Gas Marketing Services		All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	645		$	10	$	(51	)	$	113	$	(57	)	$	—		$	660
Other operating expenses^(a)	1,287			7		56			200		92			(12		)	1,630
Revenue tax expense^(b)	(98		)	—		—			—		—			—			(98		)
Adjusted Operating Margin	$	1,834		$	17	$	5		$	313	$	35		$	(12	)	$	2,192



	Successor
	July 1, 2016 through December 31, 2016
	Gas Distribution Operations			Gas Pipeline Investments		Wholesale Gas Services			Gas Marketing Services		All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	225		$	1	$	(2	)	$	27	$	(52	)	$	—		$	199
Other operating expenses^(a)	623			2		26			112		71			(4		)	830
Revenue tax expense^(b)	(31		)	—		—			—		—			—			(31		)
Adjusted Operating Margin	$	817		$	3	$	24		$	139	$	19		$	(4	)	$	998

II-189

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report



	Predecessor
	January 1, 2016 through June 30, 2016
	Gas Distribution Operations			Gas Pipeline Investments		Wholesale Gas Services			Gas Marketing Services		All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	353		$	3	$	(69	)	$	109	$	(73	)	$	—		$	323
Other operating expenses^(a)	614			—		33			81		89			(4		)	813
Revenue tax expense^(b)	(56		)	—		—			—		—			—			(56		)
Adjusted Operating Margin	$	911		$	3	$	(36	)	$	190	$	16		$	(4	)	$	1,080


(a)	Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, goodwill impairment, gain on dispositions, net, and Merger-related expenses.


(b)	Nicor Gas' revenue tax expenses, which are passed through directly to customers.

FUTURE EARNINGS POTENTIAL

General

The results of operations for the past three years are not necessarily indicative of future earnings potential. The Southern Company Gas Dispositions are expected to materially decrease future earnings and cash flows to Southern Company Gas. For the year ended December 31, 2018, pre-tax earnings attributable to these dispositions were $297 million, which includes a $291 million gain on dispositions, net and a $42 million goodwill impairment. For the year ended December 31, 2017, net income attributable to these dispositions was $71 million, which included additional tax expense of $16 million associated with the Tax Reform Legislation. Due to the seasonal nature of the natural gas business and other factors including, but not limited to, weather, regulation, competition, customer demand, and general economic conditions, these results are not necessarily indicative of the results to be expected for any other period. The level of Southern Company Gas' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Company Gas' primary business of natural gas distribution and its complementary businesses in the gas pipeline investments, wholesale gas services, and gas marketing services sectors. These factors include Southern Company Gas' ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs, the completion and subsequent operation of ongoing infrastructure and other construction projects, creditworthiness of customers, its ability to optimize its transportation and storage positions, and its ability to re-contract storage rates at favorable prices.

Future earnings will be driven by customer growth and are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of natural gas, the price elasticity of demand, and the rate of economic growth or decline in Southern Company Gas' service territories. Demand for natural gas is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.

Volatility of natural gas prices has a significant impact on Southern Company Gas' customer rates, its long-term competitive position against other energy sources, and the ability of its gas marketing services and wholesale gas services segments to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability. Over the longer term, volatility is expected to be low to moderate and locational and/or transportation spreads are expected to decrease as new pipelines are built to reduce the existing supply constraints in the shale areas of the Northeast U.S. To the extent these pipelines are delayed or not built, volatility could increase. See "FERC Matters" herein for additional information on permitting challenges experienced by the Atlantic Coast Pipeline. Additional economic factors may contribute to this environment, including a significant drop in oil and natural gas prices, which could lead to consolidation of natural gas producers or reduced levels of natural gas production. Further, if 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.

As part of its business strategy, Southern Company Gas regularly considers and evaluates joint development arrangements as well as acquisitions and dispositions of businesses and assets.


•	On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC. Southern Company Gas and American Water Enterprises LLC entered into a transition services

II-190

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

agreement whereby Southern Company Gas provided certain administrative and operational services through November 4, 2018.

•

On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. Southern Company Gas and South Jersey Industries, Inc. entered into transition services agreements whereby Southern Company Gas will provide certain administrative and operational services through no later than July 31, 2020.

•

On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy. Southern Company Gas and NextEra Energy entered into a transition services agreement whereby Southern Company Gas will provide certain administrative and operational services through no later than July 29, 2020.

See OVERVIEW – "Merger, Acquisition, and Disposition Activities" herein and Note 15 to the financial statements under "Southern Company Gas" for additional information on these dispositions. See BUSINESS – "Seasonality" in Item 1, RISK FACTORS in Item 1A, and OVERVIEW – "Seasonality of Results" for additional information on seasonality.

Environmental Matters

Southern Company Gas' operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Southern Company Gas maintains a comprehensive environmental compliance strategy to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations may impact future results of operations, cash flows, and financial condition. A major portion of these compliance costs are expected to be recovered through customer rates. The ultimate impact of the environmental laws and regulations discussed herein will depend on various factors, such as state adoption and implementation of requirements and the outcome of pending and/or future legal challenges.

New or revised environmental laws and regulations could affect many areas of Southern Company Gas' operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be recovered in rates on a timely basis. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for 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 for some may have the potential to ultimately affect their demand for natural gas.

Environmental Remediation

Southern Company Gas is subject to environmental remediation liabilities associated with 40 former MGP sites in four different states. Southern Company Gas conducts studies to determine the extent of any required cleanup and has recognized the costs to clean up known impacted sites in its financial statements. An accrued environmental remediation liability of $294 million was included in the balance sheets at December 31, 2018, of which $26 million is expected to be incurred over the next 12 months. The accrued environmental remediation liability decreased at December 31, 2018 primarily due to the disposition of $85 million that related to Elizabethtown Gas. The natural gas distribution utilities in Illinois and Georgia have received authority from their respective state regulators to recover approved environmental compliance costs through regulatory mechanisms, which covers substantially all of the total accrued remediation costs. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein and Note 3 to the financial statements under "Environmental Remediation" for additional information.

Water Quality

In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) jointly published a final rule that revised the regulatory definition of waters of the United States (WOTUS) for all Clean Water Act programs. The rule significantly expanded the scope of federal jurisdiction over waterbodies (such as rivers, streams, and canals), which could impact permitting and reporting requirements associated with the installation, expansion, and maintenance of pipeline projects. The EPA and the Corps are expected to publish a final rule in 2019 to replace the 2015 WOTUS definition. The impact of any changes to the 2015 WOTUS rule will depend on the content of this final rule and the outcome of any legal challenges.

Global Climate Issues

II-191

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

Company Gas' 2017 GHG emissions were approximately 0.6 million metric tons of CO₂ equivalent. The preliminary estimate of Southern Company Gas' 2018 GHG emissions on the same basis is approximately 0.6 million metric tons of CO₂ equivalent.

FERC Matters

Southern Company Gas is involved in two significant pipeline construction projects within gas pipeline investments. These projects, along with Southern Company Gas' existing pipelines, are intended to provide diverse sources of natural gas supplies to customers, resolve current and long-term supply planning for new capacity, enhance system reliability, and generate economic development in the areas served. The following table provides an overview of these pipeline projects.



	Miles of Pipe	Capital Expenditures^(a)		Ownership Percentage
		(in millions)
Atlantic Coast Pipeline^(b)	594	$	350-390	5	%
PennEast Pipeline^(c)	118	$	276	20	%


(a)	Represents Southern Company Gas' expected total capital expenditures, excluding AFUDC, at completion, which may change.

(b)

In 2014, Southern Company Gas entered into a joint venture to construct and operate a natural gas pipeline that will run from West Virginia through Virginia and into eastern North Carolina to meet the region's growing demand for natural gas. The proposed pipeline project is expected to transport natural gas to customers in Virginia. In August 2017, the Atlantic Coast Pipeline received FERC approval.

(c)

In 2014, Southern Company Gas entered into a joint venture to construct and operate a natural gas pipeline that will transport low-cost natural gas from the Marcellus Shale area to customers in New Jersey. Southern Company Gas believes this will alleviate takeaway constraints in the Marcellus region and help mitigate some of the price volatility experienced during recent winters. On January 19, 2018, the PennEast Pipeline received FERC approval.

In August 2017, the Dalton Pipeline, which serves as an extension of the Transco pipeline system and provides additional natural gas supply to customers in Georgia, was placed in service. Southern Company Gas has a 50% ownership interest in the Dalton Pipeline. See Note 5 to the financial statements under "Joint Ownership Agreements" for additional information.

On November 16, 2018, SNG completed its purchase of Georgia Power's natural gas lateral pipeline serving Plant McDonough Units 4 through 6 at net book value, as approved by the Georgia PSC on January 16, 2018. SNG expects to pay $142 million to Georgia Power in the first quarter 2020. During the interim period, Georgia Power will receive a discounted shipping rate to reflect the delayed consideration. Southern Company Gas' portion of the expected capital expenditures for the purchase of this pipeline and additional construction is $122 million.

Regulatory Matters

Utility Regulation and Rate Design

The natural gas distribution utilities are subject to regulations 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. Rate base generally consists of the original

II-192

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

cost of the utility plant in service, working capital, and certain other assets, less accumulated depreciation on the utility plant in service and net deferred income tax liabilities, and may include certain other additions or deductions.

The natural gas market for Atlanta Gas Light was deregulated in 1997. Accordingly, Marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. The Marketers file their rates monthly with the Georgia PSC. As a result of operating in a deregulated environment, Atlanta Gas Light's role includes:


•	distributing natural gas for Marketers;


•	constructing, operating, and maintaining the gas system infrastructure, including responding to customer service calls and leaks;


•	reading meters and maintaining underlying customer premise information for Marketers; and


•	planning and contracting for capacity on interstate transportation and storage systems.

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.

Georgia Rate Adjustment Mechanism (GRAM)

In February 2017, the Georgia PSC approved GRAM and a $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, using an earnings band based on the previously approved ROE of 10.75% and does not collect revenue through special riders and surcharges. Atlanta Gas Light adjusts rates up to the lower end of the band of 10.55% and adjusts rates down to the higher end of the band of 10.95%. Various infrastructure programs previously authorized by the Georgia PSC under Atlanta Gas Light's STRIDE program including the Integrated Vintage Plastic Replacement Program (i-VPR) to replace aging plastic pipe and the Integrated System Reinforcement Program (i-SRP) 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 Georgia PSC reviews Atlanta Gas Light's performance annually under GRAM. See "Rate Proceedings" herein for additional information.

Pursuant to the GRAM approval, Atlanta Gas Light and the staff of the Georgia PSC 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, which was formerly part of the STRIDE program. As a result, a new tariff was created, effective October 10, 2017, to provide up to $15 million annually for Atlanta Gas Light to commit to strategic economic development projects. Projects under this tariff must be approved by the Georgia PSC.

PRP

In 2015, Atlanta Gas Light began recovering incremental PRP surcharge amounts through three phased-in increases in addition to its already existing PRP surcharge amount, which was established to address recovery of the unrecovered PRP balance of $144 million and the estimated amounts to be earned under the program through 2025. The unrecovered balance is the result of the continued revenue requirement earned under the program offset by the existing and incremental PRP surcharges. The under recovered balance at December 31, 2018 was $171 million, including $95 million of unrecognized equity return. The PRP surcharge will remain in effect until the earlier of the full recovery of the under recovered amount or December 31, 2025. See "Rate Proceedings" and "Unrecognized Ratemaking Amounts" herein for additional information.

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 normalization mechanisms and weather derivative instruments, that limit exposure to weather changes within typical ranges in these utilities' respective service territories.

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. 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 specific to Georgia's deregulated market. In addition to natural gas recovery mechanisms, there are other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs as well as environmental remediation and

II-193

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

energy efficiency plans. 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 Nicor Gas, the 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. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company Gas' revenues or net income, but will affect cash flows. See Note 2 to the financial statements under "Southern Company Gas" for additional information.

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



	Nicor Gas	Atlanta Gas Light	Virginia Natural Gas	Chattanooga Gas
Authorized ROE^(a)(b)	9.80%	10.75%	9.50%	9.80%
Weather normalization mechanisms^(c)			ü	ü
Decoupled, including straight-fixed-variable rates^(d)		ü	ü
Regulatory infrastructure program rates^(e)(f)	ü		ü
Bad debt rider^(g)	ü		ü	ü
Energy efficiency plan^(h)	ü		ü
Year of last rate decision⁽ⁱ⁾	2018	2018	2018	2018


(a)	Represents the authorized ROE, or the midpoint of the authorized ROE range, at December 31, 2018.


(b)	The authorized ROE range for Atlanta Gas Light and Virginia Natural Gas was 10.55% - 10.95% and 9.00% - 10.00%, respectively, at December 31, 2018.

(c)

Regulatory mechanisms that allow 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. These mechanisms are designed to help stabilize operating results by increasing base rate amounts charged to customers when weather is warmer than normal and decreasing amounts charged when weather is colder than normal.


(d)	Recovery of fixed customer service costs separately from assumed natural gas volumes used by customers.


(e)	Programs that update or expand distribution systems and LNG facilities.


(f)	Recovery of program costs at Atlanta Gas Light was incorporated in GRAM, which the Georgia PSC approved in February 2017. See "Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light" herein for additional information.


(g)	The recovery (refund) of bad debt expense over (under) an established benchmark expense. Nicor Gas, Virginia Natural Gas, and Chattanooga Gas recover the gas portion of bad debt expense through their purchased gas adjustment mechanisms.


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


(i)	See "Rate Proceedings" herein and Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" for additional information.

Infrastructure Replacement Programs and Capital Projects

Southern Company Gas continues to focus on capital discipline and cost control while pursuing projects and initiatives that are expected to have current and future benefits to customers, provide an appropriate return on invested capital, and help ensure the safety and reliability of the utility infrastructure. In addition to capital expenditures recovered through base rates by each of the natural gas distribution utilities, Nicor Gas and Virginia Natural Gas have separate rate riders that provide timely recovery of capital expenditures for specific infrastructure replacement programs. Total capital expenditures incurred during 2018 for gas distribution operations were $1.4 billion, including $97 million related to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold in 2018.

The following table and discussions provide updates on the infrastructure replacement programs and capital projects at the natural gas distribution utilities at December 31, 2018. 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. The anticipated expenditures for these programs in 2019 are quantified in the discussion below.

II-194

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report



Utility	Program	Recovery	Expenditures in 2018		Expenditures Since Project Inception		Pipe Installed Since Project Inception	Scope of Program	Program Duration	Last Year of Program
			(in millions)				(miles)	(miles)	(years)
Nicor Gas	Investing in Illinois^(*)	Rider	$	409	$	1,316	706	1,500	9	2023
Virginia Natural Gas	Steps to Advance Virginia's Energy (SAVE and SAVE II)	Rider	40		196		287	496	10	2021
Total			$	449	$	1,512	993	1,996


(*)	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.

Nicor Gas

In 2013, Illinois enacted legislation that allows Nicor Gas to provide more widespread safety and reliability enhancements to its distribution system. The legislation 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. Nicor Gas expects to place into service $373 million of qualifying projects under Investing in Illinois in 2019.

In conjunction with the base rate case order issued by the Illinois Commission on January 31, 2018, Nicor Gas is recovering program costs incurred prior to December 31, 2017 through base rates. Nicor Gas has requested that the program costs incurred subsequent to December 31, 2017, which are currently being recovered through a separate rider, be addressed in the base rate case filed November 9, 2018. See "Rate Proceedings" herein for additional information.

Virginia Natural Gas

In 2012, the Virginia Commission approved the SAVE program, an accelerated infrastructure replacement program, to be completed over a five-year period. In 2016, the Virginia Commission approved an extension to the SAVE program for Virginia Natural Gas to replace more than 200 miles of aging pipeline infrastructure and invest up to $30 million in 2016 and up to $35 million annually through 2021. Virginia Natural Gas expects to invest $35 million under this program in 2019.

The SAVE program is subject to annual review by the Virginia Commission. In conjunction with the base rate case order issued by the Virginia Commission in December 2017, Virginia Natural Gas is recovering program costs incurred prior to September 1, 2017 through base rates. Program costs incurred subsequent to September 1, 2017 are currently recovered through a separate rider and are subject to future base rate case proceedings.

Atlanta Gas Light

As discussed previously under "Utility Regulation and Rate Design," i-SRP and i-VPR will continue under GRAM and the recovery of and return on current and future capital investments under the STRIDE program will be included in annual base rate adjustments.

The orders for the STRIDE program provide for recovery of all prudent costs incurred in the performance of the program. Atlanta Gas Light will recover from end-use customers, through billings to Marketers, the costs related to the program, net of any related cost savings. The regulatory asset represents incurred program costs that will be collected through GRAM. The future expected costs to be recovered through rates related to allowed, but not incurred, costs are recognized in an unrecognized ratemaking amount that is not reflected on the balance sheets. This allowed cost is primarily the equity return on the capital investment under the program. See "Unrecognized Ratemaking Amounts" herein for additional information.

Atlanta Gas Light capitalizes and depreciates the capital expenditure costs incurred from the STRIDE programs over the life of the assets. Operations and maintenance costs are expensed as incurred. Recoveries, which are recorded as revenue, are based on a formula that allows Atlanta Gas Light to recover operations and maintenance costs in excess of those included in its current base rates, depreciation, and an allowed rate of return on capital expenditures. However, Atlanta Gas Light is allowed the recovery of carrying costs on the under recovered balance resulting from the timing difference.

II-195

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

Rate Proceedings

Nicor Gas

On January 31, 2018, the Illinois Commission approved a $137 million increase in annual base rate revenues, including $93 million related to the recovery of investments under the Investing in Illinois program, effective February 8, 2018, based on a ROE of 9.8%.

On April 19, 2018, the Illinois Commission approved Nicor Gas' variable income tax adjustment rider. This rider provides for refund or recovery of changes in income tax expense that result from income tax rates that differ from those used in Nicor Gas' last rate case. Customer refunds, via bill credits, related to the impacts of the Tax Reform Legislation from January 25, 2018 through May 4, 2018 began on July 1, 2018 and are expected to conclude in the second quarter 2019.

On November 9, 2018, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $230 million increase in annual base rate revenues. The requested increase is based on a projected test year for the 12-month period ending September 30, 2020, a ROE of 10.6%, and an increase in the equity ratio from 52.0% to 54.0% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. The Illinois Commission is expected to rule on the requested increase within the 11-month statutory time limit, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.

Atlanta Gas Light

Atlanta Gas Light's recovery of the previously unrecovered PRP revenue through 2014, as well as the mitigation costs associated with the PRP that were not previously included in its rates, were included in GRAM. In connection with the GRAM approval, the last monthly PRP surcharge increase became effective March 1, 2017.

Virginia Natural Gas

On December 17, 2018, the Virginia Commission approved Virginia Natural Gas' annual information form filing, which reduced annual base rates by $14 million effective January 1, 2019 due to lower tax expense as a result of the lower corporate income tax rate and the impact of the flowback of excess deferred income taxes. This approval also requires Virginia Natural Gas to issue customer refunds, via bill credits, for the entire $14 million which was deferred as a regulatory liability, current, on the balance sheet at December 31, 2018. These customer refunds are expected to be completed in the first quarter 2019.

Affiliate Asset Management Agreements

With the exception of Nicor Gas, the natural gas distribution utilities use asset management agreements with an affiliate, Sequent, for the primary purpose of reducing utility customers' gas cost recovery rates through payments to the utilities by Sequent. For Atlanta Gas Light, these payments are controlled by the Georgia PSC and are utilized for infrastructure improvements and to fund heating assistance programs, rather than as a reduction to gas cost recovery rates. Under these asset management agreements, Sequent supplies natural gas to the utility and markets available pipeline and storage capacity to improve the overall cost of supplying gas to the utility customers. Currently, the natural gas distribution utilities primarily purchase their gas from Sequent. The purchase agreements require Sequent to provide firm gas to the natural gas distribution utilities, but these natural gas distribution utilities maintain the right and ability to make their own long-term supply arrangements if they believe it is in the best interest of their customers.

Upon closing the sales of Elizabethtown Gas and Elkton Gas, an affiliate of South Jersey Industries, Inc. assumed the asset management agreements with wholesale gas services for Elizabethtown Gas and Elkton Gas. The sale of Pivotal Utility Holdings to NextEra Energy did not impact the asset management agreement between Sequent and Florida City Gas, which will remain in

II-196

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

effect until March 31, 2019. See Note 15 to the financial statements under "Southern Company Gas " for additional information on these dispositions.

Each agreement provides for Sequent to make payments to the natural gas distribution utility through either an annual minimum guarantee within a profit sharing structure, a profit sharing structure without an annual minimum guarantee, or a fixed fee. From the inception of these agreements in 2001 through December 31, 2018, Sequent made sharing payments to the natural gas distribution utilities under these agreements totaling $425 million.

The following table provides payments made by Sequent to the remaining natural gas distribution utilities under these agreements during the last three years:



	Successor						Predecessor
	Year Ended December 31,		Year Ended December 31,		July 1, 2016 through December 31,		January 1, 2016 through June 30,
	2018		2017		2016		2016		Expiration Date
	(in millions)						(in millions)
Virginia Natural Gas	$	11	$	6	$	2	$	9	March 2019
Atlanta Gas Light	9		4		1		6		March 2020
Chattanooga Gas	1		1		—		1		March 2021
Total^(*)	$	21	$	11	$	3	$	16

(*)

Payments made to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold in July 2018, were $14 million and $12 million for the successor years ended December 31, 2018 and 2017, respectively, $3 million for the successor period of July 1, 2016 through December 31, 2016, and $13 million for the predecessor period of January 1, 2016 through June 30, 2016. See Note 15 to the financial statements under "Southern Company Gas" for additional information on these dispositions.

energySMART

The Illinois Commission approved Nicor Gas' energySMART program, which includes energy efficiency program offerings and therm reduction goals. Through December 31, 2017, Nicor Gas spent $107 million of the initial authorized expenditure of $113 million. A new program began on January 1, 2018, with an additional authorized expenditure of $160 million through 2021. Through December 31, 2018, Nicor Gas had spent $29 million.

Unrecognized Ratemaking Amounts

The following table illustrates Southern Company Gas' authorized ratemaking amounts that are not recognized on its balance sheets. These amounts are primarily composed of an allowed equity rate of return on assets associated with certain regulatory infrastructure programs. These amounts will be recognized as revenues in Southern Company Gas' financial statements in the periods they are billable to customers, the majority of which will be recovered by 2025.



	December 31, 2018		December 31, 2017
	(in millions)
Atlanta Gas Light	$	95	$	104
Virginia Natural Gas	11		11
Nicor Gas	4		2
Total	$	110	$	117

Income Tax Matters

Federal Tax Reform Legislation

In December 2017, the Tax Reform Legislation was signed into law and became effective on January 1, 2018. The Tax Reform Legislation, among other things, reduced the federal corporate income tax rate to 21%, retained normalization provisions for public utility property and existing renewable energy incentives, and repealed the corporate alternative minimum tax. In addition, under the Tax Reform Legislation, net operating losses (NOL) generated after December 31, 2017 can no longer be carried back to previous tax years but can be carried forward indefinitely, with utilization limited to 80% of taxable income of the subsequent tax year. The projected reduction of Southern Company's consolidated income tax liability resulting from the tax rate reduction

II-197

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

also delays the expected utilization of existing tax credit carryforwards. See Note 10 to the financial statements for information on Southern Company's joint consolidated income tax allocation agreement.

Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provided for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes and their application under GAAP, Southern Company Gas considered all amounts recorded in the financial statements as a result of the Tax Reform Legislation "provisional" as discussed in SAB 118 and subject to revision prior to filing its 2017 tax return in the fourth quarter 2018. Southern Company Gas recognized tax benefits of $3 million and tax expense of $93 million in 2018 and 2017, respectively, for a total net tax expense of $90 million as a result of the Tax Reform Legislation. In addition, in total, Southern Company Gas recorded a $781 million increase in regulatory liabilities as a result of the Tax Reform Legislation and $4 million of stranded excess deferred tax balances in AOCI at December 31, 2017 were adjusted through retained earnings in 2018. As of December 31, 2018, Southern Company Gas considered the measurement of impacts from the Tax Reform Legislation on deferred income tax assets and liabilities, primarily due to the impact of the reduction of the corporate income tax rate, to be complete.

However, the IRS continues to issue regulations that provide further interpretation and guidance on the law and each state's adoption of the provisions contained in the Tax Reform Legislation remains uncertain. In addition, the regulatory treatment of certain impacts of the Tax Reform Legislation is subject to the discretion of the FERC and the relevant state regulatory bodies. The ultimate impact of these matters cannot be determined at this time. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" for additional information on the natural gas distribution utilities' rate filings to reflect the impacts of the Tax Reform Legislation. Also see FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein and Note 10 to the financial statements under "Current and Deferred Income Taxes" for additional information.

Bonus Depreciation

Under the Tax Reform Legislation, projects with binding contracts prior to September 28, 2017 and placed in service after September 27, 2017 remain eligible for bonus depreciation under the PATH Act. The PATH Act allowed for 50% bonus depreciation for 2015 through 2017, 40% bonus depreciation for 2018, and 30% bonus depreciation for 2019 and certain long-lived assets placed in service in 2020. Based on provisional estimates, bonus depreciation is expected to result in positive cash flows of approximately $40 million for the 2018 tax year and approximately $20 million for the 2019 tax year. See Note 10 to the financial statements under "Current and Deferred Income Taxes" for additional information. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

Southern Company Gas is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the ordinary course of business.

Southern Company Gas is involved in litigation relating to an incident that occurred in one of its prior service territories that resulted in several deaths, injuries, and property damage. Southern Company Gas has resolved all claims for personal injuries or death, but it is continuing to defend litigation seeking to recover alleged property damages. Southern Company Gas has insurance that provides full coverage of the expected financial exposure in excess of $11 million per incident. During the successor period ended December 31, 2016, Southern Company Gas recorded reserves for substantially all of its potential exposure from these cases.

The ultimate outcome of this matter and such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings 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 would have a material effect on Southern Company Gas' financial statements. See Notes 2 and 3 to the financial statements for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

Southern Company Gas owns a 50% interest in a LNG liquefaction and storage facility in Jacksonville, Florida, which was placed in service in October 2018. The facility, outfitted with a 2.0 million gallon storage tank with the capacity to produce in excess of 120,000 gallons of LNG per day, is not expected to have a material impact on Southern Company Gas' 2019 financial statements.

II-198

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

Company Gas retiring the cavern early. At December 31, 2018, the facility's property, plant, and equipment had a net book value of $109 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.

The cavern continues to maintain its pressures and overall structural integrity. Southern Company Gas intends to monitor the cavern and comply with the Louisiana DNR order through 2020 and place the cavern back in service in 2021. These events were considered in connection with Southern Company Gas' annual long-lived asset impairment analysis, which determined there was no impairment as of December 31, 2018. Any changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a material impact on Southern Company Gas' financial statements.

Effective January 1, 2018, Southern Company Gas conformed its paid time off policy to align with Southern Company. Under the new policy, paid time off days are vested by the employee on the first day of each year and will continue to be recovered through rates on an as-paid basis. As a result, Southern Company Gas accrued $21 million as of January 1, 2018, of which $9 million was recorded as regulatory assets by the natural gas distribution utilities. See Note 2 to the financial statements under "Southern Company Gas" for additional information.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Company Gas prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Notes 1, 5, and 6 to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on Southern Company Gas' results of operations and related disclosures. 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.

Utility Regulation

The natural gas distribution utilities comprised approximately 82% of Southern Company Gas' total operating revenues for 2018 and are subject to rate regulation by their respective state regulatory agencies, which set the rates utilities are permitted to charge customers based on allowable costs, including a reasonable ROE. As a result, 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 has a further effect on Southern Company Gas' 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 natural gas distribution utilities; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and other postretirement benefits have less of a direct impact on Southern Company Gas' results of operations and financial condition than they would on a non-regulated company.

As reflected in Note 2 to the financial statements under "Southern Company Gas – Regulatory Assets and Liabilities," 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 Southern Company Gas' financial statements.

Accounting for Income Taxes

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, 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 many states in which Southern Company Gas operates.

II-199

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

On behalf of Southern Company Gas, Southern Company files a consolidated federal income tax return and 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 no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. Certain deductions and credits can be limited at the consolidated or combined level resulting in NOL and tax credit carryforwards that would not otherwise result on a stand-alone basis. Utilization of NOL carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of Southern Company Gas', as well as Southern Company's, current financial position and result of operations, including currently available information about future years, to estimate when future taxable income will be realized.

Given the significant judgment involved in estimating NOL carryforwards and tax credit carryforwards and multi-state apportionments, Southern Company Gas considers state deferred income tax liabilities and assets to be critical accounting estimates.

Assessment of Assets

Goodwill

Southern Company Gas does not amortize its goodwill, but tests it annually for impairment at the reporting unit level during the fourth quarter or more frequently if impairment indicators arise. These indicators include, but are 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 Southern Company Gas' impairment test, Southern Company Gas 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 Southern Company Gas 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 Southern Company Gas 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. Under ASU No. 2017-04, which was adopted effective January 1, 2018, any goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value.

For the 2018 and 2016 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 analysis was required. For the 2017 annual impairment test, Southern Company Gas performed the quantitative assessment, which resulted in the fair value of all of its reporting units that have goodwill exceeding their carrying value. In the first quarter 2018, Southern Company Gas recorded a $42 million impairment charge in contemplation of the sale of Pivotal Home Solutions.

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, Southern Company Gas considers these estimates to be critical accounting estimates.

See Note 1 to the financial statements under "Recently Adopted Accounting Standards – Other" for information on Southern Company Gas' adoption of ASU No. 2017-04.

Long-Lived Assets

Southern Company Gas depreciates or amortizes its long-lived and intangible assets over their estimated useful lives. Southern Company Gas assesses its long-lived and intangible assets for impairment whenever events or changes in circumstances indicate that an asset's carrying amount may not be recoverable. When such events or circumstances are present, Southern Company Gas

II-200

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

assesses the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected future cash flows. Impairment is indicated if the carrying amount of a long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If impairment is indicated, Southern Company Gas records an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset.

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, Southern Company Gas considers these estimates to be critical accounting estimates.

See Notes 2 and 3 to the financial statements under "FERC Matters – Southern Company Gas" and "Other Matters – Southern Company Gas," respectively, for information on certain assets recently evaluated for impairment.

Derivatives and Hedging Activities

Determining whether a contract meets the definition of a derivative instrument, contains an embedded derivative requiring bifurcation, or qualifies for hedge accounting treatment is complex. The treatment of a single contract may vary from period to period depending upon accounting elections, changes in Southern Company Gas' assessment of the likelihood of future hedged transactions, or new interpretations of accounting guidance. As a result, judgment is required in determining the appropriate accounting treatment. In addition, the estimated fair value of derivative instruments may change significantly from period to period depending upon market conditions, and changes in hedge effectiveness may impact the accounting treatment.

Derivative instruments (including certain derivative instruments embedded in other contracts) are recorded on the balance sheets as either assets or liabilities measured at their fair value. If the transaction qualifies for, and is designated as, a normal purchase or normal sale, it is exempted from fair value accounting treatment and is, instead, subject to traditional accrual accounting. Southern Company Gas utilizes market data or assumptions that market participants would use in pricing the derivative asset or liability, including assumptions about risk and the risks inherent in the inputs of the valuation technique.

Changes in the derivatives' fair value are recognized concurrently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, derivative gains and losses offset related results of the hedged item in the income statement in the case of a fair value hedge, or gains and losses are recorded in OCI on the balance sheets until the hedged transaction affects earnings in the case of a cash flow hedge. Additionally, a company is required to formally designate a derivative as a hedge as well as document and assess the effectiveness of derivatives associated with transactions that receive hedge accounting treatment.

Nicor Gas utilizes derivative instruments to hedge the price risk for the purchase of natural gas for customers. These derivatives are reflected at fair value and are not designated as accounting hedges. Realized gains or losses on such instruments are included in the cost of gas delivered and are passed through directly to customers, subject to review by the applicable state regulatory agencies, and therefore have no direct impact on earnings. Unrealized changes in the fair value of these derivative instruments are deferred as regulatory assets or liabilities. Prior to its disposition, Elizabethtown Gas utilized the same policy.

Southern Company Gas uses derivative instruments primarily to reduce the impact to its results of operations due to the risk of changes in the price of natural gas and to a lesser extent Southern Company Gas hedges against warmer-than-normal weather and interest rates. The fair value of natural gas derivative instruments used to manage exposure to changing natural gas prices reflects the estimated amounts that Southern Company Gas would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. For derivatives utilized at gas marketing services and wholesale gas services that are not designated as accounting hedges, changes in fair value are reported as gains or losses in Southern Company Gas' results of operations in the period of change. Gas marketing services records derivative gains or losses arising from cash flow hedges in OCI and reclassifies them into earnings in the same period that the underlying hedged item is recognized in earnings.

Southern Company Gas classifies derivative assets and liabilities based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The determination of the fair value of the derivative instruments incorporates various required factors. These factors include:


•	the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit);


•	events specific to a given counterparty; and


•	the impact of Southern Company Gas' nonperformance risk on its liabilities.

II-201

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

If there is a significant change in the underlying market prices or pricing assumptions Southern Company Gas uses in pricing its derivative assets or liabilities, Southern Company Gas may experience a significant impact on its financial position, results of operations, and cash flows. See Note 14 to the financial statements for additional information.

Given the assumptions used in pricing the derivative asset or liability, Southern Company Gas considers the valuation of derivative assets and liabilities a critical accounting estimate. See FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" herein for more information.

Pension and Other Postretirement Benefits

Southern Company Gas' calculation of pension and other postretirement benefits expense is dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term return 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 Southern Company Gas believes that the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect its pension and other postretirement benefit costs and obligations.

Key elements in determining Southern Company Gas' pension and other postretirement benefit expense are the expected long-term return on plan assets and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. The expected long-term return on pension and other postretirement benefit plan assets is based on Southern Company's investment strategy, historical experience, and expectations for long-term rates of return that consider external actuarial advice. Southern Company determines the long-term return on plan assets by applying the long-term rate of expected returns on various asset classes to Southern Company's target asset allocation. For purposes of determining Southern Company Gas' liability related to the pension and other postretirement benefit plans, Southern Company discounts the future related cash flows using a single-point discount rate developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments.

A 25 basis point change in any significant assumption (discount rate, salary increases, or long-term rate of return on plan assets) would result in a $3 million or less change in total annual benefit expense, a $30 million or less change in the projected obligation for the pension plan, and a $6 million or less change in the projected obligation for other post retirement benefit plans.

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

Contingent Obligations

Southern Company Gas is subject to a number of federal and state laws and regulations as well as other factors and conditions that subject it 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. Southern Company Gas periodically evaluates its exposure to such risks and records 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 Southern Company Gas' results of operations, cash flows, or financial condition.

Recently Issued Accounting Standards

See Note 1 to the financial statements under "Recently Adopted Accounting Standards" for additional information.

In 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Southern Company Gas adopted the new standard effective January 1, 2019.

Southern Company Gas elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby the requirements of ASU 2016-02 are applied on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Southern Company Gas elected the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Southern Company Gas 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. Southern Company Gas also made accounting policy elections to account

II-202

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

for short-term leases in all asset classes as off-balance sheet leases and combined lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.

Southern Company Gas completed the implementation of a new application to track and account for its leases and updated its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Southern Company Gas completed its lease inventory and determined its most significant leases involve real estate and fleet vehicles. In the first quarter 2019, the adoption of ASU 2016-02 resulted in recording lease liabilities and right-of-use assets on Southern Company Gas' balance sheet each totaling $86 million, with no impact on Southern Company Gas' statement of income.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Company Gas' financial condition remained stable at December 31, 2018. Southern Company Gas' cash requirements primarily consist of funding ongoing operations, common stock dividends, capital expenditures, investments in unconsolidated subsidiaries, and debt maturities. 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. Operating cash flows provide a substantial portion of Southern Company Gas' cash needs. For the three-year period from 2019 through 2021, Southern Company Gas' projected common stock dividends, capital expenditures, and debt maturities are expected to exceed operating cash flows. Southern Company Gas plans to finance future cash needs in excess of its operating cash flows primarily through external securities issuances, equity contributions from Southern Company, and borrowings from financial institutions. Southern Company Gas plans to use commercial paper to manage seasonal variations in operating cash flows and other working capital needs. Southern Company Gas intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital," "Financing Activities," and "Capital Requirements and Contractual Obligations" herein for additional information.

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, 2018, the amount of subsidiary retained earnings restricted to dividend totaled $814 million. 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.

Southern Company Gas' investments in the qualified pension plan decreased in value at December 31, 2018 as compared to December 31, 2017. There were no voluntary contributions to the qualified pension plan in 2018 and no mandatory contributions to its qualified pension plan are anticipated during 2019. See Note 11 to the financial statements for additional information.

Net cash provided from operating activities in the successor year ended 2018 totaled $764 million, a decrease of $117 million from 2017. The decrease was primarily due to higher income tax payments as a result of net taxable gains from the Southern Company Gas Dispositions, partially offset by increased volumes of natural gas sold during 2018 as a result of colder weather compared to 2017. Net cash provided from operating activities totaled $881 million for 2017, primarily due to earnings and the timing of cash receipts for the sale of natural gas inventory and vendor payments. Net cash used for operating activities was $327 million for the successor period of July 1, 2016 through December 31, 2016, primarily due to a $125 million voluntary pension contribution, a $35 million payment for the settlement of an interest rate swap, and less cash due to the timing of collecting receivables and disbursing payables. Due to the seasonal nature of its business, Southern Company Gas typically reports negative cash flows from operating activities in the second half of the year. Net cash provided from operating activities was $1.1 billion for the predecessor period of January 1, 2016 through June 30, 2016, primarily due to low volumes of natural gas sales and changes in natural gas inventory as a result of warmer weather and the timing of recovery of related gas costs and weather normalization adjustments from customers.

Net cash provided from investing activities for the successor year ended 2018 totaled $1.0 billion and was primarily due to the $2.6 billion proceeds from the Southern Company Gas Dispositions, partially offset by gross property additions primarily related to utility capital expenditures and pre-approved rider and infrastructure investments recovered through replacement programs at gas distribution operations as well as capital contributed to equity method pipeline investments partially offset by capital returned from equity method pipeline investments. Net cash used for investing activities totaled $1.6 billion for the successor year ended 2017, which reflected $1.5 billion in capital expenditures primarily due to gross property additions for infrastructure replacement programs at gas distribution operations and $145 million in capital contributions to equity method pipeline investments, partially offset by $80 million in capital returned from equity method pipeline investments. Net cash used for investing activities was $2.1 billion for the successor period of July 1, 2016 through December 31, 2016, which reflected

II-203

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

$1.4 billion primarily related to Southern Company Gas' acquisition of the 50% interest in SNG, and $632 million in capital expenditures. Net cash used for investing activities was $556 million for the predecessor period of January 1, 2016 through June 30, 2016 which primarily related to capital expenditures. See Note 7 to the financial statements under "Southern Company Gas" and Note 15 to the financial statements under "Southern Company Gas – Investment in SNG" for additional information.

Net cash used for financing activities for the successor year ended 2018 of $1.8 billion included payments of common stock dividends to Southern Company, return of capital to Southern Company, redemptions of gas facility revenue bonds and senior notes, and repayments of commercial paper borrowings and long-term debt, partially offset by debt issuances and capital contributions from Southern Company. Net cash provided from financing activities totaled $741 million for 2017, primarily due to $850 million in debt issuances, $262 million in net additional commercial paper borrowings, and $103 million in capital contributions from Southern Company, partially offset by $443 million in common stock dividend payments to Southern Company and $22 million in repayment of long-term debt. Net cash provided from financing activities was $2.4 billion for the successor period of July 1, 2016 through December 31, 2016, which reflected $1.1 billion of capital contributions from Southern Company, primarily used to fund Southern Company Gas' investment in SNG, $1.1 billion in net additional commercial paper borrowings, partially offset by $160 million for the purchase of the 15% noncontrolling ownership interest in SouthStar, and $900 million in proceeds from debt issuances, partially offset by $420 million in debt payments. Net cash used for financing activities was $558 million for the predecessor period of January 1, 2016 through June 30, 2016, primarily due to $896 million in net repayment of commercial paper borrowings and $125 million in repayment of long-term debt, partially offset by $600 million in debt issuances. See Note 7 to the financial statements under "Southern Company Gas" and Note 15 to the financial statements under "Southern Company Gas – Investment in SNG" for additional information.

Significant balance sheet changes at December 31, 2018 include $2.8 billion and $403 million in total assets and liabilities sold, respectively, associated with the Southern Company Gas Dispositions as described in Note 15 to the financial statements herein under "Southern Company Gas." After adjusting for these changes, other significant balance sheet changes included an increase of $1.0 billion in total property, plant, and equipment primarily due to capital expenditures for infrastructure replacement programs, a decrease of $73 million in accumulated deferred income tax liabilities primarily due to the change in the federal corporate income tax rate, partially offset by tax depreciation related to infrastructure assets placed in service, as well as the impacts of State of Illinois tax legislation, and a decrease of $108 million in long-term debt (including securities due within one year), primarily due to $200 million redemption of gas facility revenue bonds and $155 million in repayments of long-term debt, partially offset by the issuance of $300 million of first mortgage bonds at Nicor Gas. Other significant balance sheet changes include a decrease of $868 million in notes payable primarily related to a decrease in commercial paper borrowings of $840 million at Southern Company Gas Capital and $28 million at Nicor Gas. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" and FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein and Notes 8 and 10 to the financial statements for additional information.

Sources of Capital

Southern Company Gas plans to obtain the funds to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, depend upon prevailing market conditions, regulatory approval, and other factors. With respect to the public offering of securities, Southern Company Gas (excluding its subsidiaries) and Southern Company Gas Capital file registration statements with the SEC under the Securities Act of 1933, as amended. The issuance of securities by Nicor Gas is generally subject to the approval of the Illinois Commission.

Southern Company Gas obtains separate financing without credit support from any affiliate in the Southern Company system. 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, except as described below, funds of Southern Company Gas are not commingled with funds of any other company in the Southern Company system.

Southern Company Gas maintains commercial paper programs at Southern Company Gas Capital and Nicor Gas that consist of short-term, unsecured promissory notes. 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 Southern Company Gas' other subsidiaries benefit from Southern Company Gas Capital's commercial paper program.

At December 31, 2018, Southern Company Gas' current liabilities exceeded current assets by $469 million, primarily as a result of $650 million in notes payable and $357 million of securities due within one year. Southern Company Gas' current liabilities frequently exceed current assets because of commercial paper borrowings used to fund daily operations, scheduled maturities of long-term debt, and significant seasonal fluctuations in cash needs.

II-204

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

At December 31, 2018, Southern Company Gas had $64 million of cash and cash equivalents. Committed credit arrangements with banks at December 31, 2018 were as follows:



Company	Expires 2022		Unused
	(millions)
Southern Company Gas Capital^(a)	$	1,400	$	1,395
Nicor Gas	500		500
Total^(b)	$	1,900	$	1,895

(a)Southern Company Gas guarantees the obligations of Southern Company Gas Capital.

(b)Pursuant to the credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.

See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information.

The multi-year credit arrangement of Southern Company Gas Capital and Nicor Gas (Facility) contains a covenant that limits the debt levels and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of the applicable company. Such cross-acceleration provision to other indebtedness would trigger an event of default of the applicable company if Southern Company Gas or Nicor Gas defaulted on indebtedness, the payment of which was then accelerated. At December 31, 2018, both companies were in compliance with such covenant. The Facility does not contain a material adverse change clause at the time of borrowings.

Subject to applicable market conditions, the applicable company expects to renew or replace the Facility as needed, prior to expiration. In connection therewith, the applicable company may extend the maturity dates and/or increase or decrease the lending commitments thereunder. A portion of unused credit with banks provides liquidity support to Southern Company Gas.

Southern Company Gas has substantial cash flow from operating activities and access to capital markets, including the commercial paper programs, and financial institutions to meet liquidity needs. Southern Company Gas makes short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Short-term borrowings are included in notes payable in the balance sheets.

II-205

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

Details of short-term borrowings were as follows:



	Short-term Debt at the End of the Period				Short-term Debt During the Period^(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
Successor – December 31, 2018:
Commercial paper:
Southern Company Gas Capital	$	403	3.05	%	$	489	2.25	%	$	1,261
Nicor Gas	247		2.98	%	123		2.16	%	275
Short-term bank debt:
Southern Company Gas Capital	—		—	%	31		2.72	%	276
Total	$	650	3.03	%	$	643	2.25	%

Successor – December 31, 2017:
Commercial paper:
Southern Company Gas Capital	$	1,243	1.73	%	$	723	1.40	%	$	1,243
Nicor Gas	275		1.83	%	176		1.12	%	525
Total	$	1,518	1.75	%	$	899	1.35	%

Successor – December 31, 2016:
Commercial paper:
Southern Company Gas Capital	$	733	1.09	%	$	461	0.79	%	$	770
Nicor Gas	524		0.95	%	309		0.67	%	587
Total	$	1,257	1.03	%	$	770	0.74	%


(*)	Average and maximum amounts are based upon daily balances during the 12-month periods.

Southern Company Gas believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.

Financing Activities

The long-term debt on Southern Company Gas' balance sheets includes both principal and non-principal components. At December 31, 2018, the non-principal components totaled $456 million, including the amount attributable to long-term debt due within one year, which consisted of the unamortized portions of the fair value adjustment recorded in purchase accounting, debt premiums, debt discounts, and debt issuance costs.

In December 2016, Southern Company Gas executed intercompany promissory notes to further allocate interest expense to its reportable segments that previously remained in the "all other" segment. These intercompany promissory notes allow Southern Company Gas to calculate net income, which is its performance measure subsequent to the Merger, at the segment level that incorporates the full impact of interest costs.

Except as otherwise described herein, Southern Company Gas and its subsidiaries used the proceeds of debt issuances for their redemptions and maturities, to pay common stock dividends, to repay short-term indebtedness, for capital expenditures, and for general corporate purposes, including working capital.

In January 2018, Southern Company Gas issued a floating rate promissory note to Southern Company in an aggregate principal amount of $100 million bearing interest based on one-month LIBOR. In March 2018, Southern Company Gas repaid this promissory note.

Prior to its sale, in the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of gas facility revenue bonds to be redeemed. Also in the second quarter 2018, Pivotal Utility Holdings, as borrower, and Southern Company Gas, as guarantor, entered into a $181 million short-term delayed draw floating rate bank term loan bearing interest

II-206

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

based on one-month LIBOR, which Pivotal Utility Holdings used to repay the gas facility revenue bonds. In July 2018, Pivotal Utility Holdings repaid this short-term loan.

Nicor Gas issued $300 million aggregate principal amount of first mortgage bonds in a private placement, of which $100 million was issued in August 2018 and $200 million was issued in November 2018.

In October 2018, Southern Company Gas Capital repaid at maturity $155 million aggregate principal amount of 3.50% Series B Senior Notes.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company Gas plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

Credit Rating Risk

Southern Company Gas does 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 below BBB- and/or Baa3. These contracts are for physical gas purchases and sales and energy price risk management. The maximum potential collateral requirement under these contracts at December 31, 2018 was $30 million.

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 Southern Company Gas to access capital markets and would be likely to impact the cost at which it does so.

On September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and certain of its subsidiaries (including Southern Company Gas, Southern Company Gas Capital, and Nicor Gas).

As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Southern Company Gas, may be negatively impacted. Southern Company Gas and its regulated subsidiaries have taken actions to mitigate the resulting impacts, which, among other alternatives, include adjusting capital structure. Absent actions by Southern Company and its subsidiaries that fully mitigate the impacts, Southern Company Gas', Southern Company Gas Capital's, and Nicor Gas' credit ratings could be negatively affected. The Georgia PSC's May 15, 2018 approval of a stipulation for Atlanta Gas Light's annual rate adjustment maintained the previously authorized earnings band and increased the equity ratio to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. See Note 2 to the financial statements under "Southern Company Gas" for information on additional rate proceedings for Nicor Gas and Atlanta Gas Light expected to conclude in 2019.

Market Price Risk

Southern Company Gas is exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas distribution utilities of Southern Company Gas that sell natural gas directly to end-use customers have limited exposure to market volatility of natural gas prices. To manage the volatility attributable to these exposures, Southern Company Gas nets the exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Southern Company Gas' policies in areas such as counterparty exposure and risk management practices. Southern Company Gas uses derivatives to buy and sell natural gas as well as 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.

Certain natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. For the weather risk associated with Nicor Gas, Southern Company Gas has a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower adjusted operating margins potentially resulting from significantly warmer-than-normal weather. In addition, certain non-regulated operations 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.

II-207

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

Gas marketing services and wholesale gas services also actively manage 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 operating margins. Some of these economic hedge activities may not qualify, or may not be designated, for hedge accounting treatment. Southern Company Gas had no material change in market risk exposure for the year ended December 31, 2018 when compared to the year ended December 31, 2017.

For the periods presented below, the changes in net fair value of derivative contracts were as follows:



	Successor									Predecessor
	Year Ended December 31, 2018			Year Ended December 31, 2017			July 1, 2016 through December 31, 2016			January 1, 2016 through June 30, 2016
	(in millions)									(in millions)
Contracts outstanding at beginning of period, assets (liabilities), net	$	(106	)	$	8		$	(54	)	$	75
Contracts realized or otherwise settled	66			(1		)	18			(77		)
Current period changes^(a)	(127		)	(113		)	48			(82		)
Contracts outstanding at end of period, assets (liabilities), net	(167		)	(106		)	12			(84		)
Netting of cash collateral	277			193			62			120
Cash collateral and net fair value of contracts outstanding at end of period^(b)	$	110		$	87		$	74		$	36


(a)	Current period changes also include the changes in fair value of new contracts entered into during the period, if any.


(b)	Net fair value of derivative contracts outstanding excludes premium and intrinsic value associated with weather derivatives of $8 million and $11 million at December 31, 2018 and 2017, respectively, and includes premium and intrinsic value associated with weather derivatives of $4 million at December 31, 2016, and $5 million at June 30, 2016.

The net hedge volume of energy-related derivative contracts for natural gas positions at December 31, 2018 and 2017 were as follows:



	2018	2017
	mmBtu Volume
	(in millions)
Commodity – Natural gas	120	300
Net Purchased / (Sold) Volume	120	300

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 volume presented above represents the net of long natural gas positions of 4.16 billion mmBtu and short natural gas positions of 4.04 billion mmBtu at December 31, 2018 and the net of long natural gas positions of 3.51 billion mmBtu and short natural gas positions of 3.21 billion mmBtu at December 31, 2017.

Energy-related derivative contracts that are designated as regulatory hedges relate primarily to Southern Company Gas' fuel-hedging programs. Therefore, gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in cost of natural gas as the underlying gas is used in operations and ultimately recovered through the respective cost recovery clause. Certain other 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 OCI before being recognized in income in the same period as the hedged transaction. 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 natural gas industry. 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.

II-208

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

Southern Company Gas uses OTC 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. See Note 13 to the financial statements for further discussion of fair value measurements.

The maturities of the energy-related derivative contracts at December 31, 2018 were as follows:



				Fair Value Measurements
				December 31, 2018
				Maturity
	Total Fair Value			Year 1			Years 2 & 3			Years 4 & 5
	(in millions)
Level 1^(a)	$	(179	)	$	(59	)	$	(86	)	$	(34	)
Level 2^(b)	12			37			—			(25		)
Fair value of contracts outstanding at end of period^(c)	$	(167	)	$	(22	)	$	(86	)	$	(59	)


(a)	Valued using NYMEX futures prices.


(b)	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 $277 million as well as premium and associated intrinsic value associated with weather derivatives of $8 million at December 31, 2018.

Value at Risk (VaR)

VaR is the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability. Southern Company Gas' VaR may not be comparable to that of other companies due to differences in the factors used to calculate VaR. Southern Company Gas' VaR is determined on a 95% confidence interval and a one-day holding period, which means that 95% of the time, the risk of loss in a day from a portfolio of positions is expected to be less than or equal to the amount of VaR calculated. The open exposure of Southern Company Gas is managed in accordance with established policies that limit market risk and require daily reporting of potential financial exposure to senior management. Because Southern Company Gas generally manages physical gas assets and economically protects its positions by hedging in the futures markets, Southern Company Gas' open exposure is generally mitigated. Southern Company Gas employs daily risk testing, using both VaR and stress testing, to evaluate the risk of its positions.

Southern Company Gas actively monitors open commodity positions and the resulting VaR and maintains a relatively small risk exposure as total buy volume is close to sell volume, with minimal open natural gas price risk. Based on a 95% confidence interval and employing a one-day holding period, SouthStar's portfolio of positions for all periods presented was immaterial.

For the periods presented below, wholesale gas services had the following VaRs:



	Successor						Predecessor
	Year Ended December 31, 2018		Year Ended December 31, 2017		July 1, 2016 through December 31, 2016		January 1, 2016 through June 30, 2016
	(in millions)						(in millions)
Period end^(*)	$	6.4	$	4.8	$	2.3	$	1.9
Average	3.7		2.0		2.0		2.0
High^(*)	11.7		4.8		2.8		2.5
Low	1.2		1.0		1.4		1.6

(*)

Increases in VaR at December 31, 2018 and 2017 were driven by significant natural gas price increases in Sequent's key markets. The natural gas price increase in 2018 was driven by an industry-wide lower-than-normal natural gas storage inventory position and colder-than-normal weather in the middle of fourth quarter 2018. The natural gas price increase in 2017 was driven by colder-than-normal weather. As weather and natural gas prices moderated subsequent to December 31, 2018 and 2017, VaR reduced to a level consistent with December 31, 2016.

II-209

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

Credit Risk

Gas Distribution Operations

Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 15 Marketers in Georgia. The credit risk exposure to 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. For 2018, the four largest Marketers based on customer count, which includes SouthStar, accounted for 20% of Southern Company Gas' adjusted operating margin and 25% of gas distribution operations' adjusted operating margin.

Several factors are designed to mitigate Southern Company Gas' risks from the increased concentration of credit that has resulted from deregulation. In addition to the security support described above, Atlanta Gas Light bills intrastate delivery service to Marketers in advance rather than in arrears. Atlanta Gas Light accepts credit support in the form of cash deposits, letters of credit/surety bonds from acceptable issuers, and corporate guarantees from investment-grade entities. On a monthly basis, a management risk oversight committee reviews the adequacy of credit support coverage, credit rating profiles of credit support providers, and payment status of each Marketer. Southern Company Gas believes that adequate policies and procedures are in place to properly quantify, manage, and report on Atlanta Gas Light's credit risk exposure to Marketers.

Atlanta Gas Light also faces potential credit risk in connection with assignments of interstate pipeline transportation and storage capacity to Marketers. Although Atlanta Gas Light assigns this capacity to Marketers, in the event that a Marketer fails to pay the interstate pipelines for the capacity, the interstate pipelines would likely seek repayment from Atlanta Gas Light.

Wholesale Gas Services

Southern Company Gas has established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. Southern Company Gas also utilizes netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty and also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral, provided the netting and cash collateral agreements include such provisions.

Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary. Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for a counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.

Certain of Southern Company Gas' derivative instruments contain credit-risk-related or other contingent features that could increase the payments for collateral it posts in the normal course of business when its financial instruments are in net liability positions. At December 31, 2018, for agreements with such features, Southern Company Gas' derivative instruments with liability fair values totaled $5 million for which Southern Company Gas had no collateral posted with derivatives counterparties to satisfy these arrangements.

Southern Company Gas has a concentration of credit risk as measured by its 30-day receivable exposure plus forward exposure. At December 31, 2018, wholesale gas services' top 20 counterparties represented approximately 48%, or $298 million, of its total counterparty exposure and had a weighted average S&P equivalent credit rating of A-, all of which is consistent with the prior year. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P or Moody's ratings to an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody's, respectively, and 1 being D / Default by S&P and Moody's, respectively. A counterparty that does not have an external rating is assigned an internal rating based on the strength of the financial ratios of that counterparty. To arrive at the weighted average credit rating, each counterparty is assigned an internal ratio, which is multiplied by their credit exposure and summed for all counterparties. The sum is divided by the aggregate total counterparties' exposures, and this numeric value is then converted to a S&P equivalent.

II-210

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

The following table provides credit risk information related to Southern Company Gas' third-party natural gas contracts receivable and payable positions at December 31:



	Gross Receivables				Gross Payables
	2018		2017		2018		2017
	(in millions)				(in millions)
Netting agreements in place:
Counterparty is investment grade	$	461	$	342	$	255	$	202
Counterparty is non-investment grade	5		20		95		25
Counterparty has no external rating	314		226		505		315
No netting agreements in place:
Counterparty is investment grade	19		19		1		4
Counterparty has no external rating	2		—		—		—
Amount recorded in balance sheets	$	801	$	607	$	856	$	546

Gas Marketing Services

Southern Company Gas obtains credit scores for its firm residential and small commercial customers using a national credit reporting agency, enrolling only those customers that meet or exceed Southern Company Gas' credit threshold. Southern Company Gas considers potential interruptible and large commercial customers based on reviews of publicly available financial statements and commercially available credit reports. Prior to entering into a physical transaction, Southern Company Gas also assigns physical wholesale counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements.

Capital Requirements and Contractual Obligations

Southern Company Gas' capital investments are currently estimated to total $1.6 billion for 2019, $1.9 billion for 2020, $1.3 billion for 2021, $1.2 billion for 2022, and $1.3 billion for 2023. The regulatory infrastructure programs and other construction programs are subject to periodic review and revision, and actual costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in FERC rules and regulations; state regulatory agency approvals; changes in legislation; the cost and efficiency of labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

In addition, as discussed in Note 11 to the financial statements, Southern Company Gas provides postretirement benefits to certain eligible employees and funds trusts to the extent required by the applicable state regulatory agencies.

Funding requirements related to obligations associated with scheduled maturities of long-term debt, including the related interest; pipeline charges, storage capacity, and gas supply; operating leases; asset management agreements; financial derivative obligations; pension and other postretirement benefit plans; and other purchase commitments, primarily related to environmental remediation liabilities, are detailed in the contractual obligations table that follows. See Notes 1, 3, 8, 9, 11, and 14 to the financial statements for additional information.

II-211

Table of Contents Index to Financial Statements

MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)

Southern Company Gas and Subsidiary Companies 2018 Annual Report

Contractual Obligations

Contractual obligations at December 31, 2018 were as follows:



	2019		2020- 2021		2022- 2023		After 2023		Total
	(in millions)
Long-term debt^(a) —
Principal	$	350	$	330	$	446	$	4,359	$	5,485
Interest	244		453		422		3,242		4,361
Pipeline charges, storage capacity, and gas supply^(b)	781		1,104		901		1,871		4,657
Operating leases^(c)	18		31		23		34		106
Asset management agreements^(d)	10		8		—		—		18
Financial derivative obligations^(e)	583		217		109		—		909
Pension and other postretirement benefit plans^(f)	16		32		—		—		48
Purchase commitments —
Capital^(g)	1,591		3,231		2,496		—		7,318
Other^(h)	25		4		2		—		31
Total	$	3,618	$	5,410	$	4,399	$	9,506	$	22,933


(a)	Amounts are reflected based on final maturity dates. Southern Company Gas plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates at December 31, 2018, as reflected in the statements of capitalization.

(b)

Includes charges recoverable through a natural gas cost recovery mechanism, or alternatively billed to Marketers, and demand charges associated with Sequent. The gas supply balance includes amounts for Nicor Gas and SouthStar gas commodity purchase commitments of 47 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2018 and valued at $150 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries, including SouthStar, in support of payment obligations.

(c)

Certain operating leases have provisions for step rent or escalation payments and certain lease concessions are accounted for by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms. However, this accounting treatment does not affect the future annual operating lease cash obligations as shown herein. In terms of rental charges and duration of contracts, Southern Company Gas' most significant operating leases relate to real estate.


(d)	Represent fixed-fee minimum payments for Sequent's affiliated asset management agreements.


(e)	See Notes 1 and 14 to the financial statements for additional information.

(f)

Southern Company Gas forecasts contributions to the pension and other postretirement benefit plans over a three-year period. Southern Company Gas anticipates no mandatory contributions to the qualified pension plan during the next three years. Amounts presented represent estimated benefit payments for the nonqualified pension plans, estimated non-trust benefit payments for the other postretirement benefit plans, and estimated contributions to the other postretirement benefit plan trusts, all of which will be made from Southern Company Gas' corporate assets. See Note 11 to the financial statements for additional information related to the pension and other postretirement benefit plans, including estimated benefit payments. Certain benefit payments will be made through the related benefit plans. Other benefit payments will be made from Southern Company Gas' corporate assets.


(g)	Estimated capital expenditures are provided through 2023. At December 31, 2018, significant purchase commitments were outstanding in connection with infrastructure and other construction programs.


(h)	Includes contractual environmental remediation liabilities that are generally recoverable through base rates or rate rider mechanisms and LTSAs.

II-212

Table of Contents Index to Financial Statements


Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

II-213

Table of Contents Index to Financial Statements


Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO 2018 FINANCIAL STATEMENTS



	Page
The Southern Company and Subsidiary Companies:
Report of Independent Registered Public Accounting Firm	II-216
Consolidated Statements of Income for the Years Ended December 31, 2018, 2017, and 2016	II-217
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2018, 2017, and 2016	II-218
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017, and 2016	II-219
Consolidated Balance Sheets at December 31, 2018 and 2017	II-220
Consolidated Statements of Capitalization at December 31, 2018 and 2017	II-222
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2018, 2017, and 2016	II-224

Alabama Power:
Report of Independent Registered Public Accounting Firm	II-225
Statements of Income for the Years Ended December 31, 2018, 2017, and 2016	II-226
Statements of Comprehensive Income for the Years Ended December 31, 2018, 2017, and 2016	II-227
Statements of Cash Flows for the Years Ended December 31, 2018, 2017, and 2016	II-228
Balance Sheets at December 31, 2018 and 2017	II-229
Statements of Capitalization at December 31, 2018 and 2017	II-231
Statements of Common Stockholder's Equity for the Years Ended December 31, 2018, 2017, and 2016	II-232

Georgia Power:
Report of Independent Registered Public Accounting Firm	II-233
Statements of Income for the Years Ended December 31, 2018, 2017, and 2016	II-234
Statements of Comprehensive Income for the Years Ended December 31, 2018, 2017, and 2016	II-235
Statements of Cash Flows for the Years Ended December 31, 2018, 2017, and 2016	II-236
Balance Sheets at December 31, 2018 and 2017	II-237
Statements of Capitalization at December 31, 2018 and 2017	II-239
Statements of Common Stockholder's Equity for the Years Ended December 31, 2018, 2017, and 2016	II-240

Mississippi Power:
Report of Independent Registered Public Accounting Firm	II-241
Statements of Operations for the Years Ended December 31, 2018, 2017, and 2016	II-242
Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2018, 2017, and 2016	II-243
Statements of Cash Flows for the Years Ended December 31, 2018, 2017, and 2016	II-244
Balance Sheets at December 31, 2018 and 2017	II-245
Statements of Capitalization at December 31, 2018 and 2017	II-247
Statements of Common Stockholder's Equity for the Years Ended December 31, 2018, 2017, and 2016	II-248

II-214

Table of Contents Index to Financial Statements



	Page
Southern Power and Subsidiary Companies:
Report of Independent Registered Public Accounting Firm	II-249
Consolidated Statements of Income for the Years Ended December 31, 2018, 2017, and 2016	II-250
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2018, 2017, and 2016	II-251
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017, and 2016	II-252
Consolidated Balance Sheets at December 31, 2018 and 2017	II-253
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2018, 2017, and 2016	II-255

Southern Company Gas and Subsidiary Companies:
Report of Independent Registered Public Accounting Firm	II-256
Consolidated Statements of Income for the Years Ended December 31, 2018, 2017, and 2016	II-257
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2018, 2017, and 2016	II-258
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017, and 2016	II-259
Consolidated Balance Sheets at December 31, 2018 and 2017	II-260
Consolidated Statements of Capitalization at December 31, 2018 and 2017	II-262
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2018, 2017, and 2016	II-263

Combined Notes to Financial Statements	II-264

II-215

Table of Contents Index to Financial Statements

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 and consolidated statements of capitalization of The Southern Company and subsidiary companies (Southern Company) as of December 31, 2018 and 2017, 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, 2018, 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, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, 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, 2018, 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.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

February 19, 2019

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

II-216

Table of Contents Index to Financial Statements

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2018, 2017, and 2016

Southern Company and Subsidiary Companies 2018 Annual Report



	2018			2017			2016
	(in millions)
Operating Revenues:
Retail electric revenues	$	15,222		$	15,330		$	15,234
Wholesale electric revenues	2,516			2,426			1,926
Other electric revenues	664			681			698
Natural gas revenues	3,854			3,791			1,596
Other revenues	1,239			803			442
Total operating revenues	23,495			23,031			19,896
Operating Expenses:
Fuel	4,637			4,400			4,361
Purchased power	971			863			750
Cost of natural gas	1,539			1,601			613
Cost of other sales	806			513			260
Other operations and maintenance	5,889			5,739			5,382
Depreciation and amortization	3,131			3,010			2,502
Taxes other than income taxes	1,315			1,250			1,113
Estimated loss on plants under construction	1,097			3,362			428
Impairment charges	210			—			—
Gain on dispositions, net	(291		)	(40		)	1
Total operating expenses	19,304			20,698			15,410
Operating Income	4,191			2,333			4,486
Other Income and (Expense):
Allowance for equity funds used during construction	138			160			202
Earnings from equity method investments	148			106			59
Interest expense, net of amounts capitalized	(1,842		)	(1,694		)	(1,317		)
Other income (expense), net	114			163			50
Total other income and (expense)	(1,442		)	(1,265		)	(1,006		)
Earnings Before Income Taxes	2,749			1,068			3,480
Income taxes	449			142			951
Consolidated Net Income	2,300			926			2,529
Dividends on preferred and preference stock of subsidiaries	16			38			45
Net income attributable to noncontrolling interests	58			46			36
Consolidated Net Income Attributable to Southern Company	$	2,226		$	842		$	2,448
Common Stock Data:
Earnings per share —
Basic	$	2.18		$	0.84		$	2.57
Diluted	2.17			0.84			2.55
Average number of shares of common stock outstanding — (in millions)
Basic	1,020			1,000			951
Diluted	1,025			1,008			958

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

II-217

Table of Contents Index to Financial Statements

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Years Ended December 31, 2018, 2017, and 2016

Southern Company and Subsidiary Companies 2018 Annual Report



	2018			2017			2016
	(in millions)
Consolidated Net Income	$	2,300		$	926		$	2,529
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(16), $34, and $(84), respectively	(47		)	57			(136		)
Reclassification adjustment for amounts included in net income, net of tax of $24, $(37), and $43, respectively	72			(60		)	69
Pension and other postretirement benefit plans:
Benefit plan net gain (loss), net of tax of $(2), $6, and $10, respectively	(5		)	17			13
Reclassification adjustment for amounts included in net income, net of tax of $5, $(6), and $3, respectively	6			(23		)	4
Total other comprehensive income (loss)	26			(9		)	(50		)
Dividends on preferred and preference stock of subsidiaries	16			38			45
Comprehensive income attributable to noncontrolling interests	58			46			36
Consolidated Comprehensive Income Attributable to Southern Company	$	2,252		$	833		$	2,398

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

II-218

Table of Contents Index to Financial Statements

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2018, 2017, and 2016

Southern Company and Subsidiary Companies 2018 Annual Report



	2018			2017			2016
				(in millions)
Operating Activities:
Consolidated net income	$	2,300		$	926		$	2,529
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	3,549			3,457			2,923
Deferred income taxes	94			166			(127		)
Collateral deposits	17			(4		)	(102		)
Allowance for equity funds used during construction	(138		)	(160		)	(202		)
Pension and postretirement funding	(4		)	(2		)	(1,029		)
Settlement of asset retirement obligations	(244		)	(177		)	(171		)
Stock based compensation expense	125			109			121
Hedge settlements	(10		)	6			(233		)
Estimated loss on plants under construction	1,093			3,179			428
Impairment charges	210			—			—
Gain on dispositions, net	(301		)	(42		)	(2		)
Other, net	(22		)	(112		)	(219		)
Changes in certain current assets and liabilities —
-Receivables	(426		)	(202		)	(544		)
-Fossil fuel for generation	123			36			178
-Natural gas for sale	49			36			(226		)
-Other current assets	(127		)	(143		)	(206		)
-Accounts payable	291			(280		)	301
-Accrued taxes	267			(142		)	1,456
-Retail fuel cost over recovery	36			(212		)	(231		)
-Other current liabilities	63			(45		)	250
Net cash provided from operating activities	6,945			6,394			4,894
Investing Activities:
Business acquisitions, net of cash acquired	(65		)	(1,054		)	(10,680		)
Property additions	(8,001		)	(7,423		)	(7,310		)
Proceeds pursuant to the Toshiba Guarantee, net of joint owner portion	—			1,682			—
Nuclear decommissioning trust fund purchases	(1,117		)	(811		)	(1,160		)
Nuclear decommissioning trust fund sales	1,111			805			1,154
Proceeds from dispositions	2,956			97			15
Cost of removal, net of salvage	(388		)	(313		)	(245		)
Change in construction payables, net	50			259			(121		)
Investment in unconsolidated subsidiaries	(114		)	(152		)	(1,444		)
Payments pursuant to LTSAs	(186		)	(227		)	(134		)
Other investing activities	(6		)	(53		)	(122		)
Net cash used for investing activities	(5,760		)	(7,190		)	(20,047		)
Financing Activities:
Increase (decrease) in notes payable, net	(774		)	(401		)	1,228
Proceeds —
Long-term debt	2,478			5,858			16,368
Common stock	1,090			793			3,758
Preferred stock	—			250			—
Short-term borrowings	3,150			1,259			—
Redemptions and repurchases —
Long-term debt	(5,533		)	(2,930		)	(3,145		)
Preferred and preference stock	(33		)	(658		)	—
Short-term borrowings	(1,900		)	(659		)	(478		)
Distributions to noncontrolling interests	(153		)	(119		)	(72		)
Capital contributions from noncontrolling interests	2,551			80			682
Payment of common stock dividends	(2,425		)	(2,300		)	(2,104		)
Other financing activities	(264		)	(222		)	(512		)
Net cash provided from (used for) financing activities	(1,813		)	951			15,725
Net Change in Cash, Cash Equivalents, and Restricted Cash	(628		)	155			572
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year	2,147			1,992			1,420
Cash, Cash Equivalents, and Restricted Cash at End of Year	$	1,519		$	2,147		$	1,992
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $72, $89, and $128 capitalized, respectively)	$	1,794		$	1,676		$	1,066
Income taxes (net of refunds)	172			(410		)	(148		)
Noncash transactions — Accrued property additions at year-end	1,103			985			1,262

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

II-219

Table of Contents Index to Financial Statements

CONSOLIDATED BALANCE SHEETS

At December 31, 2018 and 2017

Southern Company and Subsidiary Companies 2018 Annual Report



Assets	2018			2017
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,396		$	2,130
Receivables —
Customer accounts receivable	1,726			1,806
Energy marketing receivable	801			607
Unbilled revenues	654			810
Under recovered fuel clause revenues	115			171
Other accounts and notes receivable	813			698
Accumulated provision for uncollectible accounts	(50		)	(44		)
Materials and supplies	1,465			1,438
Fossil fuel for generation	405			594
Natural gas for sale	524			595
Prepaid expenses	432			452
Assets from risk management activities, net of collateral	222			137
Other regulatory assets, current	525			604
Assets held for sale, current	393			12
Other current assets	162			62
Total current assets	9,583			10,072
Property, Plant, and Equipment:
In service	103,706			103,542
Less: Accumulated depreciation	31,038			31,457
Plant in service, net of depreciation	72,668			72,085
Nuclear fuel, at amortized cost	875			883
Construction work in progress	7,254			6,904
Total property, plant, and equipment	80,797			79,872
Other Property and Investments:
Goodwill	5,315			6,268
Equity investments in unconsolidated subsidiaries	1,580			1,513
Other intangible assets, net of amortization of $235 and $186 at December 31, 2018 and December 31, 2017, respectively	613			873
Nuclear decommissioning trusts, at fair value	1,721			1,832
Leveraged leases	798			775
Miscellaneous property and investments	269			249
Total other property and investments	10,296			11,510
Deferred Charges and Other Assets:
Deferred charges related to income taxes	794			825
Unamortized loss on reacquired debt	323			206
Other regulatory assets	8,308			6,943
Assets held for sale	5,350			—
Other deferred charges and assets	1,463			1,577
Total deferred charges and other assets	16,238			9,551
Total Assets	$	116,914		$	111,005

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

II-220

Table of Contents Index to Financial Statements

CONSOLIDATED BALANCE SHEETS

At December 31, 2018 and 2017

Southern Company and Subsidiary Companies 2018 Annual Report



Liabilities and Stockholders' Equity	2018		2017
	(in millions)
Current Liabilities:
Securities due within one year	$	3,198	$	3,892
Notes payable	2,915		2,439
Energy marketing trade payables	856		546
Accounts payable	2,580		2,530
Customer deposits	522		542
Accrued taxes	656		636
Accrued interest	472		488
Accrued compensation	1,030		959
Asset retirement obligations, current	404		351
Other regulatory liabilities, current	376		337
Liabilities held for sale, current	425		—
Other current liabilities	852		874
Total current liabilities	14,286		13,594
Long-Term Debt (See accompanying statements)	40,736		44,462
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	6,558		6,842
Deferred credits related to income taxes	6,460		7,256
Accumulated deferred ITCs	2,372		2,267
Employee benefit obligations	2,147