10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2019

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 35203

(205) 257-1000

1-6468 Georgia Power Company 58-0257110

(A Georgia Corporation)

241 Ralph McGill Boulevard, N.E.

Atlanta, Georgia 30308

(404) 506-6526

001-11229 Mississippi Power Company 64-0205820

(A Mississippi Corporation)

2992 West Beach Boulevard

Gulfport, Mississippi 39501

(228) 864-1211

001-37803 Southern Power Company 58-2598670

(A Delaware Corporation)

30 Ivan Allen Jr. Boulevard, N.W.

Atlanta, Georgia 30308

(404) 506-5000

1-14174 Southern Company Gas 58-2210952

(A Georgia Corporation)

Ten Peachtree Place, N.E.

Atlanta, Georgia 30309

(404) 584-4000

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

Registrant	Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
The Southern Company	Common Stock, par value $5 per share	SO	New York Stock Exchange
			(NYSE)
The Southern Company	Series 2015A 6.25% Junior Subordinated Notes due 2075	SOJA	NYSE
The Southern Company	Series 2016A 5.25% Junior Subordinated Notes due 2076	SOJB	NYSE
The Southern Company	Series 2017B 5.25% Junior Subordinated Notes due 2077	SOJC	NYSE
Alabama Power Company	5.00% Series Class A Preferred Stock	ALP PR Q	NYSE
Georgia Power Company	Series 2017A 5.00% Junior Subordinated Notes due 2077	GPJA	NYSE
Southern Power Company	Series 2016A 1.000% Senior Notes due 2022	SO/22B	NYSE
Southern Power Company	Series 2016B 1.850% Senior Notes due 2026	SO/26A	NYSE

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 þ 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 þ No ¨

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 þ (Response applicable to all registrants.)

Registrant	Description of Common Stock	Shares Outstanding at June 30, 2019
The Southern Company	Par Value $5 Per Share	1,045,231,646
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

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

2

INDEX TO QUARTERLY REPORT ON FORM 10-Q

June 30, 2019

		Page Number
DEFINITIONS		5
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION		9
	PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations
	The Southern Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	12
	Condensed Consolidated Statements of Comprehensive Income	13
	Condensed Consolidated Statements of Cash Flows	14
	Condensed Consolidated Balance Sheets	15
	Condensed Consolidated Statements of Stockholders' Equity	17
	Management's Discussion and Analysis of Financial Condition and Results of Operations	19
	Alabama Power Company
	Condensed Statements of Income	51
	Condensed Statements of Comprehensive Income	51
	Condensed Statements of Cash Flows	52
	Condensed Balance Sheets	53
	Condensed Statements of Common Stockholder's Equity	55
	Management's Discussion and Analysis of Financial Condition and Results of Operations	56
	Georgia Power Company
	Condensed Statements of Income	68
	Condensed Statements of Comprehensive Income	68
	Condensed Statements of Cash Flows	69
	Condensed Balance Sheets	70
	Condensed Statements of Common Stockholder's Equity	72
	Management's Discussion and Analysis of Financial Condition and Results of Operations	73
	Mississippi Power Company
	Condensed Statements of Income	94
	Condensed Statements of Comprehensive Income	94
	Condensed Statements of Cash Flows	95
	Condensed Balance Sheets	96
	Condensed Statements of Common Stockholder's Equity	98
	Management's Discussion and Analysis of Financial Condition and Results of Operations	99
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	113
	Condensed Consolidated Statements of Comprehensive Income	113
	Condensed Consolidated Statements of Cash Flows	114
	Condensed Consolidated Balance Sheets	115
	Condensed Consolidated Statements of Stockholders' Equity	117
	Management's Discussion and Analysis of Financial Condition and Results of Operations	119

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q

June 30, 2019

		Page Number
	PART I—FINANCIAL INFORMATION (CONTINUED)
	Southern Company Gas and Subsidiary Companies
	Condensed Consolidated Statements of Income	132
	Condensed Consolidated Statements of Comprehensive Income	132
	Condensed Consolidated Statements of Cash Flows	133
	Condensed Consolidated Balance Sheets	134
	Condensed Consolidated Statements of Stockholder's Equity	136
	Management's Discussion and Analysis of Financial Condition and Results of Operations	137
	Notes to the Condensed Financial Statements	160
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	49
Item 4.	Controls and Procedures	49
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	230
Item 1A.	Risk Factors	230
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	Inapplicable
Item 3.	Defaults Upon Senior Securities	Inapplicable
Item 4.	Mine Safety Disclosures	Inapplicable
Item 5.	Other Information	Inapplicable
Item 6.	Exhibits	230
	Signatures	233

4

DEFINITIONS

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
Amended and Restated Loan Guarantee Agreement	Loan guarantee agreement entered into by Georgia Power with the DOE in 2014, as amended and restated on March 22, 2019, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4
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
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
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
CPP	Clean Power Plan, the final action published by the EPA in 2015 that established guidelines for states to develop plans to meet EPA-mandated CO2 emission rates or emission reduction goals for existing electric generating units
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
DSGP	Diamond State Generation Partners
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
EPA	U.S. Environmental Protection Agency
EPC Contractor	Westinghouse and its affiliate, WECTEC Global Project Services Inc.; the former engineering, procurement, and construction contractor for Plant Vogtle Units 3 and 4
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FFB	Federal Financing Bank

5

DEFINITIONS

(continued)

Term	Meaning
Fitch	Fitch Ratings, Inc.
Form 10-K	Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas for the year ended December 31, 2018, as applicable
GAAP	U.S. generally accepted accounting principles
Georgia Power	Georgia Power Company
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, until January 1, 2019, a subsidiary of Southern Company
Heating Degree Days	A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Heating Season	The period from November through March when Southern Company Gas' natural gas usage and operating revenues are generally higher
HLBV	Hypothetical liquidation at book value
IGCC	Integrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility (Plant Ratcliffe)
IIC	Intercompany Interchange Contract
Illinois Commission	Illinois Commerce Commission
ITAAC	Inspections, Tests, Analyses, and Acceptance Criteria, standards established by the NRC
ITC	Investment tax credit
JEA	Jacksonville Electric Authority
KWH	Kilowatt-hour
LIFO	Last-in, first-out
LOCOM	Lower of weighted average cost or current market price
LTSA	Long-term service agreement
MEAG	Municipal Electric Authority of Georgia
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal units
Moody's	Moody's Investors Service, Inc.
MRA	Municipal and Rural Associations
MW	Megawatt
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
NextEra Energy	NextEra Energy, Inc.
Nicor Gas	Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas
NRC	U.S. Nuclear Regulatory Commission
NYMEX	New York Mercantile Exchange, Inc.
OATT	Open access transmission tariff
OCI	Other comprehensive income
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

6

DEFINITIONS

(continued)

Term	Meaning
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
PowerSecure	PowerSecure, Inc.
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
PPA	Power purchase agreements, as well as, for Southern Power, contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid
PSC	Public Service Commission
PTC	Production tax credit
Rate CNP	Alabama Power's Rate Certificated New Plant
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
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
SNG	Southern Natural Gas Company, L.L.C.
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, Southern Electric Generating Company, Southern Nuclear, SCS, Southern Communications Services, Inc., PowerSecure, and other subsidiaries
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company and its subsidiaries
SP Solar	SP Solar Holdings I, LP
SP Wind	SP Wind Holdings II, LLC
Tax Reform Legislation	The Tax Cuts and Jobs Act, which became effective on January 1, 2018
Toshiba	Toshiba Corporation, the parent company of Westinghouse
traditional electric operating companies	Alabama Power, Georgia Power, 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
VCM	Vogtle Construction Monitoring

7

DEFINITIONS

(continued)

Term	Meaning
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

8

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q 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, financing activities, completion dates of construction projects, matters related to the abandonment of the Kemper IGCC, completion of announced dispositions, filings with state and federal regulatory authorities, and estimated construction plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "would," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• the impact of recent and future federal and state regulatory changes, including tax and environmental laws and regulations 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 legal requirements related to CCR;

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

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

• variations in demand for electricity and natural gas;

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

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

• transmission constraints;

• effects of inflation;

• the ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of facilities, 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, and including changes in labor costs, availability, and productivity; challenges with management of contractors, subcontractors, or vendors; adverse weather conditions; shortages, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; nonperformance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel; challenges with start-up activities, including major equipment failure, system integration, or regional transmission upgrades; 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;

• 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;

9

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 construction projects, such as Plant Vogtle Units 3 and 4 and pipeline projects, including PSC approvals and FERC and NRC actions;

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

• in the event Georgia Power becomes obligated to provide funding to MEAG 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 (including the Form 10-K) filed by the registrants from time to time with the SEC.

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

10

THE SOUTHERN COMPANY

AND SUBSIDIARY COMPANIES

11

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)						(in millions)
Operating Revenues:
Retail electric revenues	$	3,540		$	3,740		$	6,623		$	7,308
Wholesale electric revenues	542			616			1,041			1,239
Other electric revenues	161			170			331			330
Natural gas revenues (includes alternative revenue programs of $1, $(4), $-, and $(27), respectively)	689			706			2,163			2,314
Other revenues	166			395			352			808
Total operating revenues	5,098			5,627			10,510			11,999
Operating Expenses:
Fuel	914			1,103			1,764			2,204
Purchased power	201			236			371			503
Cost of natural gas	191			228			877			949
Cost of other sales	84			279			203			568
Other operations and maintenance	1,316			1,523			2,628			2,972
Depreciation and amortization	755			783			1,506			1,552
Taxes other than income taxes	299			316			628			671
Estimated loss on plants under construction	4			1,060			6			1,105
(Gain) loss on dispositions, net	(8		)	36			(2,506		)	36
Total operating expenses	3,756			5,564			5,477			10,560
Operating Income	1,342			63			5,033			1,439
Other Income and (Expense):
Allowance for equity funds used during construction	31			32			63			63
Earnings from equity method investments	33			31			81			72
Interest expense, net of amounts capitalized	(429		)	(470		)	(859		)	(928		)
Other income (expense), net	99			78			176			138
Total other income and (expense)	(266		)	(329		)	(539		)	(655		)
Earnings (Loss) Before Income Taxes	1,076			(266		)	4,494			784
Income taxes (benefit)	145			(139		)	1,505			(25		)
Consolidated Net Income (Loss)	931			(127		)	2,989			809
Dividends on preferred stock of subsidiaries	3			4			7			8
Net income attributable to noncontrolling interests	29			23			—			17
Consolidated Net Income (Loss) Attributable to Southern Company	$	899		$	(154	)	$	2,982		$	784
Common Stock Data:
Earnings (loss) per share -
Basic	$	0.86		$	(0.15	)	$	2.86		$	0.77
Diluted	$	0.85		$	(0.15	)	$	2.84		$	0.77
Average number of shares of common stock outstanding (in millions)
Basic	1,044			1,014			1,041			1,012
Diluted	1,052			1,014			1,049			1,017

The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.

12

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)						(in millions)
Consolidated Net Income (Loss)	$	931		$	(127	)	$	2,989		$	809
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(11), $(18), $(21), and $(3), respectively	(32		)	(54		)	(60		)	(8		)
Reclassification adjustment for amounts included in net income, net of tax of $(1), $21, $8, and $15, respectively	(3		)	64			24			45
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $-, $1, $-, and $1, respectively	—			2			1			4
Total other comprehensive income (loss)	(35		)	12			(35		)	41
Comprehensive Income (Loss)	896			(115		)	2,954			850
Dividends on preferred stock of subsidiaries	3			4			7			8
Comprehensive income attributable to noncontrolling interests	29			23			—			17
Consolidated Comprehensive Income (Loss) Attributable to Southern Company	$	864		$	(142	)	$	2,947		$	825

The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.

13

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2019			2018
	(in millions)
Operating Activities:
Consolidated net income	$	2,989		$	809
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	1,623			1,750
Deferred income taxes	274			(338		)
Allowance for equity funds used during construction	(63		)	(63		)
Mark-to-market adjustments	31			3
Pension, postretirement, and other employee benefits	(65		)	(74		)
Settlement of asset retirement obligations	(143		)	(97		)
Stock based compensation expense	75			83
Estimated loss on plants under construction	11			1,088
(Gain) loss on dispositions, net	(2,512		)	35
Impairment charges	32			161
Other, net	(22		)	(34		)
Changes in certain current assets and liabilities —
-Receivables	653			94
-Prepayments	(53		)	(73		)
-Natural gas for sale	255			295
-Other current assets	(18		)	(40		)
-Accounts payable	(1,045		)	(406		)
-Accrued taxes	938			213
-Accrued compensation	(312		)	(284		)
-Other current liabilities	(135		)	136
Net cash provided from operating activities	2,513			3,258
Investing Activities:
Property additions	(3,484		)	(3,828		)
Nuclear decommissioning trust fund purchases	(405		)	(571		)
Nuclear decommissioning trust fund sales	400			566
Proceeds from dispositions and asset sales	5,000			500
Cost of removal, net of salvage	(197		)	(128		)
Change in construction payables, net	(107		)	49
Investment in unconsolidated subsidiaries	(134		)	(63		)
Payments pursuant to LTSAs	(64		)	(103		)
Other investing activities	(7		)	(46		)
Net cash provided from (used for) investing activities	1,002			(3,624		)
Financing Activities:
Increase in notes payable, net	83			1,442
Proceeds —
Long-term debt	1,390			1,100
Common stock	452			222
Short-term borrowings	250			1,650
Redemptions and repurchases —
Long-term debt	(2,560		)	(3,379		)
Short-term borrowings	(1,850		)	(550		)
Distributions to noncontrolling interests	(82		)	(42		)
Capital contributions from noncontrolling interests	5			1,210
Payment of common stock dividends	(1,269		)	(1,194		)
Other financing activities	(67		)	(223		)
Net cash provided from (used for) financing activities	(3,648		)	236
Net Change in Cash, Cash Equivalents, and Restricted Cash	(133		)	(130		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	1,519			2,147
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	1,386		$	2,017
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $36 and $35 capitalized for 2019 and 2018, respectively)	$	844		$	927
Income taxes, net	210			4
Noncash transactions — Accrued property additions at end of period	988			1,067

The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.

14

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2019			At December 31, 2018
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,383		$	1,396
Receivables —
Customer accounts receivable	1,654			1,726
Energy marketing receivables	361			801
Unbilled revenues	583			654
Under recovered fuel clause revenues	69			115
Other accounts and notes receivable	756			813
Accumulated provision for uncollectible accounts	(50		)	(50		)
Materials and supplies	1,440			1,465
Fossil fuel for generation	435			405
Natural gas for sale	268			524
Prepaid expenses	543			432
Assets from risk management activities, net of collateral	107			222
Other regulatory assets	607			525
Assets held for sale	58			393
Other current assets	138			162
Total current assets	8,352			9,583
Property, Plant, and Equipment:
In service	103,428			103,706
Less: Accumulated depreciation	30,693			31,038
Plant in service, net of depreciation	72,735			72,668
Nuclear fuel, at amortized cost	871			875
Construction work in progress	7,568			7,254
Total property, plant, and equipment	81,174			80,797
Other Property and Investments:
Goodwill	5,282			5,315
Equity investments in unconsolidated subsidiaries	1,557			1,580
Other intangible assets, net of amortization of $253 and $235 at June 30, 2019 and December 31, 2018, respectively	550			613
Nuclear decommissioning trusts, at fair value	1,942			1,721
Leveraged leases	813			798
Miscellaneous property and investments	505			269
Total other property and investments	10,649			10,296
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,862			—
Deferred charges related to income taxes	794			794
Unamortized loss on reacquired debt	313			323
Regulatory assets – asset retirement obligations	4,062			2,933
Other regulatory assets, deferred	5,835			5,375
Assets held for sale, deferred	685			5,350
Other deferred charges and assets	1,141			1,463
Total deferred charges and other assets	14,692			16,238
Total Assets	$	114,867		$	116,914

The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.

15

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At June 30, 2019		At December 31, 2018
	(in millions)
Current Liabilities:
Securities due within one year	$	3,148	$	3,198
Notes payable	1,398		2,915
Energy marketing trade payables	393		856
Accounts payable	1,978		2,580
Customer deposits	489		522
Accrued taxes —
Accrued income taxes	171		21
Other accrued taxes	501		635
Accrued interest	455		472
Accrued compensation	676		1,030
Asset retirement obligations	429		404
Other regulatory liabilities	304		376
Liabilities held for sale	36		425
Operating lease obligations	228		—
Other current liabilities	793		852
Total current liabilities	10,999		14,286
Long-term Debt	39,682		40,736
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	7,728		6,558
Deferred credits related to income taxes	6,386		6,460
Accumulated deferred ITCs	2,283		2,372
Employee benefit obligations	2,058		2,147
Operating lease obligations, deferred	1,702		—
Asset retirement obligations, deferred	9,478		8,990
Accrued environmental remediation	247		268
Other cost of removal obligations	2,283		2,297
Other regulatory liabilities, deferred	176		169
Liabilities held for sale, deferred	39		2,836
Other deferred credits and liabilities	384		465
Total deferred credits and other liabilities	32,764		32,562
Total Liabilities	83,445		87,584
Redeemable Preferred Stock of Subsidiaries	291		291
Total Stockholders' Equity (See accompanying statements)	31,131		29,039
Total Liabilities and Stockholders' Equity	$	114,867	$	116,914

The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.

16

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)

	Southern Company Common Stockholders' Equity
	Number of Common Shares			Common Stock											Accumulated Other Comprehensive Income (Loss)
	Issued	Treasury		Par Value		Paid-In Capital			Treasury			Retained Earnings						Noncontrolling Interests			Total
	(in millions)
Balance at December 31, 2017	1,009	(1	)	$	5,038	$	10,469		$	(36	)	$	8,885		$	(189	)	$	1,361		$	25,528
Consolidated net income attributable to Southern Company	—	—		—		—			—			938			—			—			938
Other comprehensive income	—	—		—		—			—			—			30			—			30
Stock issued	4	—		16		97			—			—			—			—			113
Stock-based compensation	—	—		—		36			—			—			—			—			36
Cash dividends of $0.58 per share	—	—		—		—			—			(586		)	—			—			(586		)
Contributions from noncontrolling interests	—	—		—		—			—			—			—			9			9
Distributions to noncontrolling interests	—	—		—		—			—			—			—			(13		)	(13		)
Net income (loss) attributable to noncontrolling interests	—	—		—		—			—			—			—			(6		)	(6		)
Other	—	—		—		1			(2		)	20			(41		)	(2		)	(24		)
Balance at March 31, 2018	1,013	(1	)	5,054		10,603			(38		)	9,257			(200		)	1,349			26,025
Consolidated net loss attributable to Southern Company	—	—		—		—			—			(154		)	—			—			(154		)
Other comprehensive income (loss)	—	—		—		—			—			—			12			—			12
Stock issued	2	—		12		97			—			—			—			—			109
Stock-based compensation	—	—		—		12			—			—			—			—			12
Cash dividends of $0.60 per share	—	—		—		—			—			(607		)	—			—			(607		)
Contributions from noncontrolling interests	—	—		—		—			—			—			—			22			22
Distributions to noncontrolling interests	—	—		—		—			—			—			—			(29		)	(29		)
Net income attributable to noncontrolling interests	—	—		—		—			—			—			—			23			23
Sale of noncontrolling interests	—	—		—		(407		)	—			—			—			1,690			1,283
Other	—	—		—		(2		)	(1		)	(2		)	—			1			(4		)
Balance at June 30, 2018	1,015	(1	)	$	5,066	$	10,303		$	(39	)	$	8,494		$	(188	)	$	3,056		$	26,692

17

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)

	Southern Company Common Stockholders' Equity
	Number of Common Shares			Common Stock										Accumulated Other Comprehensive Income (Loss)
	Issued	Treasury		Par Value		Paid-In Capital		Treasury			Retained Earnings						Noncontrolling Interests			Total
	(in millions)
Balance at December 31, 2018	1,035	(1	)	$	5,164	$	11,094	$	(38	)	$	8,706		$	(203	)	$	4,316		$	29,039
Consolidated net income attributable to Southern Company	—	—		—		—		—			2,084			—			—			2,084
Stock issued	6	—		28		196		—			—			—			—			224
Stock-based compensation	—	—		—		24		—			—			—			—			24
Cash dividends of $0.60 per share	—	—		—		—		—			(623		)	—			—			(623		)
Contributions from noncontrolling interests	—	—		—		—		—			—			—			3			3
Distributions to noncontrolling interests	—	—		—		—		—			—			—			(41		)	(41		)
Net income (loss) attributable to noncontrolling interests	—	—		—		—		—			—			—			(29		)	(29		)
Other	—	—		—		7		(2		)	—			—			1			6
Balance at March 31, 2019	1,041	(1	)	5,192		11,321		(40		)	10,167			(203		)	4,250			30,687
Consolidated net income attributable to Southern Company	—	—		—		—		—			899			—			—			899
Other comprehensive income	—	—		—		—		—			—			(35		)	—			(35		)
Stock issued	5	—		25		203		—			—			—			—			228
Stock-based compensation	—	—		—		11		—			—			—			—			11
Cash dividends of $0.62 per share	—	—		—		—		—			(646		)	—			—			(646		)
Contributions from noncontrolling interests	—	—		—		—		—			—			—			2			2
Distributions to noncontrolling interests	—	—		—		—		—			—			—			(47		)	(47		)
Net income attributable to noncontrolling interests	—	—		—		—		—			—			—			29			29
Other	—	—		—		5		(1		)	—			—			(1		)	3
Balance at June 30, 2019	1,046	(1	)	$	5,217	$	11,540	$	(41	)	$	10,420		$	(238	)	$	4,233		$	31,131

The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.

18

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2019 vs. SECOND QUARTER 2018

AND

YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018

OVERVIEW

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. Discussion of the results of operations is focused on the Southern Company system's primary businesses of 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. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas pipeline investments, wholesale gas services, and gas marketing services. The Southern Company system's other business activities include providing energy solutions, such as distributed energy infrastructure and energy efficiency products and services, to customers. Other business activities also include investments in telecommunications, leveraged lease projects, and gas storage facilities. For additional information, see BUSINESS – "The Southern Company System – Traditional Electric Operating Companies," " – Southern Power," " – Southern Company Gas," and " – Other Businesses" in Item 1 of the Form 10-K.

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. The preliminary gain associated with the sale of Gulf Power totaled $2.5 billion pre-tax ($1.3 billion after tax). See Note (K) to the Condensed Financial Statements under "Southern Company" herein for additional information.

Georgia Power and Atlanta Gas Light each filed base rate cases with the Georgia PSC in June 2019. Georgia Power's filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. Atlanta Gas Light's filing requests a $96 million increase in annual base rate revenues effective January 1, 2020. Nicor Gas filed a rate case with the Illinois Commission in November 2018, which was revised in April 2019, requesting an annual revenue increase of $180 million. These three rate cases are expected to conclude in 2019. In addition, Mississippi Power is scheduled to file a base rate case with the Mississippi PSC in the fourth quarter 2019. The ultimate outcome of these matters cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters" herein and Note 2 to the financial statements in Item 8 of the Form 10-K for additional information.

Southern Company 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.

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

19

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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. In September 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.

In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the total estimated project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.

In March 2019, Georgia Power entered into the Amended and Restated 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, up to approximately $5.130 billion. At June 30, 2019, Georgia Power had a total of $3.46 billion of borrowings outstanding under the related multi-advance credit facilities.

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

See FUTURE EARNINGS POTENTIAL – "Construction Program – Nuclear Construction" and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information.

RESULTS OF OPERATIONS

Net Income (Loss)

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$1,053	N/M	$2,198	N/M

N/M - Not meaningful

Consolidated net income attributable to Southern Company was $899 million ($0.86 per share) for the second quarter 2019 compared to a net loss of $154 million ($(0.15) per share) for the corresponding period in 2018. The change was primarily due 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 and a decrease in operations and maintenance expenses.

Consolidated net income attributable to Southern Company was $3.0 billion ($2.86 per share) for year-to-date 2019 compared to $784 million ($0.77 per share) for the corresponding period in 2018. The increase was primarily due to the $2.5 billion ($1.3 billion after tax) gain on the sale of Gulf Power in 2019 and 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

20

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Plant Vogtle Units 3 and 4. See Note (K) to the Condensed Financial Statements under "Southern Company" herein and Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information.

Retail Electric Revenues

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(200)	(5.3)	$(685)	(9.4)

In the second quarter 2019, retail electric revenues were $3.5 billion compared to $3.7 billion for the corresponding period in 2018. For year-to-date 2019, retail electric revenues were $6.6 billion compared to $7.3 billion for the corresponding period in 2018.

Details of the changes in retail electric revenues were as follows:

	Second Quarter 2019					Year-to-Date 2019
	(in millions)			(% change)		(in millions)			(% change)
Retail electric – prior year	$	3,740				$	7,308
Estimated change resulting from –
Rates and pricing	125			3.3	%	182			2.5	%
Sales decline	(30		)	(0.8	)	(41		)	(0.6	)
Weather	34			0.9		(56		)	(0.8	)
Fuel and other cost recovery	(28		)	(0.7	)	(179		)	(2.4	)
Gulf Power disposition	(301		)	(8.0	)	(591		)	(8.1	)
Retail electric – current year	$	3,540		(5.3	)%	$	6,623		(9.4	)%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily due to increased revenues at Alabama Power due to the impacts of customer bill credits related to the Tax Reform Legislation in 2018 and increases to CNP Compliance revenue, increases in the NCCR tariff effective January 1, 2019 at Georgia Power, and increases in PEP and ECO Plan rates that became effective for the first billing cycle of September 2018 at Mississippi Power. The year-to-date 2019 increase also reflects the rate pricing effect of decreased customer usage, partially offset by lower contributions from commercial and industrial customers with variable demand-driven pricing at Georgia Power.

See Note 2 to the financial statements under "Alabama Power," "Georgia Power," and "Mississippi Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.

Revenues attributable to changes in sales decreased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018. Weather-adjusted residential KWH sales decreased 1.0% and 0.3% in the second quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018 primarily due to decreased customer usage primarily resulting from an increase in energy efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 1.3% and 1.6% in the second quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018 primarily due to decreased customer usage resulting from an increase in energy saving initiatives. Industrial KWH sales decreased 2.0% in both the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals, chemicals, stone, clay, and glass, textile, and paper sectors.

Fuel and other cost recovery revenues decreased $28 million and $179 million in the second quarter and year-to-date 2019, respectively, compared to the corresponding periods in 2018 primarily due to decreases in generation and the average cost of fuel. The year-to-date decrease was also driven by milder weather in the first quarter 2019.

21

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Wholesale Electric Revenues

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(74)	(12.0)	$(198)	(16.0)

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 municipal and rural association sales under cost-based tariffs as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.

In the second quarter 2019, wholesale electric revenues were $542 million compared to $616 million for the corresponding period in 2018. For year-to-date 2019, wholesale electric revenues were $1.0 billion compared to $1.2 billion for the corresponding period in 2018. The second quarter 2019 decrease was related to a $54 million decrease in energy revenues and a $20 million decrease in capacity revenues. The year-to-date 2019 decrease was related to a $160 million decrease in energy revenues and a $38 million decrease in capacity revenues. Excluding decreases of $7 million and $13 million of energy revenues for the second quarter and year-to-date 2019, respectively, related to the sale of Gulf Power, the decreases in energy revenues primarily related to Southern Power and included a decrease in non-PPA revenues due to a decrease in the volume of KWHs sold through short-term sales and a decrease in revenues from natural gas PPAs due to a decrease in the average cost of fuel and purchased power. These decreases were also due to lower fuel prices and lower customer demand at the traditional electric operating companies. The decreases in capacity revenues primarily related to the sales of Gulf Power and Southern Power's Plant Oleander and Plant Stanton Unit A in December 2018. See Note 15 to the financial statements under "Southern Power – Sales of Natural Gas Plants" in Item 8 of the Form 10-K for additional information.

Natural Gas Revenues

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(17)	(2.4)	$(151)	(6.5)

In the second quarter 2019, natural gas revenues were $689 million compared to $706 million for the corresponding period in 2018. For year-to-date 2019, natural gas revenues were $2.2 billion compared to $2.3 billion for the corresponding period in 2018.

22

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in natural gas revenues were as follows:

	Second Quarter 2019					Year-to-Date 2019
	(in millions)			(% change)		(in millions)			(% change)
Natural gas revenues – prior year	$	706				$	2,314
Estimated change resulting from –
Infrastructure replacement programs and base rate changes	10			1.4	%	42			1.8	%
Gas costs and other cost recovery	(13		)	(1.8	)	49			2.1
Weather	(7		)	(1.1	)	—			—
Wholesale gas services	64			9.1		(16		)	(0.7	)
Southern Company Gas Dispositions	(70		)	(9.9	)	(237		)	(10.2	)
Other	(1		)	(0.1	)	11			0.5
Natural gas revenues – current year	$	689		(2.4	)%	$	2,163		(6.5	)%

Revenues attributable to infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased in the second quarter and year-to-date 2019 compared to the corresponding periods in 2018 primarily due to increases of $4 million and $25 million, respectively, at Nicor Gas and $5 million and $14 million, respectively, at Atlanta Gas Light. These amounts include the natural gas distribution utilities' continued investments recovered through infrastructure replacement programs and base rate increases as well as increases due to the impacts of the Tax Reform Legislation.

Revenues attributable to gas costs and other cost recovery decreased in the second quarter 2019 and increased year-to-date 2019 compared to the corresponding periods in 2018. The decrease in the second quarter 2019 is primarily due to lower natural gas prices and decreased volumes of natural gas sold. The increase for year-to-date 2019 is primarily due to increased natural gas prices in the first quarter 2019, partially offset by decreased volumes of natural gas sold year-to-date 2019. 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.

Revenues decreased in the second quarter 2019 due to warmer weather, as determined by Heating Degree Days, in Illinois and Georgia compared to the corresponding period in 2018.

Revenues attributable to Southern Company Gas' wholesale gas services business increased in the second quarter 2019 and decreased year-to-date 2019 compared to the corresponding periods in 2018. The increase in the second quarter 2019 is primarily due to derivative gains, partially offset by decreased commercial activity. For year-to-date 2019, the decrease is primarily due to decreased commercial activity, partially offset by derivative gains.

See Note (B) to the Condensed Financial Statements herein under "Southern Company Gas" for additional information.

Other Revenues

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(229)	(58.0)	$(456)	(56.4)

In the second quarter 2019, other revenues were $166 million compared to $395 million for the corresponding period in 2018. For year-to-date 2019, other revenues were $352 million compared to $808 million for the corresponding period in 2018. These decreases were primarily related to PowerSecure's 2018 storm restoration services in Puerto Rico.

23

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses

	Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(189	)	(17.1)	$	(440	)	(20.0)
Purchased power	(35		)	(14.8)	(132		)	(26.2)
Total fuel and purchased power expenses	$	(224	)		$	(572	)

In the second quarter 2019, total fuel and purchased power expenses were $1.1 billion compared to $1.3 billion for the corresponding period in 2018. Excluding approximately $126 million associated with the sale of Gulf Power, the decrease was primarily the result of an $81 million decrease in the average cost of fuel and purchased power and a $17 million net decrease in the aggregate volume of KWHs generated and purchased.

For year-to-date 2019, total fuel and purchased power expenses were $2.1 billion compared to $2.7 billion for the corresponding period in 2018. Excluding approximately $225 million associated with the sale of Gulf Power, the decrease was primarily the result of a $198 million decrease in the average cost of fuel and purchased power and a $149 million decrease in the aggregate 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.

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

	Second Quarter 2019	Second Quarter 2018(a)	Year-to-Date 2019	Year-to-Date 2018(a)
Total generation (in billions of KWHs)	46	47	90	93
Total purchased power (in billions of KWHs)	4	4	8	7
Sources of generation (percent) —
Gas	52	45	50	45
Coal	22	29	22	29
Nuclear	16	15	16	16
Hydro	3	3	5	3
Other	7	8	7	7
Cost of fuel, generated (in cents per net KWH)—
Gas	2.39	2.71	2.47	2.78
Coal	3.04	2.71	2.98	2.80
Nuclear	0.80	0.82	0.80	0.80
Average cost of fuel, generated (in cents per net KWH)	2.26	2.39	2.29	2.43
Average cost of purchased power (in cents per net KWH)(b)	4.89	5.18	5.04	6.11

(a) Excludes Gulf Power, which was sold on January 1, 2019.

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel

In the second quarter 2019, fuel expense was $0.9 billion compared to $1.1 billion for the corresponding period in 2018. Excluding approximately $74 million related to Gulf Power in 2018, the decrease was primarily due to a 26.2% decrease in the volume of KWHs generated by coal and an 11.8% decrease in the average cost of natural gas per KWH generated, partially offset by a 12.2% increase in the average cost of coal per KWH generated and a 12.1% increase in the volume of KWHs generated by natural gas.

For year-to-date 2019, fuel expense was $1.8 billion compared to $2.2 billion for the corresponding period in 2018. Excluding approximately $127 million related to Gulf Power in 2018, the decrease was primarily due to a 27.6% decrease in the volume of KWHs generated by coal and an 11.2% decrease in the average cost of natural gas per KWH generated, partially offset by a 6.6% increase in the volume of KWHs generated by natural gas and a 6.4% increase in the average cost of coal per KWH generated.

Purchased Power

In the second quarter 2019, purchased power expense was $201 million compared to $236 million for the corresponding period in 2018. This decrease was primarily associated with Gulf Power.

For year-to-date 2019, purchased power expense was $371 million compared to $503 million for the corresponding period in 2018. Excluding approximately $98 million associated with Gulf Power, the decrease was primarily due to a 17.5% decrease in the average cost per KWH purchased and a 2.1% decrease in the volume of KWHs purchased.

See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.

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

Cost of Natural Gas

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(37)	(16.2)	$(72)	(7.6)

Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, 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 at the natural gas distribution utilities represented 80% and 85% of total cost of natural gas for the second quarter and year-to-date 2019, respectively.

In the second quarter 2019, cost of natural gas was $191 million compared to $228 million for the corresponding period in 2018. Excluding a $25 million decrease related to the Southern Company Gas Dispositions, cost of natural gas decreased $12 million.

For year-to-date 2019, cost of natural gas was $877 million compared to $949 million for the corresponding period in 2018. Excluding a $104 million decrease related to the Southern Company Gas Dispositions, cost of natural gas increased $32 million. This increase reflects an increase in natural gas prices, partially offset by a decrease in the volume of natural gas sold year-to-date 2019 compared to the corresponding period in 2018.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cost of Other Sales

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(195)	(69.9)	$(365)	(64.3)

In the second quarter 2019, cost of other sales was $84 million compared to $279 million for the corresponding period in 2018. For year-to-date 2019, cost of other sales was $203 million compared to $568 million for the corresponding period in 2018. These decreases were primarily related to PowerSecure's 2018 storm restoration services in Puerto Rico.

Other Operations and Maintenance Expenses

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(207)	(13.6)	$(344)	(11.6)

In the second quarter 2019, other operations and maintenance expenses were $1.3 billion compared to $1.5 billion for the corresponding period in 2018. For year-to-date 2019, other operations and maintenance expenses were $2.6 billion compared to $3.0 billion for the corresponding period in 2018. The second quarter and year-to-date 2019 decreases reflect approximately $90 million and $166 million, respectively, related to Gulf Power in 2018 and $34 million and $105 million, respectively, related to the Southern Company Gas Dispositions. These decreases also reflect an asset impairment charge of $119 million recorded in the second quarter 2018 at Southern Power related to the sale of Southern Power's Florida plants. These decreases were partially offset by a $32 million goodwill impairment charge in the second quarter 2019 in contemplation of the sale of PowerSecure's utility infrastructure services business unit. See Note (K) to the Condensed Financial Statements under "Southern Company" herein and Note 15 to the financial statements under "Southern Power" and "Southern Company Gas" in Item 8 of the Form 10-K for additional information.

Depreciation and Amortization

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(28)	(3.6)	$(46)	(3.0)

In the second quarter 2019, depreciation and amortization was $755 million compared to $783 million for the corresponding period in 2018. For year-to-date 2019, depreciation and amortization was $1.5 billion compared to $1.6 billion for the corresponding period in 2018. The second quarter and year-to-date 2019 decreases were primarily due to decreases of $48 million and $95 million, respectively, related to the sale of Gulf Power and decreases of $10 million and $26 million, respectively, related to the Southern Company Gas Dispositions, partially offset by increases of $29 million and $62 million, respectively, related to additional plant in service.

Taxes Other Than Income Taxes

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(17)	(5.4)	$(43)	(6.4)

In the second quarter 2019, taxes other than income taxes were $299 million compared to $316 million for the corresponding period in 2018. For year-to-date 2019, taxes other than income taxes were $628 million compared to $671 million for the corresponding period in 2018. These decreases primarily relate to the sale of Gulf Power.

26

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Estimated Loss on Plants Under Construction

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(1,056)	(99.6)	$(1,099)	(99.5)

In the second quarter 2019, estimated loss on plants under construction was $4 million compared to $1.06 billion for the corresponding period in 2018. For year-to-date 2019, estimated loss on plants under construction was $6 million compared to $1.11 billion for the corresponding period in 2018. These decreases were primarily due to the $1.1 billion charge recorded in the second quarter 2018 as a result of Georgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4. The second quarter and year-to-date 2019 charges were related to abandonment and closure activities for the mine and gasifier-related assets of the Kemper IGCC at Mississippi Power.

See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Georgia Power – Nuclear Construction" for additional information.

(Gain) Loss on Dispositions, Net

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$44	N/M	$2,542	N/M

N/M - Not meaningful

In the second quarter 2019, gain on dispositions, net was $8 million compared to a loss on dispositions, net of $36 million in the corresponding period in 2018. This change was primarily due to a $36 million loss on the sale of Pivotal Home Solutions at Southern Company Gas recorded in 2018 and a $23 million gain as a result of the sale of Southern Power's Plant Nacogdoches in the second quarter 2019, partially offset by a $15 million adjustment to the preliminary gain on the sale of Gulf Power.

For year-to-date 2019, gain on dispositions, net was $2.5 billion compared to a loss on dispositions, net of $36 million in the corresponding period in 2018. This change was primarily due to a preliminary gain of $2.5 billion ($1.3 billion after tax) on the sale of Gulf Power.

See Note (K) to the Condensed Financial Statements under "Southern Company" herein for additional information.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(41)	(8.7)	$(69)	(7.4)

In the second quarter 2019, interest expense, net of amounts capitalized was $429 million compared to $470 million in the corresponding period in 2018. For year-to-date 2019, interest expense, net of amounts capitalized was $859 million compared to $928 million in the corresponding period in 2018. Excluding decreases of $13 million and $26 million in the second quarter and year-to-date 2019, respectively, related to the sale of Gulf Power, the decreases were primarily due to a decrease in average outstanding long-term debt, primarily at the parent company.

See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein, Note 8 to the financial statements in Item 8 of the Form 10-K, and Note (F) to the Condensed Financial Statements herein for additional information.

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Other Income (Expense), Net

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$21	26.9	$38	27.5

In the second quarter 2019, other income (expense), net was $99 million compared to $78 million for the corresponding period in 2018. For year-to-date 2019, other income (expense), net was $176 million compared to $138 million for the corresponding period in 2018. These increases were primarily due to a $36 million gain arising from the settlement of litigation related to the Roserock solar facility at Southern Power in June 2019, partially offset by $24 million due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018. Also contributing to these increases were $7 million and $13 million for the second quarter and year-to-date 2019, respectively, of non-service cost-related pension income and $10 million for year-to-date 2019 of increased interest income from temporary cash investments at the parent company. See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein and Note 3 to the financial statements under "Other Matters – Mississippi Power," in Item 8 of the Form 10-K for additional information.

Income Taxes (Benefit)

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$284	N/M	$1,530	N/M

N/M - Not meaningful

In the second quarter 2019, income taxes were $145 million compared to an income tax benefit of $139 million for the corresponding period in 2018. The change was primarily due to the reduction in pre-tax earnings in the second quarter 2018 resulting from the charge associated with Plant Vogtle Units 3 and 4 construction.

For year-to-date 2019, income taxes were $1.5 billion compared to an income tax benefit of $25 million for the corresponding period in 2018. The change was primarily due to the tax impacts related to the sale of Gulf Power and the reduction in pre-tax earnings in the second quarter 2018 resulting from the charge associated with Plant Vogtle Units 3 and 4 construction.

See Notes (G) and (K) to the Condensed Financial Statements herein for additional information.

Net Income Attributable to Noncontrolling Interests

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$6	26.1	$(17)	N/M

N/M - Not meaningful

Substantially all noncontrolling interests relate to renewable projects at Southern Power. See Notes 1 and 7 to the financial statements in Item 8 of the Form 10-K under "General" and "Southern Power," respectively, for additional information.

In the second quarter 2019, net income attributable to noncontrolling interests was $29 million compared to $23 million for the corresponding period in 2018. The increase was primarily due to an allocation of approximately $26 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement, partially offset by $25 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For year-to-date 2019, net income attributable to noncontrolling interests was immaterial compared to $17 million for the corresponding period in 2018. The decrease was primarily due to $48 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018, partially offset by an allocation of approximately $29 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Company's future earnings potential. Future earnings will be impacted by the recently completed and additional pending disposition activities described herein, in Note (K) to the Condensed Financial Statements herein, and in Note 15 to the financial statements in Item 8 of the Form 10-K. 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 June 13, 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for an aggregate cash purchase price of approximately $461 million, including working capital adjustments.

On May 4, 2019, Southern Power achieved commercial operation of the 385-MW natural gas expansion unit at Plant Mankato and started providing energy under a PPA with Northern States Power on June 1, 2019. The sale of Plant Mankato to Northern States Power remains subject to state commission approvals and is expected to close in fall 2019. If these state commission approvals are not obtained by October 1, 2019, either party has the option to

29

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

terminate the sale, which, if elected, would result in the payment of a $15 million termination fee by Northern States Power to Southern Power. The ultimate outcome of this matter cannot be determined at this time.

For additional information relating to these issues, see RISK FACTORS and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K.

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 and to achieve stated goals. 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, and may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. 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 GHG goals 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company in Item 7 and Note 3 to the financial statements under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Laws and Regulations

Coal Combustion Residuals

In June 2019, Alabama Power recorded an increase of approximately $308 million to its AROs primarily related to the CCR Rule and the related state rule based on management's completion of closure designs during the second quarter 2019 for all but two of its ash pond facilities, including one jointly owned with Mississippi Power. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and increases in the estimated ash volumes. The cost estimate for the remaining ash pond facilities will be updated within the next 12 months and the change could be material.

As further analysis is performed and additional details are developed with respect to ash pond closures, the traditional electric operating companies expect to periodically update their ARO cost estimates. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, Southern Company's results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of these matters cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Global Climate Issues

On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. Implementation of the CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule requires states to develop unit-specific CO₂ emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. The Southern Company system has ownership interests in 19 coal-fired units to which the ACE Rule is applicable. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to the Southern Company system will depend on state implementation plan requirements and the outcome of any associated legal challenges and cannot be determined at this time.

Regulatory Matters

See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.

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.

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.

Environmental Accounting Order

On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" and Note 6 in Item 8 of the Form 10-K for additional information.

Georgia Power

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery (ECCR) tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to 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.

Rate Plans

On June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These

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increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.

Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:

Tariff	2020		2021		2022
	(in millions)
Traditional base:
Levelized	$	209	$	—	$	—
CCR AROs	158		140		227
ECCR	165		—		—
Demand-Side Management	14		2		1
Municipal Franchise Fee	17		3		5
Total(*)	$	563	$	145	$	234

(*) Totals may not add due to rounding.

Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:

• Continuation of an allowed retail ROE range of 10.00% to 12.00%.

• Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the remaining one-third are retained by Georgia Power.

• Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.

Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be determined at this time.

Integrated Resource Plan

In 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan, including 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 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. In accordance with the Georgia PSC's order, costs incurred of approximately $50 million have been recorded as a regulatory asset.

On July 16, 2019, the Georgia PSC voted to approve Georgia Power's triennial Integrated Resource Plan (2019 IRP) as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.

In the 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively, at June 30, 2019), as well as any unusable materials and supplies inventory balances, upon retirement to a regulatory asset. Recovery of each unit's net book value will continue through December 31, 2019 as provided in the 2013 ARP.

For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case as follows: (i) the net book values of Plant Mitchell Unit 3 (approximately $8

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million at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The ultimate outcome of these matters cannot be determined at this time.

Also in the 2019 IRP, the Georgia PSC rejected 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. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future Integrated Resource Plan. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Southern Company's financial statements.

Additionally, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $135 million at June 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.

The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.

See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.

Mississippi Power

Kemper County Energy Facility

As the mining permit holder, Liberty Fuels Company, LLC 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 in Item 8 of the Form 10-K for additional information.

During the second quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $6 million ($5 million after tax), respectively, 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 dismantlement costs, net of salvage), 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 at $7 million for the remainder of 2019 and $2 million to $6 million annually in 2020 through 2023.

In addition, Mississippi Power constructed the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery and 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 could have a material impact on Southern Company's financial statements.

In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of 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. In connection with the DOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power

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of an investigation related to the Kemper County energy facility. The ultimate outcome of these matters cannot be determined at this time; however, they could have a material 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. With the exception of Atlanta Gas Light, which does not sell natural gas to end-use customers, 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.

In November 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% to 54% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation.

On April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with the Staff of the Illinois Commission, including a ROE of 9.86% and an equity ratio of 54%. Also on April 16, 2019, Nicor Gas filed its rebuttal testimony with the Illinois Commission incorporating the stipulation agreement and addressing the remaining items outstanding with the other two intervenors. As a result of the stipulation agreement and rebuttal testimony, the revised requested annual revenue increase is $180 million.

The Illinois Commission is expected to rule on the requested increase by early October 2019, after which rate adjustments will be effective.

On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia PSC requesting a $96 million increase in annual base rate revenues. The requested increase is based on a forward-looking test year for the 12-month period ending July 31, 2020, a ROE of 10.75% with an earnings band based on a ROE between 10.55% and 10.95%, and a continued equity ratio of 55%. The filing also requests the continuation of the Georgia rate adjustment mechanism, as previously authorized. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter on December 19, 2019 with the new rates becoming effective January 1, 2020.

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

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 Notes 2 and

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15 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" and "Southern Power," respectively, in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.

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 Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and "Nuclear Construction" herein for additional information.

Also 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

See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, the joint ownership agreements and related funding agreement, VCM reports, and the NCCR tariff.

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. In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

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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 June 30, 2019(b)	(5.2		)
Remaining estimate to complete(a)	$	3.2

(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 $2.0 billion had been incurred through June 30, 2019.

In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the estimated total project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.

As construction continues and testing and system turnover activities increase, challenges with management of contractors, subcontractors, and vendors; supervision of craft labor and related craft labor productivity, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures, or components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.

The April 2019 cost and schedule validation process established target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the approved in-service dates. To support that strategy, monthly production and activity target values will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers (particularly electrical and pipefitter craft labor), as well as additional supervision and other field support resources, must be retained and deployed.

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 submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, 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 regulatory-approved project schedule is currently estimated to result in additional base capital costs of approximately $50

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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

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

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 in conjunction with the nineteenth VCM report, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 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) 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 at pre-established prices, 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 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 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.

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 June 30, 2019, Georgia Power had recovered approximately $2.0 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. In December 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

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certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the 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 in 2018 and are estimated to have negative earnings impacts of approximately $70 million in 2019 and an aggregate of approximately $630 million from 2020 to 2022.

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.

In February 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. In March 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. In December 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.

In August 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

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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).

On April 30, 2019, as requested by the staff of the Georgia PSC, Georgia Power reported the results of the cost and schedule validation process to the Georgia PSC. On August 30, 2019, Georgia Power will file its twentieth VCM report concurrently with its twenty-first VCM report with the Georgia PSC, which will reflect the capital cost forecast discussed previously and request approval of $1.2 billion of construction capital costs incurred from June 30, 2018 through June 30, 2019. In addition, on June 20, 2019, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a settlement agreement related to the administrative claim filed in the Westinghouse bankruptcy proceedings. Accordingly, in the twentieth/twenty-first VCM report, Georgia Power will also request approval of the $51.6 million of associated expenditures previously deferred by the Georgia PSC.

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

See RISK FACTORS of Southern Company in the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.

DOE Financing

At June 30, 2019, Georgia Power had borrowed $3.46 billion related to Plant Vogtle Units 3 and 4 costs as provided through the Amended and Restated Loan Guarantee Agreement and related multi-advance credit facilities among Georgia Power, the DOE, and the FFB, which provide for borrowings of up to approximately $5.130 billion, subject to the satisfaction of certain conditions. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

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

Other Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company in Item 7 for additional information.

Southern Company and its subsidiaries are involved in various other matters that could affect future earnings, including matters being litigated, as well as other regulatory matters and matters that could result in asset impairments. 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, regulatory matters, or potential asset impairments cannot be determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) to the Condensed Financial Statements herein, 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 (B) and (C) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

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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 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 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. Also in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition. In March 2018, the court 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. In April 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. In August 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal.

In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. 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. In April 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, 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. In May 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 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 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, which were denied by the arbitration panel on May 10, 2019.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. In 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court. Georgia Power filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted in 2017. In June 2018, the Georgia Supreme Court affirmed the judgment of the Georgia Court of Appeals and remanded the case to the trial court for further proceedings. Following a motion by Georgia Power, on February 13, 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling to address certain terms the court previously held were ambiguous as used in the Georgia PSC's orders. The order entered by the Superior Court of Fulton County also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Georgia Power also filed a notice of appeal with the Georgia Court of Appeals regarding the Superior Court of Fulton County's February 2019 order. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether conditional class certification will be upheld and the ultimate composition of any class and whether any losses would be subject to recovery from any municipalities.

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

Mississippi Power

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 by the FERC and the Mississippi PSC, and cannot be determined at this time. See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.

Southern Company Gas

See Note 3 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Southern Company Gas" for information on a natural gas storage facility consisting of two salt dome caverns in Louisiana. The future performance of this facility, as well as Southern Company Gas' two other natural gas storage facilities located in California and Texas, could be impacted by ongoing changes in the U.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and may imply an impact on future rates and/or asset values. Southern Company Gas is evaluating these recent market transactions for impacts on its plans to return one of the salt dome caverns in Louisiana back to service in 2021. Sustained diminished natural gas storage values could trigger impairment of one or all of these natural gas storage facilities, which have a combined net book value of $438 million at June 30, 2019. The ultimate outcome of these matters cannot be determined at this time, but could have a material 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 Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of

41

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company's critical accounting policies and estimates.

Recently Issued Accounting Standards

See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company's recently adopted accounting standards.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at June 30, 2019. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $2.5 billion for the first six months of 2019, a decrease of $0.7 billion from the corresponding period in 2018. The decrease in net cash provided from operating activities was primarily due to the timing of vendor payments and the impacts of the Gulf Power disposition and the Southern Company Gas Dispositions. Net cash provided from investing activities totaled $1.0 billion for the first six months of 2019 primarily due to proceeds from the sale of Gulf Power, partially offset by 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. Net cash used for financing activities totaled $3.6 billion for the first six months of 2019 primarily due to repayments of short-term bank debt, net redemptions and repurchases of long-term debt, and common stock dividend payments. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities. See Notes (F) and (K) to the Condensed Financial Statements herein for additional information.

Significant balance sheet changes for the first six months of 2019 include:

• decreases in assets and liabilities held for sale of $5.0 billion and $3.2 billion, respectively, primarily related to the sale of Gulf Power;

• an increase of $2.1 billion in total stockholders' equity primarily related to the gain on the sale of Gulf Power;

• operating lease right-of-use assets, net of amortization and operating lease obligations, each totaling $1.9 billion, recorded upon the adoption of FASB ASC Topic 842, Leases;

• an increase of $1.7 billion in total property, plant, and equipment primarily related to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, partially offset by Alabama Power's reclassification of $1.4 billion to regulatory assets related to the retirement of Plant Gorgas, including $0.7 billion associated with AROs;

• decreases of $1.5 billion in notes payable and $1.1 billion in long-term debt (including amounts due within one year) related to net repayments of short-term bank debt and long-term debt, respectively; and

• an increase of $1.2 billion in accumulated deferred income taxes primarily related to the expected utilization of tax credit carryforwards in the 2019 tax year as a result of increased taxable income from the sale of Gulf Power.

42

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power" herein and Notes (A), (B), (F), (G), (K), and (L) to the Condensed Financial Statements herein for additional information.

At the end of the second quarter 2019, the market price of Southern Company's common stock was $55.28 per share (based on the closing price as reported on the NYSE) and the book value was $25.73 per share, representing a market-to-book ratio of 215%, compared to $43.92, $23.91, and 184%, respectively, at the end of 2018. Southern Company's common stock dividend for the second quarter 2019 was $0.62 per share compared to $0.60 per share in the second quarter 2018.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for a description of Southern Company's capital requirements and contractual obligations. Approximately $3.1 billion will be required through June 30, 2020 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. 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" in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions and construction projects.

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, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; nonperformance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel; challenges with start-up activities, including major equipment failure, system integration, or regional transmission upgrades; and/or operational performance. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.

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

43

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 asset sale. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information. Also see Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding the pending sale of Plant Mankato.

In addition, in 2014, Georgia Power entered into a loan guarantee agreement with the DOE and, in March 2019, entered into the Amended and Restated Loan Guarantee Agreement, 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 Amended and Restated Loan Guarantee Agreement, the DOE has agreed to guarantee the obligations of Georgia Power under note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities, under which Georgia Power may make term loan borrowings through the FFB in an amount up to approximately $5.130 billion, provided that certain conditions are met. At June 30, 2019, Georgia Power had borrowed $3.46 billion under the FFB Credit Facilities. See Notes (B) and (F) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" and "DOE Loan Guarantee Borrowings," respectively, herein for additional information.

Southern Company'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. As of June 30, 2019, Southern Company's current liabilities exceeded current assets by $2.6 billion, primarily due to long-term debt that is due within one year and notes payable totaling $4.5 billion (including approximately $0.9 billion at the parent company, $1.5 billion at Georgia Power, $0.3 billion at Mississippi Power, $0.9 billion at Southern Power, and $0.8 billion at Southern Company Gas), partially offset by $1.4 billion of cash and cash equivalents. 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.

44

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Committed credit arrangements with banks at June 30, 2019 were as follows:

	Expires
Company	2019		2020		2022		2024		Total		Unused		Due within One Year
	(in millions)
Southern Company(a)	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—
Alabama Power	3		500		—		800		1,303		1,303		3
Georgia Power	—		—		—		1,750		1,750		1,736		—
Mississippi Power	—		—		150		—		150		150		—
Southern Power(b)	—		—		—		600		600		561		—
Southern Company Gas(c)	—		—		—		1,750		1,750		1,745		—
Other	—		30		—		—		30		30		30
Southern Company Consolidated	$	3	$	530	$	150	$	6,900	$	7,583	$	7,524	$	33

(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 $30 million was unused at June 30, 2019. 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 $1.25 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.

See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

Most of these bank credit arrangements, as well as the term loan arrangements of Alabama Power, Georgia Power, and SEGCO, 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 June 30, 2019, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, Nicor Gas, and SEGCO were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

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, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of June 30, 2019 was approximately $1.4 billion. In addition, at June 30, 2019, the traditional electric operating companies had approximately $272 million of revenue bonds outstanding that are required to be remarketed within the next 12 months.

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.

45

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of short-term borrowings were as follows:

	Short-term Debt at June 30, 2019				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)
Commercial paper	$	1,148	2.6	%	$	1,173	2.8	%	$	1,562
Short-term bank debt	250		2.9	%	127		3.0	%	250
Total	$	1,398	2.7	%	$	1,300	2.8	%

(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2019.

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.

Credit Rating Risk

At June 30, 2019, 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.

The maximum potential collateral requirements under these contracts at June 30, 2019 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	30
At BBB- and/or Baa3	$	433
At BB+ and/or Ba1(*)	$	1,935

(*) 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.

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 in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information related to state PSC or other regulatory agency actions, including approvals and requests for additional or continued adjustments of capital structure related to the Tax Reform Legislation for Alabama Power, Georgia Power, Atlanta Gas Light, and Nicor Gas, which are expected to help mitigate the potential adverse impacts to certain of their credit metrics.

46

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities

During the first six months of 2019, Southern Company issued approximately 11.5 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $452 million.

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2019:

Company	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)	$	2,100	$	—	$	—	$	—	$	—
Alabama Power	200		—		—		—		—
Georgia Power	—		513		223		835		3
Mississippi Power	—		43		—		—		—
Other	—		—		25		—		9
Southern Company Consolidated	$	2,300	$	556	$	248	$	835	$	12

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

(b) Represents the Southern Company parent entity.

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 January 2019, Southern Company repaid a $250 million short-term uncommitted bank credit arrangement and a $1.5 billion short-term floating rate bank loan.

Also in January 2019, 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, following the completion of the cash tender offers, in February 2019, Southern Company completed the redemption of all of the Series 2018A Notes, 1.85% Notes, and Series 2014B Notes remaining outstanding.

As reflected in the table above, in March 2019, Georgia Power made additional borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million at an interest rate of 3.213% through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.

In June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR.

In May 2019, Southern Power repaid at maturity a $100 million aggregate principal amount short-term bank loan.

Subsequent to June 30, 2019, Nicor Gas repaid at maturity $50 million aggregate principal amount of 4.7% first mortgage bonds due July 30, 2019.

47

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

48

PART I

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

During the six months ended June 30, 2019, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas herein. For an in-depth discussion of each registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each registrant in Item 7 of the Form 10-K and Note 1 to the financial statements under "Financial Instruments" and Notes 13 and 14 to the financial statements in Item 8 of the Form 10-K. Also see Notes (I) and (J) to the Condensed Financial Statements herein for information relating to derivative instruments.

Item 4. Controls and Procedures.

(a) Evaluation of disclosure controls and procedures.

As of the end of the period covered by this Quarterly Report on Form 10-Q, Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.

(b) Changes in internal controls over financial reporting.

There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the second quarter 2019 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting.

49

ALABAMA POWER COMPANY

50

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,378		$	1,338		$	2,592		$	2,624
Wholesale revenues, non-affiliates	62			65			123			139
Wholesale revenues, affiliates	4			31			63			82
Other revenues	69			69			143			131
Total operating revenues	1,513			1,503			2,921			2,976
Operating Expenses:
Fuel	252			347			553			672
Purchased power, non-affiliates	47			48			84			113
Purchased power, affiliates	69			43			90			80
Other operations and maintenance	402			402			812			788
Depreciation and amortization	200			189			399			379
Taxes other than income taxes	98			94			200			192
Total operating expenses	1,068			1,123			2,138			2,224
Operating Income	445			380			783			752
Other Income and (Expense):
Allowance for equity funds used during construction	14			14			28			27
Interest expense, net of amounts capitalized	(82		)	(80		)	(165		)	(158		)
Other income (expense), net	11			12			25			15
Total other income and (expense)	(57		)	(54		)	(112		)	(116		)
Earnings Before Income Taxes	388			326			671			636
Income taxes	89			64			151			145
Net Income	299			262			520			491
Dividends on Preferred Stock	3			3			7			7
Net Income After Dividends on Preferred Stock	$	296		$	259		$	513		$	484

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
	(in millions)				(in millions)
Net Income	$	299	$	262	$	520	$	491
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $1, and $1, respectively	1		1		2		2
Total other comprehensive income (loss)	1		1		2		2
Comprehensive Income	$	300	$	263	$	522	$	493

The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

51

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2019			2018
	(in millions)
Operating Activities:
Net income	$	520		$	491
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	493			452
Deferred income taxes	138			48
Allowance for equity funds used during construction	(28		)	(27		)
Pension, postretirement, and other employee benefits	(13		)	(28		)
Settlement of asset retirement obligations	(43		)	(19		)
Other, net	(1		)	(21		)
Changes in certain current assets and liabilities —
-Receivables	6			(153		)
-Prepayments	(59		)	(57		)
-Materials and supplies	5			(47		)
-Other current assets	(10		)	29
-Accounts payable	(246		)	(196		)
-Accrued taxes	8			134
-Accrued compensation	(88		)	(70		)
-Other current liabilities	13			116
Net cash provided from operating activities	695			652
Investing Activities:
Property additions	(833		)	(997		)
Nuclear decommissioning trust fund purchases	(139		)	(131		)
Nuclear decommissioning trust fund sales	139			131
Cost of removal, net of salvage	(48		)	(34		)
Change in construction payables	(103		)	(29		)
Other investing activities	(18		)	(15		)
Net cash used for investing activities	(1,002		)	(1,075		)
Financing Activities:
Proceeds —
Senior notes	—			500
Capital contributions from parent company	1,254			488
Redemptions — Senior notes	(200		)	—
Payment of common stock dividends	(422		)	(402		)
Other financing activities	(15		)	(21		)
Net cash provided from financing activities	617			565
Net Change in Cash, Cash Equivalents, and Restricted Cash	310			142
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	313			544
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	623		$	686
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $10 and $10 capitalized for 2019 and 2018, respectively)	$	154		$	143
Income taxes, net	63			17
Noncash transactions — Accrued property additions at end of period	168			216

The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

52

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2019			At December 31, 2018
	(in millions)
Current Assets:
Cash and cash equivalents	$	623		$	313
Receivables —
Customer accounts receivable	432			403
Unbilled revenues	173			150
Affiliated	38			94
Other accounts and notes receivable	55			51
Accumulated provision for uncollectible accounts	(10		)	(10		)
Fossil fuel stock	143			141
Materials and supplies	530			546
Prepaid expenses	170			66
Other regulatory assets	204			137
Other current assets	26			18
Total current assets	2,384			1,909
Property, Plant, and Equipment:
In service	29,070			30,402
Less: Accumulated provision for depreciation	9,397			9,988
Plant in service, net of depreciation	19,673			20,414
Nuclear fuel, at amortized cost	322			324
Construction work in progress	1,097			1,113
Total property, plant, and equipment	21,092			21,851
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	64			65
Nuclear decommissioning trusts, at fair value	964			847
Miscellaneous property and investments	129			127
Total other property and investments	1,157			1,039
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	152			—
Deferred charges related to income taxes	240			240
Deferred under recovered regulatory clause revenues	25			116
Regulatory assets – asset retirement obligations	1,016			147
Other regulatory assets, deferred	1,824			1,240
Other deferred charges and assets	177			188
Total deferred charges and other assets	3,434			1,931
Total Assets	$	28,067		$	26,730

The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

53

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2019		At December 31, 2018
	(in millions)
Current Liabilities:
Securities due within one year	$	1	$	201
Accounts payable —
Affiliated	321		364
Other	334		614
Customer deposits	98		96
Accrued taxes	102		44
Accrued interest	88		89
Accrued compensation	140		227
Asset retirement obligations	156		163
Other current liabilities	155		161
Total current liabilities	1,395		1,959
Long-term Debt	7,926		7,923
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,117		2,962
Deferred credits related to income taxes	2,006		2,027
Accumulated deferred ITCs	103		106
Employee benefit obligations	309		314
Operating lease obligations	137		—
Asset retirement obligations, deferred	3,389		3,047
Other cost of removal obligations	464		497
Other regulatory liabilities	69		69
Other deferred credits and liabilities	32		58
Total deferred credits and other liabilities	9,626		9,080
Total Liabilities	18,947		18,962
Redeemable Preferred Stock	291		291
Common Stockholder's Equity (See accompanying statements)	8,829		7,477
Total Liabilities and Stockholder's Equity	$	28,067	$	26,730

The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

54

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (UNAUDITED)

	Number of Common Shares Issued	Common Stock		Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	(in millions)
Balance at December 31, 2017	31	$	1,222	$	2,986	$	2,647		$	(26	)	$	6,829
Net income after dividends on preferred stock	—	—		—		225			—			225
Capital contributions from parent company	—	—		488		—			—			488
Other comprehensive income (loss)	—	—		—		—			1			1
Cash dividends on common stock	—	—		—		(202		)	—			(202		)
Other	—	—		—		—			(6		)	(6		)
Balance at March 31, 2018	31	1,222		3,474		2,670			(31		)	7,335
Net income after dividends on preferred stock	—	—		—		259			—			259
Capital contributions from parent company	—	—		5		—			—			5
Other comprehensive income (loss)	—	—		—		—			1			1
Cash dividends on common stock	—	—		—		(200		)	—			(200		)
Other	—	—		1		—			—			1
Balance at June 30, 2018	31	$	1,222	$	3,480	$	2,729		$	(30	)	$	7,401
Balance at December 31, 2018	31	$	1,222	$	3,508	$	2,775		$	(28	)	$	7,477
Net income after dividends on preferred stock	—	—		—		217			—			217
Capital contributions from parent company	—	—		1,236		—			—			1,236
Other comprehensive income (loss)	—	—		—		—			1			1
Cash dividends on common stock	—	—		—		(211		)	—			(211		)
Balance at March 31, 2019	31	1,222		4,744		2,781			(27		)	8,720
Net income after dividends on preferred stock	—	—		—		296			—			296
Capital contributions from parent company	—	—		23		—			—			23
Other comprehensive income (loss)	—	—		—		—			1			1
Cash dividends on common stock	—	—		—		(211		)	—			(211		)
Balance at June 30, 2019	31	$	1,222	$	4,767	$	2,866		$	(26	)	$	8,829

The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.

55

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2019 vs. SECOND QUARTER 2018

AND

YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018

OVERVIEW

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 in addition to wholesale customers in the Southeast.

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.

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.

RESULTS OF OPERATIONS

Net Income

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$37	14.3	$29	6.0

Alabama Power's net income after dividends on preferred stock for the second quarter 2019 was $296 million compared to $259 million for the corresponding period in 2018. The increase was primarily related to an increase in retail revenues associated with the impacts of customer bill credits issued in 2018 related to the Tax Reform Legislation, as well as additional capital investments recovered through Rate CNP Compliance, partially offset by a decrease in retail revenues associated with customer usage.

Alabama Power's net income after dividends on preferred stock for year-to-date 2019 was $513 million compared to $484 million for the corresponding period in 2018. This increase was primarily related to an increase in retail revenues associated with the impacts of customer bill credits issued in 2018 related to the Tax Reform Legislation, as well as additional capital investments recovered through Rate CNP Compliance. This increase was partially offset by decreases in retail revenues associated with milder weather and lower customer usage as well as increases to operations and maintenance expenses and depreciation.

See Note 2 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K for additional information.

56

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$40	3.0	$(32)	(1.2)

In the second quarter 2019, retail revenues were $1.38 billion compared to $1.34 billion for the corresponding period in 2018. For year-to-date 2019, retail revenues were $2.59 billion compared to $2.62 billion for the corresponding period in 2018.

Details of the changes in retail revenues were as follows:

	Second Quarter 2019					Year-to-Date 2019
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	1,338				$	2,624
Estimated change resulting from –
Rates and pricing	62			4.7	%	96			3.7	%
Sales decline	(15		)	(1.1	)	(31		)	(1.2	)
Weather	6			0.4		(19		)	(0.7	)
Fuel and other cost recovery	(13		)	(1.0	)	(78		)	(3.0	)
Retail – current year	$	1,378		3.0	%	$	2,592		(1.2	)%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily due to the impacts of customer bill credits related to the Tax Reform Legislation in 2018, as well as additional capital investments recovered through Rate CNP Compliance. See Note 2 to the financial statements under "Alabama Power – Rate RSE" and " – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.

Revenues attributable to changes in sales decreased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018. Weather-adjusted residential KWH sales decreased 1.5% and 2.0% in the second quarter and year-to-date 2019, respectively, and weather-adjusted commercial KWH sales decreased 1.2% and 2.3% in the second quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018. These decreases primarily resulted from customer initiatives in energy savings for commercial customers and more energy-efficient residential appliances. Industrial KWH sales decreased 3.2% and 3.1% in the second quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals and chemicals sectors for the second quarter 2019 and primary metals, chemicals, and paper sectors for year-to-date 2019.

Residential and commercial sales revenues decreased year-to-date 2019 by 1.2% and 0.7%, respectively, due to milder weather in the first quarter 2019 when compared to the corresponding period in 2018.

Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily due to a decrease in generation and the average cost of fuel.

Electric rates include provisions to recognize the full 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 Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

57

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Non-Affiliates

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(3)	(4.6)	$(16)	(11.5)

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 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 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.

For year-to-date 2019, wholesale revenues from sales to non-affiliates were $123 million compared to $139 million for the corresponding period in 2018. The decrease was primarily due to a 7.1% decrease in KWH sales as a result of lower demand and a 4.8% decrease in the price of energy due to lower natural gas prices in 2019 compared to the corresponding period in 2018.

Wholesale Revenues – Affiliates

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(27)	(87.1)	$(19)	(23.2)

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 and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.

In the second quarter 2019, wholesale revenues from sales to affiliates were $4 million compared to $31 million for the corresponding period in 2018. The decrease was primarily due to an 87.4% decrease in KWH sales as a result of decreased coal generation associated with the retirement of Plant Gorgas Units 8, 9, and 10 and a 6.7% decrease in the price of energy as a result of lower natural gas prices in the second quarter 2019 compared to the corresponding period in 2018.

For year-to-date 2019, wholesale revenues from sales to affiliates were $63 million compared to $82 million for the corresponding period in 2018. The decrease was primarily due to a 13.1% decrease in KWH sales as a result of decreased coal generation associated with the retirement of Plant Gorgas Units 8, 9, and 10 and an 11.0% decrease in the price of energy due to increased hydro generation in 2019 as compared to the corresponding period in 2018.

58

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses

	Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(95	)	(27.4)	$	(119	)	(17.7	)
Purchased power – non-affiliates	(1		)	(2.1)	(29		)	(25.7	)
Purchased power – affiliates	26			60.5	10			12.5
Total fuel and purchased power expenses	$	(70	)		$	(138	)

In the second quarter 2019, fuel and purchased power expenses were $368 million compared to $438 million for the corresponding period in 2018. For year-to-date 2019, fuel and purchased power expenses were $727 million compared to $865 million for the corresponding period in 2018. These decreases were primarily related to the volume of KWHs generated (excluding hydro) and purchased.

Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information.

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

	Second Quarter 2019	Second Quarter 2018	Year-to-Date 2019	Year-to-Date 2018
Total generation (in billions of KWHs)	12	15	29	31
Total purchased power (in billions of KWHs)	3	2	4	3
Sources of generation (percent) —
Coal	43	53	43	52
Nuclear	26	20	24	21
Gas	23	20	21	19
Hydro	8	7	12	8
Cost of fuel, generated (in cents per net KWH) — (a)
Coal	2.86	2.79	2.82	2.74
Nuclear	0.78	0.80	0.78	0.77
Gas	2.48	2.51	2.53	2.69
Average cost of fuel, generated (in cents per net KWH)(a)(b)	2.18	2.31	2.19	2.27
Average cost of purchased power (in cents per net KWH)(c)	4.01	4.72	4.45	5.72

(a) In the second quarter and year-to-date 2018, cost of fuel and average cost of fuel, generated exclude a $30 million adjustment in accordance with an Alabama PSC accounting order. See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K 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

In the second quarter 2019, fuel expense was $252 million compared to $347 million for the corresponding period in 2018. The decrease was primarily due to a 31.3% decrease in the volume of KWHs generated by coal and an 11.9% increase in the volume of KWHs generated by nuclear.

59

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For year-to-date 2019, fuel expense was $553 million compared to $672 million for the corresponding period in 2018. The decrease was primarily due to a 45.3% increase in the volume of KWHs generated by hydro, a 21.9% decrease in the volume of KWHs generated by coal, a 5.1% increase in the volume of KWHs generated by nuclear, and a 6.0% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements.

In addition, fuel expense increased $30 million in both the second quarter and year-to-date 2018 in accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes to offset under recovered fuel costs (Tax Reform Accounting Order). See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information.

Purchased Power – Non-Affiliates

For year-to-date 2019, purchased power expense from non-affiliates was $84 million compared to $113 million for the corresponding period in 2018. The decrease was primarily related to a 14.3% decrease in the average cost of purchased power per KWH due to lower natural gas prices and an 11.9% decrease in the amount of energy purchased due to milder weather in the first quarter 2019 compared to the corresponding period in 2018.

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

In the second quarter 2019, purchased power expense from affiliates was $69 million compared to $43 million for the corresponding period in 2018. For year-to-date 2019, purchased power expense from affiliates was $90 million compared to $80 million for the corresponding period in 2018. These increases were primarily related to the availability of lower-cost generation compared to Alabama Power's owned generation and a decrease in coal generation as a result of the retirement of Plant Gorgas Units 8, 9, and 10.

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

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$24	3.0

For year-to-date 2019, other operations and maintenance expenses were $812 million compared to $788 million for the corresponding period in 2018. This increase was primarily due to increases of $15 million in Rate CNP Compliance-related expenses and $13 million in steam generation costs primarily due to the timing of outages.

Depreciation and Amortization

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$11	5.8	$20	5.3

In the second quarter 2019, depreciation and amortization was $200 million compared to $189 million for the corresponding period in 2018. For year-to-date 2019, depreciation and amortization was $399 million compared to $379 million for the corresponding period in 2018. These increases were primarily due to additional plant in service associated with steam, distribution, and transmission.

60

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Income (Expense), Net

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(8.3)	$10	66.7

For year-to-date 2019, other income (expense), net was $25 million compared to $15 million for the corresponding period in 2018. This increase was primarily due to increases in interest income from temporary cash investments and non-service cost-related pension income.

Income Taxes

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$25	39.1	$6	4.1

In the second quarter 2019, income taxes were $89 million compared to $64 million for the corresponding period in 2018. This increase was primarily due to higher pre-tax earnings in the second quarter 2019 compared to the corresponding period in 2018 and the application of the Tax Reform Accounting Order in 2018. See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Alabama Power's 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. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.

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 and to achieve stated goals. 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, and may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. These costs are being collected through existing ratemaking and billing provisions. The ultimate impact of environmental laws and regulations and GHG

61

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

goals 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. 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 MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 of the Form 10-K and Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance" and Note 3 to the financial statements under "Environmental Remediation" in Item 8 of the Form 10-K for additional information.

Environmental Laws and Regulations

Coal Combustion Residuals

In June 2019, Alabama Power recorded an increase of approximately $308 million to its AROs primarily related to the CCR Rule and the related state rule based on management's completion of closure designs during the second quarter 2019 for all but two of its ash pond facilities. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and increases in the estimated ash volumes. The cost estimate for the remaining ash pond facilities will be updated within the next 12 months and the change could be material.

As further analysis is performed and additional details are developed with respect to all ash pond closures, Alabama Power expects to periodically update these cost estimates as necessary. Additionally, the closure designs and plans are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, Alabama Power's results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

Global Climate Issues

On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. Implementation of the CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule requires states to develop unit-specific CO₂ emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. Alabama Power has ownership interests in seven coal-fired units to which the ACE Rule is applicable. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to Alabama Power will depend on state implementation plan requirements and the outcome of any associated legal challenges and cannot be determined at this time.

FERC Matters

See Note 2 to the financial statements under "FERC Matters – Open Access Transmission Tariff" in Item 8 of the Form 10-K for additional information.

On June 28, 2019, the FERC approved a settlement agreement between Alabama Municipal Electric Authority and Cooperative Energy and SCS and the traditional electric operating companies (including Alabama Power) agreeing to an OATT rate reduction based on a 10.6% ROE, with a retroactive effective date of May 10, 2018, and a five-year moratorium on these parties seeking changes to the OATT formula rate. The terms of the OATT settlement agreement will not have a material impact on the financial statements of Alabama Power.

62

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Regulatory Matters

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" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information regarding Alabama Power's rate mechanisms, accounting orders, and the recovery balance of each regulatory clause for Alabama Power.

Environmental Accounting Order

On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" and Note 6 in Item 8 of the Form 10-K for additional information.

Other Matters

Alabama Power is involved in various other matters that could affect future earnings, including matters being litigated and regulatory matters. 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.

The ultimate outcome of such pending or potential litigation or regulatory matters cannot be determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) to the Condensed Financial Statements herein, 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 (B) and (C) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

In response to changing customer expectations, payment patterns, and ongoing efforts to increase overall operating efficiencies, Alabama Power initiated a plan to close 40 of its 86 payment offices by the end of 2019. Charges associated with these activities are not expected to have a material impact on Alabama Power's financial statements.

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 Item 8 of the Form 10-K. 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power's critical accounting policies and estimates.

63

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Recently Issued Accounting Standards

See Note (A) to the Condensed Financial Statements herein for information regarding Alabama Power's recently adopted accounting standards.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at June 30, 2019. 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 "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $695 million for the first six months of 2019, an increase of $43 million as compared to the first six months of 2018. The increase in net cash provided from operating activities was primarily due to increased fuel cost recovery, partially offset by the prior year impacts of customer billing reductions related to the Tax Reform Legislation. Net cash used for investing activities totaled $1.0 billion for the first six months of 2019 primarily related to additional capital expenditures for distribution, environmental, and transmission assets. Net cash provided from financing activities totaled $617 million for the first six months of 2019 primarily due to capital contributions from Southern Company, partially offset by a payment of common stock dividends and a long-term debt maturity. Fluctuations in cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2019 include increases of $869 million in regulatory assets associated with AROs and $584 million in other regulatory assets, deferred and a decrease of $759 million in property, plant, and equipment. These changes were primarily due to the impacts of retiring and reclassifying Plant Gorgas Units 8, 9, and 10. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Alabama Power – Environmental Accounting Order" for additional information. Other significant increases include $1.4 billion in total common stockholder's equity, primarily due to a $1.2 billion capital contribution from Southern Company, $342 million in asset retirement obligations, deferred due to an increase in the ARO estimate primarily related to ash pond facilities, and $310 million in cash and cash equivalents. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements and contractual obligations. There are no scheduled maturities of long-term debt through June 30, 2020.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's environmental compliance strategy.

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 the expected environmental compliance program; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the

64

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

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. In January 2019, Alabama Power received a capital contribution totaling $1.225 billion from Southern Company. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.

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 June 30, 2019, Alabama Power had approximately $623 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2019 were as follows:

Expires
2019		2020		2024		Total		Unused
(in millions)
$	3	$	500	$	800	$	1,303	$	1,303

See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

As reflected in the table above, in May 2019, Alabama Power amended its $800 million multi-year credit arrangement, which, among other things, extended the maturity date from 2022 to 2024.

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 June 30, 2019, 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.

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 approximately $854 million as of June 30, 2019. At June 30, 2019, Alabama Power had $87 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

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. Short-term borrowings are included in notes payable in the balance sheets.

65

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of short-term borrowings were as follows:

	Short-term Debt During the Period(*)
	Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)
Commercial paper	$	26	2.6	%	$	190

(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2019. No short-term debt was outstanding at June 30, 2019.

Alabama Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.

Credit Rating Risk

At June 30, 2019, 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.

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. At June 30, 2019, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 totaled approximately $359 million.

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.

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" in Item 8 of the Form 10-K for additional information.

Financing Activities

In February 2019, 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.

66

GEORGIA POWER COMPANY

67

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,946		$	1,889		$	3,614		$	3,688
Wholesale revenues, non-affiliates	33			36			62			80
Wholesale revenues, affiliates	3			3			5			13
Other revenues	135			120			270			227
Total operating revenues	2,117			2,048			3,951			4,008
Operating Expenses:
Fuel	390			378			689			790
Purchased power, non-affiliates	124			111			242			233
Purchased power, affiliates	134			178			310			349
Other operations and maintenance	463			457			913			863
Depreciation and amortization	244			230			483			458
Taxes other than income taxes	115			106			220			214
Estimated loss on Plant Vogtle Units 3 and 4	—			1,060			—			1,060
Total operating expenses	1,470			2,520			2,857			3,967
Operating Income (Loss)	647			(472		)	1,094			41
Other Income and (Expense):
Interest expense, net of amounts capitalized	(105		)	(102		)	(201		)	(208		)
Other income (expense), net	35			35			77			73
Total other income and (expense)	(70		)	(67		)	(124		)	(135		)
Earnings (Loss) Before Income Taxes	577			(539		)	970			(94		)
Income taxes (benefit)	129			(143		)	211			(50		)
Net Income (Loss)	$	448		$	(396	)	$	759		$	(44	)

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)						(in millions)
Net Income (Loss)	$	448		$	(396	)	$	759		$	(44	)
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(9), $-, $(9), and $-, respectively	(28		)	—			(28		)	—
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $-, and $1, respectively	1			1			1			2
Total other comprehensive income (loss)	(27		)	1			(27		)	2
Comprehensive Income (Loss)	$	421		$	(395	)	$	732		$	(42	)

The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

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GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2019			2018
	(in millions)
Operating Activities:
Net income (loss)	$	759		$	(44	)
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	583			562
Deferred income taxes	153			(256		)
Pension, postretirement, and other employee benefits	(56		)	(47		)
Settlement of asset retirement obligations	(76		)	(49		)
Estimated loss on Plant Vogtle Units 3 and 4	—			1,060
Other, net	—			29
Changes in certain current assets and liabilities —
-Receivables	(43		)	(103		)
-Fossil fuel stock	(26		)	38
-Prepaid income taxes	63			115
-Other current assets	22			25
-Accounts payable	(94		)	(87		)
-Accrued taxes	(139		)	(89		)
-Accrued compensation	(32		)	(56		)
-Other current liabilities	(2		)	(26		)
Net cash provided from operating activities	1,112			1,072
Investing Activities:
Property additions	(1,712		)	(1,501		)
Nuclear decommissioning trust fund purchases	(266		)	(440		)
Nuclear decommissioning trust fund sales	260			435
Cost of removal, net of salvage	(107		)	(50		)
Change in construction payables, net of joint owner portion	(5		)	86
Payments pursuant to LTSAs	(9		)	(46		)
Proceeds from dispositions and asset sales	9			134
Other investing activities	(4		)	(11		)
Net cash used for investing activities	(1,834		)	(1,393		)
Financing Activities:
Increase in notes payable, net	11			480
Proceeds —
FFB loan	835			—
Pollution control revenue bonds	513			—
Short-term borrowings	250			—
Capital contributions from parent company	46			1,502
Redemptions and repurchases —
Senior notes	—			(1,000		)
Pollution control revenue bonds	(223		)	(398		)
Short-term borrowings	—			(150		)
Other long-term debt	—			(100		)
Payment of common stock dividends	(788		)	(691		)
Premiums on redemption and repurchases of senior notes	—			(152		)
Other financing activities	(24		)	(11		)
Net cash provided from (used for) financing activities	620			(520		)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(102		)	(841		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	112			852
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	10		$	11
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $16 and $12 capitalized for 2019 and 2018, respectively)	$	179		$	211
Income taxes, net	(6		)	64
Noncash transactions — Accrued property additions at end of period	650			669

The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

69

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2019			At December 31, 2018
	(in millions)
Current Assets:
Cash and cash equivalents	$	10		$	4
Restricted cash and cash equivalents	—			108
Receivables —
Customer accounts receivable	603			591
Unbilled revenues	267			208
Under recovered fuel clause revenues	69			115
Joint owner accounts receivable	178			170
Affiliated	16			39
Other accounts and notes receivable	240			80
Accumulated provision for uncollectible accounts	(2		)	(2		)
Fossil fuel stock	257			231
Materials and supplies	513			519
Prepaid expenses	68			142
Other regulatory assets	240			199
Other current assets	58			70
Total current assets	2,517			2,474
Property, Plant, and Equipment:
In service	38,517			37,675
Less: Accumulated provision for depreciation	12,140			12,096
Plant in service, net of depreciation	26,377			25,579
Nuclear fuel, at amortized cost	549			550
Construction work in progress	5,193			4,833
Total property, plant, and equipment	32,119			30,962
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	51			51
Nuclear decommissioning trusts, at fair value	978			873
Miscellaneous property and investments	74			72
Total other property and investments	1,103			996
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,492			—
Deferred charges related to income taxes	518			517
Regulatory assets – asset retirement obligations	2,839			2,644
Other regulatory assets, deferred	2,272			2,258
Other deferred charges and assets	379			514
Total deferred charges and other assets	7,500			5,933
Total Assets	$	43,239		$	40,365

The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

70

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2019		At December 31, 2018
	(in millions)
Current Liabilities:
Securities due within one year	$	988	$	617
Notes payable	555		294
Accounts payable —
Affiliated	477		575
Other	901		890
Customer deposits	282		276
Accrued taxes	238		377
Accrued interest	112		105
Accrued compensation	163		221
Asset retirement obligations	240		202
Other regulatory liabilities	145		169
Other current liabilities	383		183
Total current liabilities	4,484		3,909
Long-term Debt	10,150		9,364
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,212		3,062
Deferred credits related to income taxes	3,078		3,080
Accumulated deferred ITCs	257		262
Employee benefit obligations	550		599
Operating lease obligations	1,377		—
Asset retirement obligations, deferred	5,643		5,627
Other deferred credits and liabilities	172		139
Total deferred credits and other liabilities	14,289		12,769
Total Liabilities	28,923		26,042
Common Stockholder's Equity (See accompanying statements)	14,316		14,323
Total Liabilities and Stockholder's Equity	$	43,239	$	40,365

The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

71

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (UNAUDITED)

	Number of Common Shares Issued	Common Stock		Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	(in millions)
Balance at December 31, 2017	9	$	398	$	7,328		$	4,215		$	(10	)	$	11,931
Net income	—	—		—			352			—			352
Capital contributions from parent company	—	—		1,476			—			—			1,476
Other comprehensive income (loss)	—	—		—			—			1			1
Cash dividends on common stock	—	—		—			(339		)	—			(339		)
Other	—	—		1			—			(2		)	(1		)
Balance at March 31, 2018	9	398		8,805			4,228			(11		)	13,420
Net loss	—	—		—			(396		)	—			(396		)
Capital contributions from parent company	—	—		29			—			—			29
Other comprehensive income (loss)	—	—		—			—			1			1
Cash dividends on common stock	—	—		—			(352		)	—			(352		)
Balance at June 30, 2018	9	$	398	$	8,834		$	3,480		$	(10	)	$	12,702
Balance at December 31, 2018	9	$	398	$	10,322		$	3,612		$	(9	)	$	14,323
Net income	—	—		—			311			—			311
Capital contributions from parent company	—	—		29			—			—			29
Other comprehensive income (loss)	—	—		—			—			1			1
Cash dividends on common stock	—	—		—			(394		)	—			(394		)
Other	—	—		(1		)	—			—			(1		)
Balance at March 31, 2019	9	398		10,350			3,529			(8		)	14,269
Net income	—	—		—			448			—			448
Capital contributions from parent company	—	—		20			—			—			20
Other comprehensive income (loss)	—	—		—			—			(27		)	(27		)
Cash dividends on common stock	—	—		—			(394		)	—			(394		)
Other	—	—		1			(1		)	—			—
Balance at June 30, 2019	9	$	398	$	10,371		$	3,582		$	(35	)	$	14,316

The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

72

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2019 vs. SECOND QUARTER 2018

AND

YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018

OVERVIEW

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 June 28, 2019, Georgia Power filed a base rate case with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. The ultimate outcome of this matter cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" – "Rate Plans" herein for additional information.

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.

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.

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. In September 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

73

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

entered into certain amendments to their joint ownership agreements to implement the provisions of the Vogtle Owner Term Sheet.

In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the total estimated project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.

In March 2019, Georgia Power entered into the Amended and Restated 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, up to approximately $5.130 billion. At June 30, 2019, Georgia Power had a total of $3.46 billion of borrowings outstanding under the related multi-advance credit facilities.

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

See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information.

RESULTS OF OPERATIONS

Net Income (Loss)

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$844	N/M	$803	N/M

N/M - Not meaningful

Georgia Power's net income for the second quarter 2019 was $448 million compared to a net loss of $396 million for the corresponding period in 2018. The change was primarily due 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 and an increase in retail revenues associated with an increase in the NCCR tariff effective January 1, 2019 and warmer weather in the second quarter 2019 compared to the corresponding period in 2018.

For year-to-date 2019, net income was $759 million compared to a net loss of $44 million for the corresponding period in 2018. The change was primarily due 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, an increase in other revenues primarily related to unregulated new energy conservation project sales, and an increase in retail revenues associated with an increase in the NCCR tariff effective January 1, 2019. Partially offsetting the change was a decrease in retail revenues associated with milder weather in the first quarter 2019 compared to the corresponding period in 2018 and higher non-fuel operations and maintenance expenses.

Retail Revenues

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$57	3.0	$(74)	(2.0)

In the second quarter 2019, retail revenues were $1.95 billion compared to $1.89 billion for the corresponding period in 2018. For year-to-date 2019, retail revenues were $3.61 billion compared to $3.69 billion for the corresponding period in 2018.

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Details of the changes in retail revenues were as follows:

	Second Quarter 2019					Year-to-Date 2019
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	1,889				$	3,688
Estimated change resulting from –
Rates and pricing	52			2.8	%	61			1.7	%
Sales decline	(15		)	(0.8	)	(11		)	(0.3	)
Weather	28			1.5		(29		)	(0.8	)
Fuel cost recovery	(8		)	(0.4	)	(95		)	(2.6	)
Retail – current year	$	1,946		3.1	%	$	3,614		(2.0	)%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018. The increases were primarily due to an increase in the NCCR tariff effective January 1, 2019. The year-to-date 2019 increase also reflects the rate pricing effect of decreased customer usage, partially offset by lower contributions from commercial and industrial customers with variable demand-driven pricing. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction – Regulatory Matters" herein for additional information related to the NCCR tariff.

Revenues attributable to changes in sales decreased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018. Weather-adjusted residential KWH sales decreased 0.8% in the second quarter 2019 primarily due to a decline in average customer usage, partially offset by customer growth. Weather-adjusted residential KWH sales increased 0.7% for year-to-date 2019 primarily due to customer growth, partially offset by a decline in average customer usage resulting from increases in energy saving initiatives and multi-family housing. Weather-adjusted commercial KWH sales decreased 1.2% and 1.1% in the second quarter and year-to-date 2019, respectively, primarily due to a decline in average customer usage resulting from an increase in energy saving initiatives, partially offset by customer growth. Weather-adjusted industrial KWH sales decreased 0.9% and 0.7% in the second quarter and year-to-date 2019, respectively, primarily due to decreases in the stone, clay, and glass and textile sectors. Additionally, the decrease in the second quarter 2019 also reflects a decrease in the paper sector and the decrease for year-to-date 2019 was partially offset by an increase in the paper sector.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018. For year-to-date 2019, the decrease was primarily due to decreased energy sales driven by milder weather in the first quarter 2019, resulting in lower customer demand, and lower generation costs. Electric rates include provisions to periodically 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 MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information.

Wholesale Revenues – Non-Affiliates

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(3)	(8.3)	$(18)	(22.5)

Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. 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

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electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.

In the second quarter 2019, wholesale revenues from sales to non-affiliates were $33 million compared to $36 million for the corresponding period in 2018. For year-to-date 2019, wholesale revenues from sales to non-affiliates were $62 million compared to $80 million for the corresponding period in 2018. The decrease for year-to-date 2019 was primarily due to a decrease in energy revenues primarily due to lower customer demand and lower energy prices.

Other Revenues

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$15	12.5	$43	18.9

In the second quarter 2019, other revenues were $135 million compared to $120 million for the corresponding period in 2018. The increase was primarily due to revenue increases of $6 million from unregulated sales associated with new energy conservation projects, $3 million from OATT sales, and $3 million from power delivery maintenance contracts.

For year-to-date 2019, other revenues were $270 million compared to $227 million for the corresponding period in 2018. The increase was primarily due to revenue increases of $11 million from unregulated new energy conservation project sales, $9 million from OATT sales, $8 million from outdoor lighting LED conversions and sales, $4 million from solar application fees, and $3 million from power delivery maintenance contracts.

Fuel and Purchased Power Expenses

	Second Quarter 2019 vs. Second Quarter 2018					Year-to-Date 2019 vs. Year-to-Date 2018
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	12		3.2		$	(101	)	(12.8	)
Purchased power – non-affiliates	13			11.7		9			3.9
Purchased power – affiliates	(44		)	(24.7	)	(39		)	(11.2	)
Total fuel and purchased power expenses	$	(19	)			$	(131	)

In the second quarter 2019, total fuel and purchased power expenses were $648 million compared to $667 million in the corresponding period in 2018. The decrease was primarily due to a net decrease of $19 million related to the volume of KWHs generated and purchased.

For year-to-date 2019, total fuel and purchased power expenses were $1.24 billion compared to $1.37 billion in the corresponding period in 2018. The decrease was primarily due to a $114 million decrease related to the average cost of fuel and purchased power primarily related to lower energy prices and more rainfall for hydro generation in the first quarter 2019 and a net $17 million decrease in the volume of KWHs generated and purchased.

Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information.

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

	Second Quarter 2019	Second Quarter 2018	Year-to-Date 2019	Year-to-Date 2018
Total generation (in billions of KWHs)	16	15	29	31
Total purchased power (in billions of KWHs)	6	8	15	14
Sources of generation (percent) —
Gas	45	40	47	42
Coal	26	29	23	29
Nuclear	26	28	26	26
Hydro	3	3	4	3
Cost of fuel, generated (in cents per net KWH) —
Gas	2.48	2.61	2.53	2.67
Coal	3.18	3.26	3.20	3.31
Nuclear	0.81	0.83	0.81	0.83
Average cost of fuel, generated (in cents per net KWH)	2.23	2.30	2.22	2.37
Average cost of purchased power (in cents per net KWH)(*)	4.59	4.37	4.23	4.81

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

Fuel

In the second quarter 2019, fuel expense was $390 million compared to $378 million in the corresponding period in 2018. The increase was primarily due to a 9.5% increase in the volume of KWHs generated primarily due to warmer weather in the second quarter 2019 compared to the corresponding period in 2018, partially offset by a 3.0% decrease in the average cost of fuel primarily related to lower natural gas and coal prices.

For year-to-date 2019, fuel expense was $689 million compared to $790 million in the corresponding period in 2018. The decrease was primarily due to a 6.9% decrease in the volume of KWHs generated primarily due to scheduled generation outages and milder weather in the first quarter 2019 compared to the corresponding period in 2018, a 6.3% decrease in the average cost of fuel primarily related to lower natural gas and coal prices, and more rainfall for hydro generation in the first quarter 2019.

Purchased Power – Non-Affiliates

In the second quarter 2019, purchased power expense from non-affiliates was $124 million compared to $111 million in the corresponding period in 2018. For year-to-date 2019, purchased power expense from non-affiliates was $242 million compared to $233 million in the corresponding period in 2018. The increases were primarily due to 15.1% and 24.6% increases in the volume of KWHs purchased in the second quarter and year-to-date 2019, respectively, primarily due to scheduled generation outages at Georgia Power-owned generating units, partially offset by 2.3% and 18.7% decreases in the average cost per KWH purchased in the second quarter and year-to-date 2019, respectively, primarily due to lower energy prices.

The volume increases also reflect purchases from Gulf Power which were classified as affiliate prior to January 1, 2019. See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.

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

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Purchased Power – Affiliates

In the second quarter 2019, purchased power expense from affiliates was $134 million compared to $178 million in the corresponding period in 2018. The decrease was primarily due to a 26.4% decrease in the volume of KWHs purchased as Georgia Power units generally dispatched at a lower cost than other Southern Company system resources, partially offset by a 2.9% increase in the average cost per KWH purchased.

For year-to-date 2019, purchased power expense from affiliates was $310 million compared to $349 million in the corresponding period in 2018. The decrease was primarily due to an 11.0% decrease in the average cost per KWH purchased primarily resulting from lower energy prices.

The decreases in purchased power expense from affiliates also reflect the classification of capacity expenses of $6 million and $12 million in the second quarter and year-to-date 2019, respectively, related to PPAs with Southern Power accounted for as finance leases following the adoption of FASB ASC Topic 842, Leases (ASC 842). In 2019, these expenses are included in depreciation and amortization and interest expense, net of amounts capitalized. The changes in the volume of KWHs purchased also include the effect of classifying purchases from Gulf Power as non-affiliate beginning January 1, 2019. See Notes (L) and (K) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 842 and the sale of Gulf Power, respectively.

Energy purchases from affiliates will vary depending on 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

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$6	1.3	$50	5.8

In the second quarter 2019, other operations and maintenance expenses were $463 million compared to $457 million in the corresponding period in 2018. For year-to-date 2019, other operations and maintenance expenses were $913 million compared to $863 million in the corresponding period in 2018. The increases in the second quarter and year-to-date 2019 reflect adjustments of $8 million and $15 million, respectively, for FERC fees following the conclusion of a multi-year audit of headwater benefits associated with hydro facilities.

The increase in the second quarter 2019 was also due to an increase of $7 million in generation maintenance costs, partially offset by decreases of $5 million in distribution overhead line operation and maintenance costs and $5 million in employee benefit expenses.

The increase for year-to-date 2019 was also due to increases of $14 million in scheduled generation outage expenses, $10 million related to affiliate labor billing credits received in 2018, and $9 million of expenses associated with unregulated new energy conservation project sales, partially offset by a decrease of $7 million in customer accounts and sales expenses.

Depreciation and Amortization

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$14	6.1	$25	5.5

In the second quarter 2019, depreciation and amortization was $244 million compared to $230 million in the corresponding period in 2018. For year-to-date 2019, depreciation and amortization was $483 million compared to $458 million in the corresponding period in 2018. The increases were primarily due to additional plant in service and reflect the classification of approximately $2 million and $4 million in the second quarter and year-to-date 2019, respectively, related to PPAs with Southern Power accounted for as finance leases following the adoption of

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ASC 842. In prior periods, the expenses related to these PPAs were included in purchased power, affiliates. See Note (L) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 842.

Estimated Loss on Plant Vogtle Units 3 and 4

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(1,060)	N/M	$(1,060)	N/M

N/M - Not meaningful

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" in Item 8 of the Form 10-K for additional information.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$3	2.9	$(7)	(3.4)

In the second quarter 2019, interest expense, net of amounts capitalized was $105 million compared to $102 million in the corresponding period in 2018. For year-to-date 2019, interest expense, net of amounts capitalized was $201 million compared to $208 million in the corresponding period in 2018. The decrease for year-to-date 2019 was primarily due to a $15 million decrease in interest expense associated with a decrease in average outstanding borrowings, partially offset by the reclassification of $8 million related to PPAs with Southern Power accounted for as finance leases following the adoption of ASC 842. In prior periods, the expenses related to these PPAs were included in purchased power, affiliates. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings and Note (L) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 842.

Income Taxes (Benefit)

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$272	N/M	$261	N/M

N/M - Not meaningful

In the second quarter 2019, income taxes were $129 million compared to an income tax benefit of $143 million in the corresponding period in 2018. For year-to-date 2019, income taxes were $211 million compared to an income tax benefit of $50 million in the corresponding period in 2018. The changes were primarily due to the reduction in pre-tax earnings (loss) in the second quarter 2018 resulting from the charge associated with Plant Vogtle Units 3 and 4 construction, partially offset by an increase in state ITCs. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Georgia Power's 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

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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.

For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.

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 and to achieve stated goals. 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, and may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. A major portion of these costs is expected to be recovered through retail rates. The ultimate impact of environmental laws and regulations and GHG goals 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Georgia Power in Item 7 and Note 3 to the financial statements under "Environmental Remediation" in Item 8 of the Form 10-K for additional information.

Global Climate Issues

On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. Implementation of the CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule requires states to develop unit-specific CO₂ emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. Georgia Power has ownership interests in nine coal-fired units to which the ACE Rule is applicable. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to Georgia Power will depend on state implementation plan requirements and the outcome of any associated legal challenges and cannot be determined at this time.

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FERC Matters

See Note 2 to the financial statements under "FERC Matters – Open Access Transmission Tariff" in Item 8 of the Form 10-K for additional information.

On June 28, 2019, the FERC approved a settlement agreement between Alabama Municipal Electric Authority and Cooperative Energy and SCS and the traditional electric operating companies (including Georgia Power) agreeing to an OATT rate reduction based on a 10.6% ROE, with a retroactive effective date of May 10, 2018, and a five-year moratorium on these parties seeking changes to the OATT formula rate. The terms of the OATT settlement agreement will not have a material impact on the financial statements of Georgia Power.

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 tariffs, ECCR tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to 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" in Item 8 of the Form 10-K for additional information regarding regulatory matters.

Rate Plans

On June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.

Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:

Tariff	2020		2021		2022
	(in millions)
Traditional base:
Levelized	$	209	$	—	$	—
CCR AROs	158		140		227
ECCR	165		—		—
Demand-Side Management	14		2		1
Municipal Franchise Fee	17		3		5
Total(*)	$	563	$	145	$	234

(*) Totals may not add due to rounding.

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Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:

• Continuation of an allowed retail ROE range of 10.00% to 12.00%.

• Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the remaining one-third are retained by Georgia Power.

• Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.

Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be determined at this time.

Integrated Resource Plan

In 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan, including 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 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. In accordance with the Georgia PSC's order, costs incurred of approximately $50 million have been recorded as a regulatory asset.

On July 16, 2019, the Georgia PSC voted to approve Georgia Power's triennial Integrated Resource Plan (2019 IRP) as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.

In the 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively, at June 30, 2019), as well as any unusable materials and supplies inventory balances, upon retirement to a regulatory asset. Recovery of each unit's net book value will continue through December 31, 2019 as provided in the 2013 ARP.

For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case as follows: (i) the net book values of Plant Mitchell Unit 3 (approximately $8 million at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The ultimate outcome of these matters cannot be determined at this time.

Also in the 2019 IRP, the Georgia PSC rejected 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. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future Integrated Resource Plan. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Georgia Power's financial statements.

Additionally, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $135 million at June 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and

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2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.

The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.

See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.

Nuclear Construction

See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, the joint ownership agreements and related funding agreement, VCM reports, and the NCCR tariff.

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. In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

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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 June 30, 2019(b)	(5.2		)
Remaining estimate to complete(a)	$	3.2

(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 $2.0 billion had been incurred through June 30, 2019.

In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the estimated total project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.

As construction continues and testing and system turnover activities increase, challenges with management of contractors, subcontractors, and vendors; supervision of craft labor and related craft labor productivity, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures, or components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.

The April 2019 cost and schedule validation process established target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the approved in-service dates. To support that strategy, monthly production and activity target values will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers (particularly electrical and pipefitter craft labor), as well as additional supervision and other field support resources, must be retained and deployed.

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 submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, 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 regulatory-approved project schedule is currently estimated to result in additional base capital costs of approximately $50

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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

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

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 in conjunction with the nineteenth VCM report, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 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) 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 at pre-established prices, 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 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 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.

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 June 30, 2019, Georgia Power had recovered approximately $2.0 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. In December 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

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certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the 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 in 2018 and are estimated to have negative earnings impacts of approximately $70 million in 2019 and an aggregate of approximately $630 million from 2020 to 2022.

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.

In February 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. In March 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. In December 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.

In August 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

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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).

On April 30, 2019, as requested by the staff of the Georgia PSC, Georgia Power reported the results of the cost and schedule validation process to the Georgia PSC. On August 30, 2019, Georgia Power will file its twentieth VCM report concurrently with its twenty-first VCM report with the Georgia PSC, which will reflect the capital cost forecast discussed previously and request approval of $1.2 billion of construction capital costs incurred from June 30, 2018 through June 30, 2019. In addition, on June 20, 2019, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a settlement agreement related to the administrative claim filed in the Westinghouse bankruptcy proceedings. Accordingly, in the twentieth/twenty-first VCM report, Georgia Power will also request approval of the $51.6 million of associated expenditures previously deferred by the Georgia PSC.

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

See RISK FACTORS of Georgia Power in the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.

DOE Financing

At June 30, 2019, Georgia Power had borrowed $3.46 billion related to Plant Vogtle Units 3 and 4 costs as provided through the Amended and Restated Loan Guarantee Agreement and related multi-advance credit facilities among Georgia Power, the DOE, and the FFB, which provide for borrowings of up to approximately $5.130 billion, subject to the satisfaction of certain conditions. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

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

Other Matters

Georgia Power is involved in various other matters that could affect future earnings, including matters being litigated and regulatory matters. 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 determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) to the Condensed Financial Statements herein, 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 (B) and (C) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

Litigation

In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. In 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court. Georgia Power filed a petition for writ of certiorari with the Georgia Supreme

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Court, which was granted in 2017. In June 2018, the Georgia Supreme Court affirmed the judgment of the Georgia Court of Appeals and remanded the case to the trial court for further proceedings. Following a motion by Georgia Power, on February 13, 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling to address certain terms the court previously held were ambiguous as used in the Georgia PSC's orders. The order entered by the Superior Court of Fulton County also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Georgia Power also filed a notice of appeal with the Georgia Court of Appeals regarding the Superior Court of Fulton County's February 2019 order. Georgia Power believes the plaintiffs' claims have no merit. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether conditional class certification will be upheld and the ultimate composition of any class and whether any losses would be subject to recovery from any municipalities. The ultimate outcome of this matter cannot be determined at this time.

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 Item 8 of the Form 10-K. 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power's critical accounting policies and estimates.

Recently Issued Accounting Standards

See Note (A) to the Condensed Financial Statements herein for information regarding Georgia Power's recently adopted accounting standards.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power's financial condition remained stable at June 30, 2019. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $1.1 billion for the first six months of 2019 and 2018. Net cash used for investing activities totaled $1.8 billion for the first six months of 2019 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities, including approximately $660 million related to the construction of Plant Vogtle Units 3 and 4. Net cash provided from financing activities totaled $620 million for the first six months of 2019 primarily due to borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, the reoffering of pollution control revenue bonds, and an increase in short-term borrowings, partially offset by payment of common stock dividends and the redemption and repurchase of pollution control revenue bonds. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2019 include recording $1.5 billion in operating lease right-of-use assets, net of amortization and $1.5 billion in operating lease obligations related to the adoption of ASC 842, an increase of $1.2 billion in property, plant, and equipment to comply with environmental standards and the

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construction of generation, transmission, and distribution facilities, and an increase of $1.2 billion in long-term debt (including securities due within one year) primarily due to borrowings from the FFB for construction of Plant Vogtle Units 3 and 4 and the reoffering of pollution control revenue bonds previously purchased and held by Georgia Power. See Note (L) to the Condensed Financial Statements herein for additional information on the adoption of ASC 842. Also see Notes (B) and (F) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" and "DOE Loan Guarantee Borrowings," respectively, herein for additional information regarding Plant Vogtle Units 3 and 4 and the related Amended and Restated Loan Guarantee Agreement.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power's capital requirements and contractual obligations. Approximately $988 million will be required through June 30, 2020 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information. Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

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, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; nonperformance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel; challenges with start-up activities, including major equipment failure, system integration, or regional transmission upgrades; and/or operational performance. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures.

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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Georgia Power in Item 7 of the Form 10-K for additional information.

In 2014, Georgia Power entered into a loan guarantee agreement with the DOE and, in March 2019, entered into the Amended and Restated Loan Guarantee Agreement, under which the proceeds of borrowings may be used to

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reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4.

Under the Amended and Restated Loan Guarantee Agreement, the DOE has agreed to guarantee the obligations of Georgia Power under note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities (FFB Credit Facilities). Under the FFB Credit Facilities, Georgia Power may make term loan borrowings through the FFB in an amount up to approximately $5.130 billion, provided that total aggregate borrowings under the FFB Credit Facilities may not exceed 70% of (i) Eligible Project Costs minus (ii) approximately $1.492 billion (reflecting the amounts received by Georgia Power under the Guarantee Settlement Agreement less the Customer Refunds). At June 30, 2019, Georgia Power had borrowed $3.46 billion under the FFB Credit Facilities.

See Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

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 June 30, 2019, Georgia Power's current liabilities exceeded current assets by $2.0 billion primarily due to long-term debt that is due within one year of $988 million and notes payable of $555 million.

At June 30, 2019, Georgia Power had approximately $10 million of cash and cash equivalents and a multi-year committed credit arrangement with banks totaling $1.75 billion, of which $1.74 billion was unused. In May 2019, Georgia Power amended its bank credit arrangement which, among other things, extended the maturity date from 2022 to 2024. This credit arrangement, as well as Georgia Power's term loan arrangements, contain a covenant that limits debt levels and contain a cross-acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2019, Georgia Power was in compliance with this covenant. The 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" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

A portion of the $1.74 billion unused bank credit arrangement 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 as of June 30, 2019 was approximately $550 million. In addition, at June 30, 2019, Georgia Power had $185 million of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.

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 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.

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Details of short-term borrowings were as follows:

	Short-term Debt at June 30, 2019				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)
Commercial paper	$	305	2.7	%	$	288	2.7	%	$	485
Short-term bank debt	250		2.9	%	69		2.9	%	250
Total	$	555	2.8	%	$	357	2.8	%

(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2019.

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.

Credit Rating Risk

At June 30, 2019, 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, and construction of new generation at Plant Vogtle Units 3 and 4.

The maximum potential collateral requirements under these contracts at June 30, 2019 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	92
Below BBB- and/or Baa3	$	1,040

Included in these amounts are certain agreements that could require collateral in the event that 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.

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. 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 in April 2018, is expected to help mitigate these potential adverse impacts to certain credit metrics by allowing a higher retail equity ratio through 2019, which Georgia Power has requested to extend in the Georgia Power 2019 Base Rate Case. See Note (B) to the Condensed Financial Statements and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Rate Plans" for additional information, including requests for additional capital structure adjustments.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities

In January 2019, 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 2019, Georgia Power made additional borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million at an interest rate of 3.213% through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.

Also in March 2019, Georgia Power reoffered to the public the following pollution control revenue bonds that previously had been purchased and held by Georgia Power:

• $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;

• 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; and

• $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.

In April 2019, Georgia Power purchased and held the following pollution control revenue bonds. In May 2019, Georgia Power reoffered these pollution control revenue bonds to the public.

• $55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1994;

• $30 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1995;

• $20 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Ninth Series 1994; and

• $10 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 1994.

In June 2019, Georgia Power reoffered to the public $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, which had been previously purchased and held by Georgia Power.

Also in June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR. The proceeds from these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes.

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.

92

MISSISSIPPI POWER COMPANY

93

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	215		$	212		$	418		$	406
Wholesale revenues, non-affiliates	57			59			114			127
Wholesale revenues, affiliates	37			19			58			54
Other revenues	4			7			10			11
Total operating revenues	313			297			600			598
Operating Expenses:
Fuel	105			98			198			197
Purchased power	6			7			9			16
Other operations and maintenance	68			67			127			141
Depreciation and amortization	48			44			95			84
Taxes other than income taxes	28			27			55			54
Estimated loss on Kemper IGCC	4			—			6			45
Total operating expenses	259			243			490			537
Operating Income	54			54			110			61
Other Income and (Expense):
Interest expense, net of amounts capitalized	(17		)	(21		)	(35		)	(39		)
Other income (expense), net	5			27			11			27
Total other income and (expense)	(12		)	6			(24		)	(12		)
Earnings Before Income Taxes	42			60			86			49
Income taxes	5			13			12			9
Net Income	37			47			74			40
Dividends on Preferred Stock	—			1			—			1
Net Income After Dividends on Preferred Stock	$	37		$	46		$	74		$	39

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
	(in millions)				(in millions)
Net Income	$	37	$	47	$	74	$	40
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $-, $-, and $(1), respectively	—		—		—		(1		)
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $-, and $-, respectively	—		—		1		1
Total other comprehensive income (loss)	—		—		1		—
Comprehensive Income	$	37	$	47	$	75	$	40

The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

94

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2019			2018
	(in millions)
Operating Activities:
Net income	$	74		$	40
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	98			86
Deferred income taxes	(16		)	289
Settlement of asset retirement obligations	(17		)	(15		)
Estimated loss on Kemper IGCC	11			28
Other, net	1			2
Changes in certain current assets and liabilities —
-Receivables	(8		)	(51		)
-Other current assets	(3		)	(11		)
-Accounts payable	(28		)	(15		)
-Accrued taxes	(43		)	(41		)
-Accrued compensation	(15		)	(14		)
-Other current liabilities	6			(1		)
Net cash provided from operating activities	60			297
Investing Activities:
Property additions	(95		)	(74		)
Construction payables	(12		)	(9		)
Payments pursuant to LTSAs	(11		)	(13		)
Other investing activities	(10		)	(12		)
Net cash used for investing activities	(128		)	(108		)
Financing Activities:
Decrease in notes payable, net	—			(4		)
Proceeds —
Senior notes	—			600
Short-term borrowings	—			300
Capital contributions from parent company	7			1
Pollution control revenue bonds	43			—
Redemptions —
Other long-term debt	—			(900		)
Short-term borrowings	—			(200		)
Return of capital	(75		)	—
Other financing activities	(1		)	(6		)
Net cash used for financing activities	(26		)	(209		)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(94		)	(20		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	293			248
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	199		$	228
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $(1) and $- capitalized for 2019 and 2018, respectively)	$	36		$	39
Income taxes, net	23			(257		)
Noncash transactions — Accrued property additions at end of period	23			23

The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

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MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2019		At December 31, 2018
	(in millions)
Current Assets:
Cash and cash equivalents	$	199	$	293
Receivables —
Customer accounts receivable	38		34
Unbilled revenues	44		41
Affiliated	17		21
Other accounts and notes receivable	38		31
Fossil fuel stock	23		20
Materials and supplies	52		53
Other regulatory assets	107		116
Other current assets	13		19
Total current assets	531		628
Property, Plant, and Equipment:
In service	4,800		4,900
Less: Accumulated provision for depreciation	1,427		1,429
Plant in service, net of depreciation	3,373		3,471
Construction work in progress	113		103
Total property, plant, and equipment	3,486		3,574
Other Property and Investments	124		24
Deferred Charges and Other Assets:
Deferred charges related to income taxes	33		33
Regulatory assets – asset retirement obligations	207		143
Other regulatory assets, deferred	328		332
Accumulated deferred income taxes	145		150
Other deferred charges and assets	20		2
Total deferred charges and other assets	733		660
Total Assets	$	4,874	$	4,886

The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

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MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2019		At December 31, 2018
	(in millions)
Current Liabilities:
Securities due within one year	$	300	$	40
Accounts payable —
Affiliated	60		60
Other	49		90
Accrued taxes	52		95
Accrued interest	15		15
Accrued compensation	23		38
Accrued plant closure costs	24		29
Asset retirement obligations	27		34
Other regulatory liabilities	20		12
Over recovered regulatory clause liabilities	12		14
Other current liabilities	52		28
Total current liabilities	634		455
Long-term Debt	1,318		1,539
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	366		378
Deferred credits related to income taxes	362		382
Employee benefit obligations	110		115
Asset retirement obligations, deferred	177		126
Other cost of removal obligations	189		185
Other regulatory liabilities, deferred	79		81
Other deferred credits and liabilities	22		16
Total deferred credits and other liabilities	1,305		1,283
Total Liabilities	3,257		3,277
Common Stockholder's Equity (See accompanying statements)	1,617		1,609
Total Liabilities and Stockholder's Equity	$	4,874	$	4,886

The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

97

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (UNAUDITED)

	Number of Common Shares Issued	Common Stock		Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	(in millions)
Balance at December 31, 2017	1	$	38	$	4,529		$	(3,205	)	$	(4	)	$	1,358
Net loss after dividends on preferred stock	—	—		—			(7		)	—			(7		)
Capital contributions from parent company	—	—		2			—			—			2
Other comprehensive income (loss)	—	—		—			—			(1		)	(1		)
Other	—	—		—			(1		)	—			(1		)
Balance at March 31, 2018	1	38		4,531			(3,213		)	(5		)	1,351
Net income after dividends on preferred stock	—	—		—			46			—			46
Other	—	—		—			1			—			1
Balance at June 30, 2018	1	$	38	$	4,531		$	(3,166	)	$	(5	)	$	1,398
Balance at December 31, 2018	1	$	38	$	4,546		$	(2,971	)	$	(4	)	$	1,609
Net income	—	—		—			37			—			37
Return of capital to parent company	—	—		(38		)	—			—			(38		)
Capital contributions from parent company	—	—		2			—			—			2
Balance at March 31, 2019	1	38		4,510			(2,934		)	(4		)	1,610
Net income	—	—		—			37			—			37
Return of capital to parent company	—	—		(38		)	—			—			(38		)
Capital contributions from parent company	—	—		8			—			—			8
Balance at June 30, 2019	1	$	38	$	4,480		$	(2,897	)	$	(4	)	$	1,617

The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2019 vs. SECOND QUARTER 2018

AND

YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018

OVERVIEW

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 number of customers and to operate in a constructive regulatory environment that provides timely recovery of prudently-incurred costs. These costs include those related to projected long-term demand growth, stringent environmental standards, including CCR rules, reliability, fuel, capital and operations and maintenance expenditures, including expanding and improving transmission and distribution facilities, 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).

On May 7, 2019, the FERC accepted Mississippi Power's March 28, 2019 request for a decrease in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with its wholesale customers (MRA Settlement Agreement) resolving all matters related to the Kemper County energy facility similar to the retail rate settlement agreement approved by the Mississippi PSC in February 2018 and reflecting the impacts of the Tax Reform Legislation. Pursuant to the MRA Settlement Agreement, base rates decreased $3.7 million annually, effective January 1, 2019. See Note 2 to the financial statements under "FERC Matters" in Item 8 of the Form 10-K 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. Mississippi Power also focuses on broader measures of customer satisfaction, plant availability, system reliability, and net income.

RESULTS OF OPERATIONS

Net Income

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(9)	(19.6)	$35	89.7

Mississippi Power's net income for the second quarter 2019 was $37 million compared to $46 million for the corresponding period in 2018. This decrease was primarily due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018 and a decrease in retail revenues due to a new tolling arrangement accounted for as a sales-type lease, partially offset by an increase in PEP rates that became effective for the first billing cycle of September 2018.

For year-to-date 2019, net income was $74 million compared to $39 million for the corresponding period in 2018. This increase was primarily due to lower charges associated with the Kemper IGCC in 2019 and an increase in PEP rates that became effective for the first billing cycle of September 2018, partially offset by a decrease in other income (expense), net due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018 and a decrease in retail revenues due to a new tolling arrangement accounted for as a sales-type lease.

99

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$3	1.4	$12	3.0

In the second quarter 2019, retail revenues were $215 million compared to $212 million for the corresponding period in 2018. For year-to-date 2019, retail revenues were $418 million compared to $406 million for the corresponding period in 2018.

Details of the changes in retail revenues were as follows:

	Second Quarter 2019					Year-to-Date 2019
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	212				$	406
Estimated change resulting from –
Rates and pricing	11			5.2	%	26			6.4	%
Sales decline	(1		)	(0.5	)	—			—
Weather	—			—		(9		)	(2.2	)
Fuel and other cost recovery	(7		)	(3.3	)	(5		)	(1.2	)
Retail – current year	$	215		1.4	%	$	418		3.0	%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily due to increases in PEP and ECO Plan rates that became effective for the first billing cycle of September 2018, partially offset by a new tolling arrangement accounted for as a sales-type lease effective January 2019. Partially offsetting the year-to-date 2019 increase was a rate decrease related to the Kemper County energy facility that became effective for the first billing cycle of April 2018. See Note 2 to the financial statements under "Mississippi Power – Performance Evaluation Plan," " – Environmental Compliance Overview Plan," and " – Kemper County Energy Facility – Rate Recovery" in Item 8 of the Form 10-K and Note (L) to the Condensed Financial Statements herein for additional information.

Revenues attributable to changes in sales decreased in the second quarter 2019 when compared to the corresponding period in 2018. Weather-adjusted residential KWH sales increased 0.4% and 1.0% in the second quarter and year-to-date 2019, respectively, due to increased customer usage. Weather-adjusted commercial KWH sales decreased 2.1% and 2.7% in the second quarter and year-to-date 2019, respectively, due to decreased customer usage. Industrial KWH sales decreased 3.1% and 3.5% in the second quarter and year-to-date 2019, respectively, primarily due to decreased customer usage by several large industrial customers.

Revenues associated with weather decreased for year-to-date 2019 when compared to the corresponding period in 2018 primarily due to milder weather.

Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily as a result of lower recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates 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.

100

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Non-Affiliates

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	(3.4)	$(13)	(10.2)

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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "FERC Matters" herein for additional information.

For year-to-date 2019, wholesale revenues from sales to non-affiliates were $114 million compared to $127 million for the corresponding period in 2018. This decrease primarily resulted from a $6 million decrease in cost-based electric tariff revenues due to decreased customer usage, milder weather, and a decrease in rates due to the MRA Settlement Agreement, a $5 million decrease due to lower PPA capacity and energy sales, and a $3 million decrease due to lower fuel prices, partially offset by a $1 million increase in opportunity sales. See Note (B) to the Condensed Financial Statements under "Mississippi Power – Municipal and Rural Association Tariff" herein for additional information.

Wholesale Revenues – Affiliates

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$18	94.7	$4	7.4

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 the second quarter 2019, wholesale revenues from sales to affiliates were $37 million compared to $19 million for the corresponding period in 2018. The increase was primarily due to a $15 million increase associated with higher KWH sales due to the dispatch of Mississippi Power's lower cost generation resources to serve the Southern Company system's territorial load and a $2 million increase associated with a higher average sales price.

For year-to-date 2019, wholesale revenues from sales to affiliates were $58 million compared to $54 million for the corresponding period in 2018. The increase was primarily due to a $25 million increase associated with higher KWH sales due to the dispatch of Mississippi Power's lower cost generation resources to serve the Southern Company system's territorial load, partially offset by a $21 million decrease associated with lower natural gas prices.

101

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses

	Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	7		7.1	$	1		0.5
Purchased power	(1		)	(14.3)	(7		)	(43.8)
Total fuel and purchased power expenses	$	6			$	(6	)

In the second quarter 2019, total fuel and purchased power expenses were $111 million compared to $105 million for the corresponding period in 2018. The increase was primarily due to a $13 million net increase associated with the volume of KWHs generated and purchased, partially offset by a net decrease of $7 million associated with lower average cost of fuel.

For year-to-date 2019, total fuel and purchased power expenses were $207 million compared to $213 million for the corresponding period in 2018. The decrease was primarily due to a $13 million decrease related to the average cost of fuel and purchased power primarily due to a lower average cost of natural gas, partially offset by a $7 million net increase associated with the volume of KWHs generated and purchased.

Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.

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

	Second Quarter 2019	Second Quarter 2018	Year-to-Date 2019	Year-to-Date 2018
Total generation (in millions of KWHs)	4,621	4,081	8,570	8,084
Total purchased power (in millions of KWHs)	88	104	139	207
Sources of generation (percent) –
Coal	8	7	6	6
Gas	92	93	94	94
Cost of fuel, generated (in cents per net KWH) –
Coal	3.92	3.42	4.06	3.49
Gas	2.29	2.51	2.37	2.56
Average cost of fuel, generated (in cents per net KWH)	2.43	2.58	2.48	2.61
Average cost of purchased power (in cents per net KWH)	6.53	6.55	6.56	7.77

Fuel

In the second quarter 2019, fuel expense was $105 million compared to $98 million for the corresponding period in 2018. For year-to-date 2019, fuel expense was $198 million compared to $197 million for the corresponding period in 2018. These increases were due to a 14% and 6% increase in the volume of KWHs generated in the second quarter and year-to-date 2019, respectively, partially offset by a 9% and 7% decrease in the average cost of natural gas for the second quarter and year-to-date 2019, respectively.

Purchased Power

For year-to-date 2019, purchased power expense was $9 million compared to $16 million for the corresponding period in 2018. The decrease was primarily due to a 33% decrease in the volume of KWHs purchased due to lower territorial load and a 16% decrease due to a lower average cost of purchased power.

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$1	1.5	$(14)	(9.9)

For year-to-date 2019, other operations and maintenance expenses were $127 million compared to $141 million for the corresponding period in 2018. The decrease was primarily due to decreases of $10 million related to generation maintenance, primarily due to planned outages, and $6 million in employee compensation and benefit expenses due to an employee attrition plan implemented in the third quarter 2018, partially offset by a $4 million increase related to additional overhead line maintenance and vegetation management.

Depreciation and Amortization

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$4	9.1	$11	13.1

In the second quarter 2019, depreciation and amortization was $48 million compared to $44 million for the corresponding period in 2018. For year-to-date 2019, depreciation and amortization was $95 million compared to $84 million for the corresponding period in 2018. These increases were primarily related to increases in amortization associated with ECO Plan regulatory assets. See Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information.

Estimated Loss on Kemper IGCC

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$4	N/M	$(39)	(86.7)

N/M - Not meaningful

In the second quarter and year-to-date 2019, estimated losses on the Kemper IGCC were $4 million and $6 million, respectively, compared to an immaterial amount and $45 million, respectively, for the corresponding periods in 2018. These charges relate to abandonment and closure activities for the mine and gasifier-related assets.

See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Mississippi Power – Kemper County Energy Facility" herein for additional information.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(4)	(19.0)	$(4)	(10.3)

In the second quarter 2019, interest expense, net of amounts capitalized was $17 million compared to $21 million for the corresponding period in 2018. For year-to-date 2019, interest expense, net of amounts capitalized was $35

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

million compared to $39 million for the corresponding period in 2018. These decreases primarily resulted from a decrease in average outstanding debt.

Other Income (Expense), Net

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(22)	(81.5)	$(16)	(59.3)

In the second quarter 2019, other income (expense), net was $5 million compared to $27 million for the corresponding period in 2018. For year-to-date 2019, other income (expense), net was $11 million compared to $27 million for the corresponding period in 2018. These decreases were primarily due to a $24 million decrease in the second quarter and year-to-date 2019 due to the settlement of Mississippi Power's Deepwater Horizon claim recorded in May 2018, partially offset by increases of $3 million and $6 million in the second quarter and year-to-date 2019, respectively, due to higher interest income associated with a new tolling arrangement accounted for as a sales-type lease. See Note (L) to the Condensed Financial Statements herein and Note 3 to the financial statements under "Other Matters – Mississippi Power" in Item 8 of the Form 10-K for additional information.

Income Taxes

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(8)	(61.5)	$3	33.3

In the second quarter 2019, income taxes were $5 million compared to $13 million for the corresponding period in 2018. This decrease was due to lower pre-tax earnings and an increase in the flowback of excess deferred income taxes as a result of the MRA Settlement Agreement.

For year-to-date 2019, income taxes were $12 million compared to $9 million for the corresponding period in 2018. This increase was primarily due to higher pre-tax earnings resulting from lower estimated losses on the Kemper IGCC, partially offset by an increase in the flowback of excess deferred income taxes as a result of the MRA Settlement Agreement.

See Note (B) to the Condensed Financial Statements under "Mississippi Power" herein for additional information.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Mississippi Power's 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.

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For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K.

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 and to achieve stated goals. 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, and may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. 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 GHG goals 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 MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Mississippi Power in Item 7 and Note 3 to the financial statements under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Laws and Regulations

Coal Combustion Residuals

In June 2019, Mississippi Power recorded an increase of approximately $58 million to its AROs for higher expected compliance costs related to the CCR Rule (and the related State of Alabama rule, as applicable). Approximately $49 million of the revised cost estimates are associated with an ash pond at Plant Greene County, which is jointly owned with Alabama Power. The additional estimated costs to close this ash pond under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and an increase in the estimated ash volume.

As further analysis is performed and additional details are developed with respect to ash pond closures, Mississippi Power expects to periodically update its ARO cost estimates. Additionally, the closure designs and plans in the State of Alabama are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, Mississippi Power's results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

Global Climate Issues

On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. Implementation of the CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule requires states to develop unit-specific CO₂ emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in

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the ACE Rule. Mississippi Power has ownership interests in two coal-fired units to which the ACE Rule is applicable. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to Mississippi Power will depend on state implementation plan requirements and the outcome of any associated legal challenges and cannot be determined at this time.

FERC Matters

See Note 2 to the financial statements under "FERC Matters" in Item 8 of the Form 10-K for additional information.

Municipal and Rural Association Tariff

On May 7, 2019, the FERC accepted Mississippi Power's March 28, 2019 request for a decrease in wholesale base revenues under the MRA tariff as agreed upon in the MRA Settlement Agreement resolving all matters related to the Kemper County energy facility similar to the retail rate settlement agreement approved by the Mississippi PSC in February 2018 and reflecting the impacts of the Tax Reform Legislation. Pursuant to the MRA Settlement Agreement, base rates decreased $3.7 million annually, effective January 1, 2019.

Open Access Transmission Tariff

On June 28, 2019, the FERC approved a settlement agreement between Alabama Municipal Electric Authority and Cooperative Energy and SCS and the traditional electric operating companies (including Mississippi Power) agreeing to an OATT rate reduction based on a 10.6% ROE, with a retroactive effective date of May 10, 2018, and a five-year moratorium on these parties seeking changes to the OATT formula rate. The terms of the OATT settlement agreement will not have a material impact on the financial statements of Mississippi Power.

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 under PEP 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. Mississippi Power is scheduled to file a base rate case in the fourth quarter 2019.

See Note 2 to the financial statements under "Mississippi Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Mississippi Power" herein for additional information.

Environmental Compliance Overview Plan

On July 9, 2019, Mississippi Power filed a request with the Mississippi PSC for a Certificate of Public Convenience and Necessity to complete certain environmental compliance projects, primarily associated with the Plant Daniel coal units co-owned 50% with Gulf Power. The total estimated cost is approximately $125 million, with Mississippi Power's share of approximately $66 million being proposed for recovery through its ECO Plan. Approximately $17 million of Mississippi Power's share is associated with ash pond closure and is reflected in Mississippi Power's ARO liabilities. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information on AROs and Note (C) to the Condensed Financial Statements under "Other Matters – Mississippi Power" herein for additional information on Gulf Power's ownership in Plant Daniel.

Kemper County Energy Facility

See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.

As the mining permit holder, Liberty Fuels Company, LLC 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,

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with monitoring expected to continue through 2027. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

During the second quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $6 million ($5 million after tax), respectively, 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 dismantlement costs, net of salvage), 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 at $7 million for the remainder of 2019 and $2 million to $6 million annually in 2020 through 2023.

In addition, Mississippi Power constructed the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery and 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.

In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of 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. In connection with the DOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the Kemper County energy facility. The ultimate outcome of these matters cannot be determined at this time; however, they could have a material impact on Mississippi Power's financial statements.

Other Matters

Mississippi Power is involved in various other matters that could affect future earnings, including matters being litigated and regulatory matters. 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 determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) to the Condensed Financial Statements herein, 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 (B) and (C) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

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 by

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the FERC and the Mississippi PSC, and cannot be determined at this time. See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.

Litigation

See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.

In May 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 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, which were denied by the arbitration panel on May 10, 2019.

In November 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 by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint on March 14, 2019. The amended complaint included four additional plaintiffs and additional claims for gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint.

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

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 Item 8 of the Form 10-K. 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Mississippi Power in Item 7 of the Form 10-K for a complete discussion of Mississippi Power's critical accounting policies and estimates.

Recently Issued Accounting Standards

See Note (A) to the Condensed Financial Statements herein for information regarding Mississippi Power's recently adopted accounting standards.

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FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K for additional information.

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.

Net cash provided from operating activities totaled $60 million for the first six months of 2019, a decrease of $237 million as compared to the corresponding period in 2018. The decrease in net cash provided from operating activities is primarily related to lower income tax and ad valorem tax payments and the timing of collections of receivables. Net cash used for investing activities totaled $128 million for the first six months of 2019 primarily due to gross property additions related to distribution and transmission facilities. Net cash used for financing activities totaled $26 million for the first six months of 2019 primarily due to a return of capital to Southern Company, partially offset by $43 million of pollution control revenue bonds reoffered to the public. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2019 include a decrease of $221 million in long-term debt, primarily due to the reclassification of $300 million in unsecured senior notes to securities due within one year, partially offset by $43 million in securities reoffered to the public and $40 million in variable rate revenue bonds reclassified from securities due within one year. Other significant changes include a decrease of $100 million in plant in service and an increase of $100 million in other property and investments primarily due to a new tolling arrangement, effective January 1, 2019, accounted for as a sales-type lease; a decrease of $94 million in cash and cash equivalents; and a decrease of $43 million in accrued taxes primarily due to the payment of ad valorem taxes. See Note (L) to the Condensed Financial Statements herein for additional information.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power's capital requirements and contractual obligations. Approximately $300 million will be required through June 30, 2020 to fund maturities of long-term debt. See "Sources of Capital" herein 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; storm impacts; 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 electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi 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; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND

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LIQUIDITY – "Capital Requirements and Contractual Obligations" in Item 7 of the Form 10-K for additional information.

As of June 30, 2019, Mississippi Power's current liabilities exceeded current assets by approximately $103 million primarily as a result of $300 million of long-term debt that is due within one year.

At June 30, 2019, Mississippi Power had approximately $199 million of cash and cash equivalents. In June 2019, Mississippi Power entered into a new credit arrangement of $50 million that matures in 2022 and amended its existing credit arrangements, which, among other things, extended the maturity dates from 2019 to 2022. Mississippi Power's committed credit arrangements with banks totaled $150 million at June 30, 2019, all of which was unused.

See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein 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 June 30, 2019, 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 $150 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's variable rate revenue bonds. The amount of variable rate revenue bonds outstanding requiring liquidity support as of June 30, 2019 was approximately $40 million.

Short-term debt, including the average amount and maximum amount outstanding, was immaterial at June 30, 2019 and during the three-month period ended June 30, 2019.

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, operating cash flows, and other cash.

Credit Rating Risk

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" of Mississippi Power in Item 7 of the Form 10-K for additional information.

At June 30, 2019, Mississippi 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 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 June 30, 2019, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $286 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.

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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 settlement agreement approved by the Mississippi PSC in August 2018 with respect to the 2018 PEP filings and all unresolved PEP filings for prior years 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. See Note 2 to the financial statements under "Mississippi Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Mississippi Power" herein for additional information.

Financing Activities

In March 2019, Mississippi Power reoffered to the public $43 million of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002, which previously had been purchased and held by 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.

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AND SUBSIDIARY COMPANIES

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)						(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	390		$	443		$	743		$	867
Wholesale revenues, affiliates	117			109			204			192
Other revenues	3			3			6			5
Total operating revenues	510			555			953			1,064
Operating Expenses:
Fuel	139			153			284			321
Purchased power	32			39			55			100
Other operations and maintenance	79			91			166			184
Depreciation and amortization	119			125			237			240
Taxes other than income taxes	11			12			21			24
Asset impairment	—			119			—			119
Gain on dispositions, net	(23		)	—			(23		)	—
Total operating expenses	357			539			740			988
Operating Income	153			16			213			76
Other Income and (Expense):
Interest expense, net of amounts capitalized	(41		)	(46		)	(84		)	(93		)
Other income (expense), net	40			2			41			5
Total other income and (expense)	(1		)	(44		)	(43		)	(88		)
Earnings (Loss) Before Income Taxes	152			(28		)	170			(12		)
Income taxes (benefit)	(51		)	(73		)	(60		)	(172		)
Net Income	203			45			230			160
Net income attributable to noncontrolling interests	29			23			—			17
Net Income Attributable to Southern Power	$	174		$	22		$	230		$	143

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)						(in millions)
Net Income	$	203		$	45		$	230		$	160
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1), $(19), $(10), and $(3), respectively	(1		)	(55		)	(30		)	(8		)
Reclassification adjustment for amounts included in net income, net of tax of $(2), $20, $6, and $12, respectively	(7		)	59			17			35
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $-, and $-, respectively	—			—			—			1
Total other comprehensive income (loss)	(8		)	4			(13		)	28
Comprehensive Income	195			49			217			188
Comprehensive income attributable to noncontrolling interests	29			23			—			17
Comprehensive Income Attributable to Southern Power	$	166		$	26		$	217		$	171

The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2019			2018
	(in millions)
Operating Activities:
Net income	$	230		$	160
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	251			256
Deferred income taxes	(63		)	(252		)
Amortization of investment tax credits	(122		)	(29		)
Asset impairment	—			119
Other, net	(69		)	(10		)
Changes in certain current assets and liabilities —
-Receivables	(9		)	(30		)
-Prepaid income taxes	520			(36		)
-Other current assets	4			3
-Accounts payable	(17		)	(41		)
-Accrued compensation	(9		)	(9		)
-Other current liabilities	3			(4		)
Net cash provided from operating activities	719			127
Investing Activities:
Business acquisitions	(2		)	(64		)
Property additions	(123		)	(198		)
Proceeds from dispositions and asset sales	540			—
Change in construction payables	(23		)	2
Investment in unconsolidated subsidiaries	(116		)	—
Payments pursuant to LTSAs	(31		)	(32		)
Other investing activities	9			15
Net cash provided from (used for) investing activities	254			(277		)
Financing Activities:
Decrease in notes payable, net	—			(41		)
Proceeds —
Short-term borrowings	—			200
Capital contributions from parent company	6			16
Redemptions —
Short-term borrowings	(100		)	—
Senior notes	—			(350		)
Other long-term debt	—			(420		)
Return of capital	(505		)	(250		)
Distributions to noncontrolling interests	(82		)	(42		)
Capital contributions from noncontrolling interests	5			1,210
Payment of common stock dividends	(103		)	(156		)
Other financing activities	(5		)	(15		)
Net cash provided from (used for) financing activities	(784		)	152
Net Change in Cash, Cash Equivalents, and Restricted Cash	189			2
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	181			140
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	370		$	142
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $7 and $10 capitalized for 2019 and 2018, respectively)	$	106		$	109
Income taxes, net	(421		)	109
Noncash transactions — Accrued property additions at end of period	31			33

The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2019		At December 31, 2018
	(in millions)
Current Assets:
Cash and cash equivalents	$	370	$	181
Receivables —
Customer accounts receivable	153		111
Affiliated	49		55
Other	59		116
Materials and supplies	185		220
Prepaid income taxes	489		25
Other current assets	33		37
Total current assets	1,338		745
Property, Plant, and Equipment:
In service	12,862		13,271
Less: Accumulated provision for depreciation	2,255		2,171
Plant in service, net of depreciation	10,607		11,100
Construction work in progress	419		430
Total property, plant, and equipment	11,026		11,530
Other Property and Investments:
Intangible assets, net of amortization of $60 and $61 at June 30, 2019 and December 31, 2018, respectively	313		345
Other investments	144		—
Total other property and investments	457		345
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	370		—
Prepaid LTSAs	107		98
Accumulated deferred income taxes	296		1,186
Income taxes receivable, non-current	36		30
Assets held for sale	599		576
Other deferred charges and assets	289		373
Total deferred charges and other assets	1,697		2,263
Total Assets	$	14,518	$	14,883

The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At June 30, 2019		At December 31, 2018
	(in millions)
Current Liabilities:
Securities due within one year	$	899	$	599
Notes payable	—		100
Accounts payable —
Affiliated	72		92
Other	60		77
Accrued income taxes	23		6
Accrued interest	23		36
Liabilities held for sale	10		15
Other current liabilities	116		106
Total current liabilities	1,203		1,031
Long-term Debt	4,112		4,418
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	106		105
Accumulated deferred ITCs	1,737		1,832
Operating lease obligations	373		—
Other deferred credits and liabilities	169		213
Total deferred credits and other liabilities	2,385		2,150
Total Liabilities	7,700		7,599
Total Stockholders' Equity (See accompanying statements)	6,818		7,284
Total Liabilities and Stockholders' Equity	$	14,518	$	14,883

The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.

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CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)

	Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stockholders' Equity			Noncontrolling Interests			Total
	(in millions)
Balance at December 31, 2017	$	3,662		$	1,478		$	(2	)	$	5,138		$	1,360		$	6,498
Net income attributable to Southern Power	—			121			—			121			—			121
Capital contributions from parent company	1			—			—			1			—			1
Other comprehensive income (loss)	—			—			24			24			—			24
Cash dividends on common stock	—			(78		)	—			(78		)	—			(78		)
Capital contributions from noncontrolling interests	—			—			—			—			9			9
Distributions to noncontrolling interests	—			—			—			—			(13		)	(13		)
Net income (loss) attributable to noncontrolling interests	—			—			—			—			(6		)	(6		)
Other	—			(2		)	5			3			(1		)	2
Balance at March 31, 2018	3,663			1,519			27			5,209			1,349			6,558
Net income attributable to Southern Power	—			22			—			22			—			22
Return of capital to parent company	(250		)	—			—			(250		)	—			(250		)
Capital contributions from parent company	17			—			—			17			—			17
Other comprehensive income (loss)	—			—			4			4			—			4
Cash dividends on common stock	—			(78		)	—			(78		)	—			(78		)
Capital contributions from noncontrolling interests	—			—			—			—			22			22
Distributions to noncontrolling interests	—			—			—			—			(29		)	(29		)
Net income attributable to noncontrolling interests	—			—			—			—			23			23
Sale of noncontrolling interests	(407		)	—			—			(407		)	1,690			1,283
Other	—			1			—			1			1			2
Balance at June 30, 2018	$	3,023		$	1,464		$	31		$	4,518		$	3,056		$	7,574

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CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)

	Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stockholders' Equity			Noncontrolling Interests			Total
	(in millions)
Balance at December 31, 2018	$	1,600		$	1,352		$	16		$	2,968		$	4,316		$	7,284
Net income attributable to Southern Power	—			56			—			56			—			56
Capital contributions from parent company	1			—			—			1			—			1
Other comprehensive income (loss)	—			—			(4		)	(4		)	—			(4		)
Cash dividends on common stock	—			(51		)	—			(51		)	—			(51		)
Capital contributions from noncontrolling interests	—			—			—			—			3			3
Distributions to noncontrolling interests	—			—			—			—			(41		)	(41		)
Net income (loss) attributable to noncontrolling interests	—			—			—			—			(29		)	(29		)
Other	(1		)	(1		)	—			(2		)	1			(1		)
Balance at March 31, 2019	1,600			1,356			12			2,968			4,250			7,218
Net income attributable to Southern Power	—			174			—			174			—			174
Return of capital to parent company	(505		)	—			—			(505		)	—			(505		)
Capital contributions from parent company	7			—			—			7			—			7
Other comprehensive income (loss)	—			—			(8		)	(8		)	—			(8		)
Cash dividends on common stock	—			(52		)	—			(52		)	—			(52		)
Capital contributions from noncontrolling interests	—			—			—			—			2			2
Distributions to noncontrolling interests	—			—			—			—			(47		)	(47		)
Net income attributable to noncontrolling interests	—			—			—			—			29			29
Other	—			1			—			1			(1		)	—
Balance at June 30, 2019	$	1,102		$	1,479		$	4		$	2,585		$	4,233		$	6,818

The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2019 vs. SECOND QUARTER 2018

AND

YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018

OVERVIEW

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, independent power producers, 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.

On June 13, 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for an aggregate cash purchase price of approximately $461 million, including working capital adjustments.

On June 14, 2019, Southern Power entered into an agreement with Bloom Energy to acquire a majority interest in its affiliate DSGP, which owns and operates fuel cell generation facilities in Delaware, for a total amount not to exceed $173 million. FERC approval of the transfer of the facilities is expected to occur in the third quarter 2019; however, the ultimate outcome of this matter cannot be determined at this time.

On May 4, 2019, Southern Power achieved commercial operation of the 385-MW natural gas expansion unit at Plant Mankato and started providing energy under a PPA with Northern States Power on June 1, 2019. The sale of Plant Mankato to Northern States Power remains subject to state commission approvals and is expected to close in fall 2019. If these state commission approvals are not obtained by October 1, 2019, either party has the option to terminate the sale, which, if elected, would result in the payment of a $15 million termination fee by Northern States Power to Southern Power. The ultimate outcome of this matter cannot be determined at this time.

During the six months ended June 30, 2019, Southern Power continued construction of the 100-MW Wildhorse Mountain and the 200-MW Reading wind facilities. See FUTURE EARNINGS POTENTIAL – "Construction Projects" herein for additional information.

At June 30, 2019, Southern Power's average investment coverage ratio for its generating assets (including Plant Mankato), 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, was 93% through 2023 and 91% through 2028, with an average remaining contract duration of approximately 15 years.

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.

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RESULTS OF OPERATIONS

Net Income Attributable to Southern Power

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$152	N/M	$87	60.8

N/M - Not meaningful

Net income attributable to Southern Power for the second quarter 2019 was $174 million compared to $22 million for the corresponding period in 2018. The increase is primarily due to net impacts from the dispositions of Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) in 2018 and Plant Nacogdoches in 2019 (including an asset impairment charge in 2018 and gains on sale, partially offset by decreases in 2019 operating income primarily from PPA capacity revenues) totaling approximately $168 million and net income increases totaling $22 million from a litigation settlement relating to the Roserock solar facility and sales of wind equipment. The increases were partially offset by reductions in net income of approximately $22 million, net, related to the SP Wind tax equity partnership entered into in 2018.

Net income attributable to Southern Power for year-to-date 2019 was $230 million compared to $143 million for the corresponding period in 2018. The increase is primarily due to net impacts from the dispositions of the Florida Plants in 2018 and Plant Nacogdoches in 2019 (including an asset impairment charge in 2018 and gains on sale, partially offset by decreases in 2019 operating income primarily from PPA capacity revenues) totaling approximately $162 million and net income increases totaling $23 million from a litigation settlement relating to the Roserock solar facility and sales of wind equipment. The increases were partially offset by $54 million in state income tax benefits recorded in 2018 arising from the reorganization of Southern Power's legal entities that own and operate certain solar facilities and reductions in net income of approximately $43 million, net, related to the SP Wind tax equity partnership entered into in 2018.

See Notes 7, 10, and 15 to the financial statements in Item 8 of the Form 10-K for additional information on the tax equity partnerships, the legal entity reorganization, and the Florida Plants dispositions, respectively. Also see Note (C) to the Condensed Financial Statements herein for additional information on the Roserock solar facility litigation settlement and Note (K) to the Condensed Financial Statements herein for additional information on the disposition of Plant Nacogdoches and sales of wind equipment.

Operating Revenues

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(45)	(8.1)	$(111)	(10.4)

Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities and a biomass generating facility (through the sale of Plant Nacogdoches), 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

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support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.

Solar and Wind Energy Revenue

Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have 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:

	Second Quarter 2019		Second Quarter 2018		Year-to-Date 2019		Year-to-Date 2018
	(in millions)
PPA capacity revenues	$	125	$	144	$	252	$	282
PPA energy revenues	291		302		518		556
Total PPA revenues	416		446		770		838
Non-PPA revenues	91		106		177		221
Other revenues	3		3		6		5
Total operating revenues	$	510	$	555	$	953	$	1,064

In the second quarter 2019, total operating revenues were $510 million, reflecting a $45 million, or 8%, decrease from the corresponding period in 2018. The decrease in operating revenues was primarily due to the following:

• PPA capacity revenues decreased $19 million, or 13%, primarily due to decreases totaling $21 million attributable to the sales of the Florida Plants in December 2018 and Plant Nacogdoches in June 2019 and $5 million from the contractual expiration of an affiliate natural gas PPA, partially offset by a $6 million increase in new PPA capacity revenues from existing gas facilities.

• PPA energy revenues decreased $11 million, or 4%, due to a $7 million decrease related to a decrease in the average cost of fuel and purchased power and a $4 million decrease in sales related to solar and wind facilities primarily driven by a decrease in the volume of KWHs generated.

• Non-PPA revenues decreased $15 million, or 14%, due to a $16 million decrease in the volume of KWHs sold through short-term sales.

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For year-to-date 2019, total operating revenues were $953 million, reflecting a $111 million, or 10%, decrease from the corresponding period in 2018. The decrease in operating revenues was primarily due to the following:

• PPA capacity revenues decreased $30 million, or 11%, primarily due to decreases of $38 million attributable to the sales of the Florida Plants in December 2018 and Plant Nacogdoches in June 2019 and $5 million from the contractual expiration of an affiliate natural gas PPA, partially offset by an $11 million increase in new PPA capacity revenues from existing natural gas facilities.

• PPA energy revenues decreased $38 million, or 7%, primarily due to a $30 million decrease in sales from natural gas facilities, primarily driven by a $51 million decrease in the average cost of fuel and purchased power, partially offset by a $23 million increase in the volume of KWHs sold due to increased customer load, and an $8 million decrease in sales related to solar and wind facilities primarily driven by a decrease in the volume of KWHs generated.

• Non-PPA revenues decreased $44 million, or 20%, due to a $36 million decrease in the volume of KWHs sold through short-term sales and an $8 million decrease in the market price of energy.

Fuel and Purchased Power Expenses

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

	Second Quarter 2019	Second Quarter 2018	Year-to-Date 2019	Year-to-Date 2018
	(in billions of KWHs)
Generation	11.7	12.2	21.9	22.0
Purchased power	1.0	1.2	1.8	2.2
Total generation and purchased power	12.7	13.4	23.7	24.2
Total generation and purchased power, excluding solar, wind, and tolling agreements	7.1	7.2	13.7	13.9

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:

	Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(14	)	(9.2)	$	(37	)	(11.5)
Purchased power	(7		)	(17.9)	(45		)	(45.0)
Total fuel and purchased power expenses	$	(21	)		$	(82	)

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In the second quarter 2019, total fuel and purchased power expenses decreased $21 million, or 10.9%, compared to the corresponding period in 2018. Fuel expense decreased $14 million primarily due to a decrease in the average cost of fuel per KWH generated. Purchased power expense decreased $7 million associated with the volume of KWHs purchased.

For year-to-date 2019, total fuel and purchased power expenses decreased $82 million, or 19%, compared to the corresponding period in 2018. Fuel expense decreased $37 million primarily due to a decrease in the average cost of fuel per KWH generated. Purchased power expense decreased $45 million due to a $25 million decrease associated with the average cost of purchased power and a $20 million decrease associated with the volume of KWHs purchased.

Other Operations and Maintenance Expenses

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(12)	(13.2)	$(18)	(9.8)

In the second quarter 2019, other operations and maintenance expenses were $79 million compared to $91 million for the corresponding period in 2018. The decrease was primarily due to a $14 million gain on the sale of wind turbine equipment in the second quarter 2019.

For year-to-date 2019, other operations and maintenance expenses were $166 million compared to $184 million for the corresponding period in 2018. The decrease was primarily due to a $14 million gain on the sale of wind turbine equipment in the second quarter 2019, lower scheduled outage and maintenance expenses, and the recovery of legal costs related to the Roserock litigation settlement in the first quarter 2019.

See Note (K) to the Condensed Financial Statements under "Southern Power – Development Projects" herein for additional information on the sale of wind turbine equipment. Also see Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information on the Roserock solar facility litigation settlement.

Asset Impairment

In the second quarter 2018, a $119 million asset impairment charge was recorded in anticipation of the sale of the Florida Plants. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Sale of Natural Gas Plants" for additional information.

Gain on Dispositions, net

In the second quarter 2019, the sale of Plant Nacogdoches resulted in a $23 million gain. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.

Other Income (Expense), net

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$38	N/M	$36	N/M

N/M - Not meaningful

In the second quarter 2019, other income (expense), net was $40 million compared to $2 million for the corresponding period in 2018. For year-to date 2019, other income (expense), net was $41 million compared to $5 million for the corresponding period in 2018. The increases were primarily due to a $36 million gain arising from the settlement of litigation related to the Roserock solar facility. See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information.

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Income Taxes (Benefit)

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$22	30.1	$112	65.1

In the second quarter 2019, income tax benefit was $51 million compared to $73 million for the corresponding period in 2018. This change was primarily due to a $43 million increase in income tax expense as a result of higher pre-tax earnings and a $41 million reduction of tax benefits from wind PTCs primarily as a result of the 2018 sale of a noncontrolling tax equity interest in SP Wind, partially offset by a $75 million tax benefit resulting from the recognition of deferred ITCs remaining from the original construction of Plant Nacogdoches.

For year-to-date 2019, income tax benefit was $60 million compared to $172 million for the corresponding period in 2018. This change was primarily due to an $80 million reduction of tax benefits from wind PTCs primarily as a result of the sale of a noncontrolling tax equity interest in SP Wind, $54 million in tax benefits recorded in 2018 related to changes in state apportionment rates following the reorganization of Southern Power's legal entities that own and operate certain solar facilities, and a $51 million increase in income tax expense as a result of higher pre-tax earnings, partially offset by a $75 million tax benefit resulting from the recognition of deferred ITCs remaining from the original construction of Plant Nacogdoches.

See Note (G) to the Condensed Financial Statements herein for additional information.

Net Income Attributable to Noncontrolling Interests

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$6	26.1	$(17)	N/M

N/M - Not meaningful

In the second quarter 2019, net income attributable to noncontrolling interests was $29 million compared to $23 million for the corresponding period in 2018. The increase was primarily due to an allocation of approximately $26 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement, partially offset by $25 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018.

For year-to-date 2019, net income attributable to noncontrolling interests was immaterial compared to $17 million for the corresponding period in 2018. The decrease was primarily due to $48 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018, partially offset by an allocation of approximately $29 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement.

See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein and Notes 1 and 7 to the financial statements in Item 8 of the Form 10-K under "General" and "Southern Power," respectively, for additional information.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. Future earnings potential will be impacted by the sales of noncontrolling renewable facility interests and the sale of the Florida Plants in 2018, the sale of Plant Nacogdoches in the second quarter 2019, and the pending disposition of Plant Mankato expected in fall 2019. The level of Southern Power's future earnings 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

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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 June 13, 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for an aggregate cash purchase price of approximately $461 million, including working capital adjustments. The pre-tax income related to Plant Nacogdoches was $16 million and $13 million for the six months ended June 30, 2019 and 2018, respectively.

On June 14, 2019, Southern Power entered into an agreement with Bloom Energy to acquire a majority interest in its affiliate DSGP, which owns and operates fuel cell generation facilities in Delaware, for a total amount not to exceed $173 million. FERC approval of the transfer of the facilities is expected to occur in the third quarter 2019; however, the ultimate outcome of this matter cannot be determined at this time. See Notes (E) and (K) to the Condensed Financial Statements under "Southern Power – Equity Method Investments" and "Southern Power – Development Projects," respectively, herein for additional information.

On May 4, 2019, Southern Power achieved commercial operation of the 385-MW natural gas expansion unit at Plant Mankato and started providing energy under a PPA with Northern States Power on June 1, 2019. The sale of Plant Mankato to Northern States Power remains subject to state commission approvals and is expected to close in fall 2019. If these state commission approvals are not obtained by October 1, 2019, either party has the option to terminate the sale, which, if elected, would result in the payment of a $15 million termination fee by Northern States Power to Southern Power. The ultimate outcome of this matter cannot be determined at this time. Pre-tax income for Plant Mankato was immaterial for both the six months ended June 30, 2019 and 2018.

Southern Power entered into a tax equity partnership in June 2019 for the Wildhorse Mountain wind facility, with funding of tax equity amounts expected to occur upon commercial operation, which is expected to occur in the fourth quarter 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. For additional information relating to these factors, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.

Power Sales Agreements

See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K for additional information regarding Southern Power's PPAs. Generally, under the solar and wind generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.

Environmental Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, water quality, or other environmental and health concerns could also significantly affect Southern Power. While 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, the full impact of any such legislative or regulatory changes cannot be determined at this time.

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Construction Projects

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" of Southern Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.

During the six months ended June 30, 2019, Southern Power completed construction of and placed in service the 385-MW Plant Mankato expansion and continued construction of two other projects as described in the table below. Total aggregate construction costs, excluding acquisition costs, are expected to be between $405 million and $450 million for the Wildhorse Mountain and Reading facilities. At June 30, 2019, total costs of construction incurred for these projects were $186 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Counterparties	PPA Contract Period
Projects Completed During the Six Months Ended June 30, 2019
Mankato expansion(a)	Natural Gas	385	Mankato, MN	May 2019	Northern States Power Company	20 years
Projects Under Construction as of June 30, 2019
Wildhorse Mountain(b)	Wind	100	Pushmataha County, OK	Fourth quarter 2019	Arkansas Electric Cooperative	20 years
Reading(c)	Wind	200	Osage and Lyon Counties, KS	Second quarter 2020	Royal Caribbean Cruises LTD	12 years

(a) In November 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato, including this expansion that was completed during May 2019. This transaction is subject to state commission approvals and is expected to close in fall 2019. The expansion unit started providing energy under a PPA with Northern States Power on June 1, 2019.

(b) In May 2018, Southern Power purchased 100% of the Wildhorse Mountain facility. Southern Power entered into a tax equity partnership in June 2019 with funding of tax equity amounts expected to occur upon commercial operation.

(c) 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. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the class B membership interests.

Development Projects

See Note 15 to the financial statements under "Southern Power – Development Projects" in Item 8 of the Form 10-K for additional information.

Southern Power continues to evaluate and refine the deployment of wind turbine equipment purchased in 2016 and 2017 to potential joint development and construction projects as well as the amount of MW capacity to be constructed. During the six months ended June 30, 2019, certain wind turbine equipment was sold, resulting in a gain on the sale of approximately $14 million.

Other Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" and "Power Sales Agreements – General" of Southern Power in Item 7 for additional information.

Southern Power is involved in various other matters that could affect future earnings, including matters being litigated, as well as other regulatory and business matters. 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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

The ultimate outcome of such pending or potential litigation, regulatory matters, or other business matters cannot be determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Power's financial statements.

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 withheld payment of approximately $26 million to the construction contractor, which placed a lien on the Roserock facility for the same amount. In 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas against XL Insurance America, Inc. and North American Elite Insurance Company seeking recovery from an insurance policy for damages resulting from the hail event and McCarthy's installation practices. In June 2018, the court 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. Separate lawsuits were filed between Roserock and McCarthy, as well as other parties, and that litigation was consolidated in the U.S. District Court for the Western District of Texas. On April 18, 2019, Roserock and the parties to the state and federal lawsuits executed a settlement agreement and mutual release that resolved both lawsuits. Following execution of the agreement, the lawsuits were dismissed, Southern Power paid McCarthy the amounts previously withheld, and McCarthy released its lien. As part of the settlement, Roserock received funds that covered all related legal costs, damages, and the replacement costs of certain solar panels. Funds received by Southern Power in excess of the initial replacement costs were recognized as a gain and included in other income (expense), net in 2019. A portion of the pre-tax gain was allocated to noncontrolling interests and Southern Power recognized a $12 million after-tax gain.

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 Item 8 of the Form 10-K. 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Power in Item 7 of the Form 10-K for a complete discussion of Southern Power's critical accounting policies and estimates.

Recently Issued Accounting Standards

See Note (A) to the Condensed Financial Statements herein for information regarding Southern Power's recently adopted accounting standards.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Power in Item 7 of the Form 10-K for additional information. Southern Power's financial condition remained stable at June 30, 2019. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements as needed to meet future capital and liquidity needs. See "Sources of Capital" herein for additional information on lines of credit.

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Southern Power also utilizes tax equity partnerships, where the tax partner takes significantly all of the federal tax benefits, as a financing source. 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 the first six months of 2019, Southern Power did not receive any material tax equity funding amounts. See Note 1 to the financial statements under "Hypothetical Liquidation at Book Value" in Item 8 of the Form 10-K for additional information on the HLBV methodology.

Net cash provided from operating activities totaled $719 million for the first six months of 2019 compared to $127 million for the first six months of 2018. The increase in net cash provided from operating activities was primarily due to the utilization of income tax credits of $520 million in 2019. Net cash provided from investing activities totaled $254 million for the first six months of 2019 primarily due to proceeds from the disposition of Plant Nacogdoches and wind equipment sales, partially offset by Southern Power's investment in DSGP and ongoing construction activities. Net cash used for financing activities totaled $784 million for the first six months of 2019 primarily due to returns of capital to Southern Company, common stock dividends, the repayment of a short-term bank loan, and distributions to noncontrolling interests. Cash flows from financing activities may vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2019 include a $464 million increase in prepaid income taxes due to the expected utilization of tax credits for the remainder of the 2019 tax year, a $493 million decrease in plant in service primarily as a result of the sale of Plant Nacogdoches, a $370 million increase in operating lease right-of-use assets along with a corresponding increase in operating lease obligations of $373 million due to the adoption of ASU No. 2016-02, a $144 million increase in other investments primarily related to Southern Power's investment in DSGP, and a $466 million decrease in stockholder's equity primarily due to returns of capital to Southern Company. See Note (K) under "Southern Power" and Note (L) to the Condensed Financial Statements herein for additional information.

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

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements and contractual obligations. Approximately $900 million will be required through June 30, 2020 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

Southern Power's construction program includes estimates for potential plant acquisitions and placeholder growth, new construction and development, capital improvements, and work to be performed under LTSAs and is subject to periodic review and revision. Actual construction costs, including acquisitions, 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 FUTURE EARNINGS POTENTIAL – "Construction Projects" herein for additional information.

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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

As of June 30, 2019, Southern Power had cash and cash equivalents of approximately $370 million.

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. Commercial paper is included in notes payable on the condensed consolidated balance sheets.

Details of short-term borrowings were as follows:

	Short-term Borrowings During the Period (*)
	Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)
Commercial paper	$	7	2.6	%	$	75
Short-term loans	58		3.1	%	100
Total	$	65	3.0	%

(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2019. No short-term debt was outstanding at June 30, 2019.

In May 2019, Southern Power amended and restated its committed credit facility (Facility) to extend the maturity date to 2024 and decrease the borrowing capacity from $750 million to $600 million. At June 30, 2019, $39 million of the Facility had been used for letters of credit and $561 million remains unused. 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. 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" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

The Facility 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 purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of Southern Power to the extent such debt is non-recourse to Southern Power, and capitalization excludes the capital stock or other equity attributable to such subsidiary. Southern Power is currently in compliance with all covenants in the Facility.

Southern Power also has a $120 million continuing letter of credit facility expiring in 2021 for standby letters of credit. At June 30, 2019, $90 million has been used for letters of credit, primarily as credit support for PPA requirements, and $30 million remains unused.

In addition, at June 30, 2019, Southern Power had $104 million of cash collateral posted related to PPA requirements.

Southern Power's subsidiaries do not borrow under the commercial paper program and are not parties to, and do not borrow under, the Facility or the continuing letter of credit facility.

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.

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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 June 30, 2019 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	29
At BBB- and/or Baa3	$	339
At BB+ and/or Ba1(*)	$	1,054

(*) 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.

Financing Activities

In May 2019, Southern Power repaid at maturity a $100 million short-term floating rate bank loan.

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.

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AND SUBSIDIARY COMPANIES

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)						(in millions)
Operating Revenues:
Natural gas revenues (includes revenue taxes of $23, $23, $78, and $74, respectively)	$	688		$	710		$	2,163		$	2,341
Alternative revenue programs	1			(4		)	—			(27		)
Other revenues	—			24			—			55
Total operating revenues	689			730			2,163			2,369
Operating Expenses:
Cost of natural gas	191			228			877			949
Cost of other sales	—			5			—			12
Other operations and maintenance	199			238			433			514
Depreciation and amortization	119			126			238			255
Taxes other than income taxes	46			48			128			125
Goodwill impairment	—			—			—			42
Loss on disposition	—			36			—			36
Total operating expenses	555			681			1,676			1,933
Operating Income	134			49			487			436
Other Income and (Expense):
Earnings from equity method investments	31			31			80			74
Interest expense, net of amounts capitalized	(59		)	(59		)	(118		)	(118		)
Other income (expense), net	6			3			10			15
Total other income and (expense)	(22		)	(25		)	(28		)	(29		)
Earnings Before Income Taxes	112			24			459			407
Income taxes	6			55			83			159
Net Income (Loss)	$	106		$	(31	)	$	376		$	248

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)						(in millions)
Net Income (Loss)	$	106		$	(31	)	$	376		$	248
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1), $-, $(1), and $-, respectively	(3		)	1			(3		)	1
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $-, and $1, respectively	—			—			—			2
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $(1), $-, $(1), and $-, respectively	—			—			(1		)	—
Total other comprehensive income (loss)	(3		)	1			(4		)	3
Comprehensive Income (Loss)	$	103		$	(30	)	$	372		$	251

The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2019			2018
	(in millions)
Operating Activities:
Net income	$	376		$	248
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	238			255
Deferred income taxes	59			(12		)
Mark-to-market adjustments	30			2
Goodwill impairment	—			42
Loss on disposition	—			36
Other, net	(26		)	(24		)
Changes in certain current assets and liabilities —
-Receivables	717			504
-Natural gas for sale, net of temporary LIFO liquidation	256			295
-Other current assets	29			41
-Accounts payable	(604		)	(125		)
-Accrued taxes	(54		)	38
-Accrued compensation	(34		)	(6		)
-Other current liabilities	(56		)	24
Net cash provided from operating activities	931			1,318
Investing Activities:
Property additions	(603		)	(679		)
Cost of removal, net of salvage	(33		)	(18		)
Change in construction payables, net	26			(6		)
Investment in unconsolidated subsidiaries	(18		)	(60		)
Proceeds from dispositions and asset sales	32			364
Other investing activities	10			18
Net cash used for investing activities	(586		)	(381		)
Financing Activities:
Decrease in notes payable, net	(158		)	(515		)
Redemptions — Gas facility revenue bonds	—			(200		)
Payment of common stock dividends	(235		)	(235		)
Other financing activities	38			10
Net cash used for financing activities	(355		)	(940		)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(10		)	(3		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	70			78
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	60		$	75
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $3 and $3 capitalized for 2019 and 2018, respectively)	$	125		$	129
Income taxes, net	96			106
Noncash transactions — Accrued property additions at end of period	123			129

The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2019			At December 31, 2018
	(in millions)
Current Assets:
Cash and cash equivalents	$	56		$	64
Receivables —
Energy marketing receivables	361			801
Customer accounts receivable	281			370
Unbilled revenues	63			213
Affiliated	10			11
Other accounts and notes receivable	100			142
Accumulated provision for uncollectible accounts	(31		)	(30		)
Natural gas for sale	268			524
Prepaid expenses	120			118
Assets from risk management activities, net of collateral	101			219
Other regulatory assets	56			73
Other current assets	44			50
Total current assets	1,429			2,555
Property, Plant, and Equipment:
In service	15,680			15,177
Less: Accumulated depreciation	4,522			4,400
Plant in service, net of depreciation	11,158			10,777
Construction work in progress	628			580
Total property, plant, and equipment	11,786			11,357
Other Property and Investments:
Goodwill	5,015			5,015
Equity investments in unconsolidated subsidiaries	1,509			1,538
Other intangible assets, net of amortization of $161 and $145 at June 30, 2019 and December 31, 2018, respectively	85			101
Miscellaneous property and investments	20			20
Total other property and investments	6,629			6,674
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	95			—
Other regulatory assets, deferred	636			669
Other deferred charges and assets	186			193
Total deferred charges and other assets	917			862
Total Assets	$	20,761		$	21,448

The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2019		At December 31, 2018
	(in millions)
Current Liabilities:
Securities due within one year	$	351	$	357
Notes payable	492		650
Energy marketing trade payables	393		856
Accounts payable —
Affiliated	38		45
Other	294		402
Customer deposits	92		133
Accrued taxes —
Accrued income taxes	17		66
Other accrued taxes	70		75
Accrued interest	57		55
Accrued compensation	64		100
Liabilities from risk management activities, net of collateral	22		76
Other regulatory liabilities	97		79
Other current liabilities	124		130
Total current liabilities	2,111		3,024
Long-term Debt	5,565		5,583
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,088		1,016
Deferred credits related to income taxes	910		940
Employee benefit obligations	354		357
Operating lease obligations	79		—
Other cost of removal obligations	1,598		1,585
Accrued environmental remediation	247		268
Other deferred credits and liabilities	50		105
Total deferred credits and other liabilities	4,326		4,271
Total Liabilities	12,002		12,878
Common Stockholder's Equity (See accompanying statements)	8,759		8,570
Total Liabilities and Stockholder's Equity	$	20,761	$	21,448

The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.

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CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY (UNAUDITED)

	Paid-In Capital		Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income (Loss)			Total
	(in millions)
Balance at December 31, 2017	$	9,214	$	(212	)	$	20		$	9,022
Net income	—		279			—			279
Capital contributions from parent company	14		—			—			14
Other comprehensive income (loss)	—		—			2			2
Cash dividends on common stock	—		(118		)	—			(118		)
Other	—		(4		)	4			—
Balance at March 31, 2018	9,228		(55		)	26			9,199
Net loss	—		(31		)	—			(31		)
Capital contributions from parent company	8		—			—			8
Other comprehensive income (loss)	—		—			1			1
Cash dividends on common stock	—		(117		)	—			(117		)
Other	—		1			—			1
Balance at June 30, 2018	$	9,236	$	(202	)	$	27		$	9,061
Balance at December 31, 2018	$	8,856	$	(312	)	$	26		$	8,570
Net income	—		270			—			270
Capital contributions from parent company	17		—			—			17
Other comprehensive income (loss)	—		—			(1		)	(1		)
Cash dividends on common stock	—		(118		)	—			(118		)
Balance at March 31, 2019	8,873		(160		)	25			8,738
Net income	—		106			—			106
Capital contributions from parent company	35		—			—			35
Other comprehensive income (loss)	—		—			(3		)	(3		)
Cash dividends on common stock	—		(117		)	—			(117		)
Balance at June 30, 2019	$	8,908	$	(171	)	$	22		$	8,759

The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed financial statements.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2019 vs. SECOND QUARTER 2018

AND

YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018

OVERVIEW

Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through utilities in four states – Nicor Gas in Illinois, Atlanta Gas Light in Georgia, Virginia Natural Gas in Virginia, and Chattanooga Gas in 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, and gas marketing services – and one non-reportable segment, all other. See Note (M) to the Condensed Financial Statements herein and "BUSINESS – The Southern Company System – Southern Company Gas" in Item 1 of the Form 10-K 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.

Atlanta Gas Light filed a rate case on June 3, 2019 and Nicor Gas filed a rate case in November 2018. Both rate cases are expected to be finalized in 2019. The ultimate outcome of these matters cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters" herein and Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K 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.

• 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 primarily consisted of Florida City Gas, to NextEra Energy.

See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information on these dispositions.

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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.

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 payables. However, these items are comparable when reviewing Southern Company Gas' annual results. Operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter.

RESULTS OF OPERATIONS

Net Income (Loss)

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$137	N/M	$128	51.6

N/M - Not meaningful

In the second quarter 2019, net income was $106 million compared to a net loss of $31 million for the corresponding period in 2018. Excluding a $73 million net loss in 2018 from the Southern Company Gas Dispositions and $7 million net income in 2019 from the sale of Triton, net income increased $57 million. This increase was primarily due to an increase of $44 million at wholesale gas services primarily due to significant gas price volatility during the second quarter 2018, continued investment in infrastructure replacement programs, and lower income taxes, primarily at Atlanta Gas Light due to increased flowback of excess deferred income taxes in lieu of a rate increase as previously authorized by the Georgia PSC.

For year-to-date 2019, net income was $376 million compared to $248 million for the corresponding period in 2018. Excluding an $81 million net loss in 2018 from the Southern Company Gas Dispositions and $7 million net income in 2019 from the sale of Triton, net income increased $40 million. This increase was primarily due to continued investment in infrastructure replacement programs and base rate changes, lower income taxes primarily at Atlanta Gas Light due to increased flowback of excess deferred income taxes in lieu of a rate increase as previously authorized by the Georgia PSC, the impact of adopting a new paid time off policy to align with the Southern Company system in first quarter 2018, and an increase in earnings from equity method investments in 2019. Partially offsetting these increases were a decrease of $13 million at wholesale gas services, a contractor litigation

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settlement recorded in the first quarter 2018, and increased depreciation and amortization primarily due to continued infrastructure investments at gas distribution operations.

See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings – Atlanta Gas Light" and " – Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light – PRP" in Item 8 of the Form 10-K for additional information on Atlanta Gas Light's stipulation reflecting the impacts of the Tax Reform Legislation and the contractor litigation settlement, respectively.

Natural Gas Revenues, including Alternative Revenue Programs

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(17)	(2.4)	$(151)	(6.5)

In the second quarter 2019, natural gas revenues, including alternative revenue programs, were $689 million compared to $706 million for the corresponding period in 2018. For year-to-date 2019, natural gas revenues, including alternative revenue programs, were $2.2 billion compared to $2.3 billion for the corresponding period in 2018.

Details of the changes in natural gas revenues, including alternative revenue programs, were as follows:

	Second Quarter 2019					Year-to-Date 2019
	(in millions)			(% change)		(in millions)			(% change)
Natural gas revenues – prior year	$	706				$	2,314
Estimated change resulting from –
Infrastructure replacement programs and base rate changes	10			1.4	%	42			1.8	%
Gas costs and other cost recovery	(13		)	(1.8	)	49			2.1
Weather	(7		)	(1.1	)	—			—
Wholesale gas services	64			9.1		(16		)	(0.7	)
Southern Company Gas Dispositions	(70		)	(9.9	)	(237		)	(10.2	)
Other	(1		)	(0.1	)	11			0.5
Natural gas revenues – current year	$	689		(2.4	)%	$	2,163		(6.5	)%

Revenues from infrastructure replacement programs and base rate changes increased in the second quarter and year-to-date 2019 compared to the corresponding periods in 2018 primarily due to increases of $4 million and $25 million, respectively, at Nicor Gas and $5 million and $14 million, respectively, at Atlanta Gas Light. These amounts include gas distribution operations' continued investments recovered through infrastructure replacement programs and base rate increases as well as the effect of revenues deferred in 2018 as a result of the Tax Reform Legislation. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information.

Revenues associated with gas costs and other cost recovery decreased in the second quarter 2019 and increased year-to-date 2019 compared to the corresponding periods in 2018. The decrease in the second quarter 2019 is primarily due to lower natural gas prices and decreased volumes of natural gas sold. The increase for year-to-date 2019 is primarily due to increased natural gas prices in the first quarter 2019, partially offset by decreased volumes of natural gas sold year-to-date 2019. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. See "Cost of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.

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Revenues decreased in the second quarter 2019 due to warmer weather in Illinois and Georgia compared to the corresponding period in 2018. See the weather discussion herein for additional information.

Revenues from wholesale gas services increased in the second quarter 2019 and decreased year-to-date 2019 compared to the corresponding periods in 2018. The increase in the second quarter 2019 is primarily due to derivative gains, partially offset by decreased commercial activity. For year-to-date 2019, the decrease is primarily due to decreased commercial activity, partially offset by derivative gains. See "Segment Information – Wholesale Gas Services" herein for additional information.

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 Heating Degree Days information for Illinois and Georgia, the primary locations where Southern Company Gas' operations are impacted by weather.

	Second Quarter			2019 vs. 2018		2019 vs. normal		Year-to-Date			2019 vs. 2018		2019 vs. normal
	Normal(*)	2019	2018	(warmer)		colder (warmer)		Normal(*)	2019	2018	colder (warmer)		colder (warmer)
Illinois	635	659	767	(14.1	)%	3.8	%	3,679	3,956	3,809	3.9	%	7.5	%
Georgia	124	86	175	(50.9	)%	(30.6	)%	1,566	1,298	1,539	(15.7	)%	(17.1	)%

(*) Normal represents the 10-year average from January 1, 2009 through June 30, 2018 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.

	Gas Distribution Operations								Gas Marketing Services
	Second Quarter				Year-to-Date				Second Quarter					Year-to-Date
	2019		2018		2019		2018		2019			2018		2019			2018
	(in millions)								(in millions)
Pre-tax	$	—	$	4	$	2	$	2	$	(1	)	$	2	$	(1	)	$	(1	)
After tax	—		3		2		2		(1		)	1		(1		)	(1		)

The following table provides the number of customers served by Southern Company Gas at June 30, 2019 and 2018:

	June 30,
	2019		2018		2019 vs. 2018
	(in thousands, except market share %)				(% change)
Gas distribution operations(a)	4,231		4,609		(8.2	)%
Gas marketing services
Energy customers(b)	622		696		(10.6	)%
Market share of energy customers in Georgia	28.8	%	29.4	%

(a) Includes total customers of approximately 407,000 at June 30, 2018 related to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold in July 2018. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

(b) Gas marketing services' customers are primarily located in Georgia and Illinois. Also included as of June 30, 2018 were approximately 70,000 customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2018.

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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.

Other Revenues

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(24)	(100.0)	$(55)	(100.0)

Other revenues related to Pivotal Home Solutions, which was sold in June 2018. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

Cost of Natural Gas

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(37)	(16.2)	$(72)	(7.6)

Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. Cost of natural gas at gas distribution operations represented 80% and 85% of total cost of natural gas for the second quarter and year-to-date 2019, respectively. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Cost of Natural Gas" of Southern Company Gas in Item 7 of the Form 10-K and "Natural Gas Revenues, including Alternative Revenue Programs" herein for additional information.

In the second quarter 2019, cost of natural gas was $191 million compared to $228 million for the corresponding period in 2018. Excluding a $25 million decrease related to the Southern Company Gas Dispositions, cost of natural gas decreased $12 million. This decrease reflects a 5.7% decrease in natural gas prices and a decrease in the volume of natural gas sold in the second quarter 2019 primarily as a result of warmer weather in Illinois and Georgia compared to the corresponding period in 2018.

For year-to-date 2019, cost of natural gas was $877 million compared to $949 million for the corresponding period in 2018. Excluding a $104 million decrease related to the Southern Company Gas Dispositions, cost of natural gas increased $32 million. This increase reflects an increase in natural gas prices, partially offset by a decrease in the volume of natural gas sold year-to-date 2019 compared to the corresponding period in 2018.

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

	Second Quarter		2019 vs. 2018		Year-to-Date		2019 vs. 2018
	2019	2018			2019	2018
Gas distribution operations (mmBtu in millions)
Firm	99	119	(16.8	)%	396	434	(8.8	)%
Interruptible	22	25	(12.0	)%	46	49	(6.1	)%
Total(*)	121	144	(16.0	)%	442	483	(8.5	)%
Wholesale gas services (mmBtu in millions/day)
Daily physical sales	5.7	6.4	(10.9	)%	6.3	6.6	(4.5	)%
Gas marketing services (mmBtu in millions)
Firm:
Georgia	4	5	(20.0	)%	19	22	(13.6	)%
Illinois	2	2	—		8	8	—
Ohio	1	2	(50.0	)%	8	11	(27.3	)%
Other	1	1	—		2	2	—
Interruptible large commercial and industrial	3	3	—		7	7	—
Total	11	13	(15.4	)%	44	50	(12.0	)%

(*) Includes total volumes of natural gas sold of 12 mmBtu and 38 mmBtu for the three and six months ended June 30, 2018 related to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold in July 2018. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas – Sale of Elizabethtown Gas and Elkton Gas" and " – Sale of Florida City Gas" for additional information.

Cost of Other Sales

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(5)	(100.0)	$(12)	(100.0)

Cost of other sales related to Pivotal Home Solutions, which was sold in June 2018. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

Other Operations and Maintenance Expenses

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(39)	(16.4)	$(81)	(15.8)

In the second quarter 2019, other operations and maintenance expenses were $199 million compared to $238 million for the corresponding period in 2018. Excluding a $34 million decrease related to the Southern Company Gas Dispositions, other operations and maintenance expenses decreased $5 million. This decrease was primarily due to disposition-related costs incurred during 2018 and decreased compensation and benefit costs, partially offset by an increase in expenses associated with pipeline compliance and maintenance activities.

For year-to-date 2019, other operations and maintenance expenses were $433 million compared to $514 million for the corresponding period in 2018. Excluding a $63 million decrease related to the Southern Company Gas Dispositions, other operations and maintenance expenses decreased $18 million. This decrease was primarily due to

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a one-time adjustment in 2018 for the adoption of a new paid time off policy, disposition-related costs incurred during 2018, and decreased compensation and benefits costs, partially offset by an increase in expenses associated with pipeline compliance and maintenance activities. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company Gas in Item 7 of the Form 10-K for additional information.

Depreciation and Amortization

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(7)	(5.6)	$(17)	(6.7)

In the second quarter 2019, depreciation and amortization was $119 million compared to $126 million for the corresponding period in 2018. Excluding a $10 million decrease related to the Southern Company Gas Dispositions, depreciation and amortization increased $3 million. This increase was primarily due to continued infrastructure investments at gas distribution operations.

For year-to-date 2019, depreciation and amortization was $238 million compared to $255 million for the corresponding period in 2018. Excluding a $26 million decrease related to the Southern Company Gas Dispositions, depreciation and amortization increased $9 million. This increase was primarily due to continued infrastructure investments at gas distribution operations.

Taxes Other Than Income Taxes

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	(4.2)	$3	2.4

In the second quarter 2019, taxes other than income taxes were $46 million compared to $48 million for the corresponding period in 2018. Excluding a $2 million decrease related to the Southern Company Gas Dispositions, taxes other than income taxes remained unchanged.

For year-to-date 2019, taxes other than income taxes were $128 million compared to $125 million for the corresponding period in 2018. Excluding a $6 million decrease related to the Southern Company Gas Dispositions, taxes other than income taxes increased $9 million. This increase primarily reflects increases in Nicor Gas' invested capital tax as a result of increased infrastructure investments and increased revenue tax expenses as a result of higher natural gas revenues at Nicor Gas, both of which are passed through to customers.

Goodwill Impairment

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$—	N/M	$(42)	N/M

N/M - Not meaningful

A goodwill impairment charge of $42 million was recorded during the first quarter 2018 in contemplation of the sale of Pivotal Home Solutions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

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Loss on Disposition

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(36)	N/M	$(36)	N/M

N/M - Not meaningful

As a result of the sale of Pivotal Home Solutions in June 2018, a $36 million pre-tax loss was recorded in the second quarter 2018. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

Earnings from Equity Method Investments

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$6	8.1

In the second quarter 2019 and 2018, earnings from equity method investments were $31 million. For year-to-date 2019, earnings from equity method investments were $80 million compared to $74 million for the corresponding period in 2018. For both the second quarter and year-to-date 2019, earnings from equity method investments reflect higher earnings from SNG as a result of rate increases implemented by SNG that became effective September 2018, partially offset by a $6 million pre-tax loss on the sale of Triton in May 2019. See Note (E) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

Other Income (Expense), Net

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$3	100.0	$(5)	(33.3)

For year-to-date 2019, other income (expense), net was $10 million compared to $15 million for the corresponding period in 2018. This decrease was primarily due to a contractor litigation settlement in the first quarter 2018. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light – PRP" in Item 8 of the Form 10-K for additional information.

Income Taxes

Second Quarter 2019 vs. Second Quarter 2018		Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)	(% change)	(change in millions)	(% change)
$(49)	(89.1)	$(76)	(47.8)

In the second quarter 2019, income taxes were $6 million compared to $55 million for the corresponding period in 2018. Excluding a $38 million decrease related to the Southern Company Gas Dispositions, income taxes decreased $11 million. The decrease was primarily due to an increase in the flowback of excess deferred income taxes in 2019 primarily at Atlanta Gas Light as previously authorized by the Georgia PSC and the reversal of a $13 million federal income tax valuation allowance in connection with the sale of Triton in May 2019, partially offset by higher pre-tax earnings.

For year-to-date 2019, income taxes were $83 million compared to $159 million for the corresponding period in 2018. Excluding a $51 million decrease related to the Southern Company Gas Dispositions, income taxes decreased $25 million. This decrease was primarily due to an increase in the flowback of excess deferred income taxes in 2019 primarily at Atlanta Gas Light as previously authorized by the Georgia PSC and the reversal of a $13 million federal income tax valuation allowance in connection with the sale of Triton in May 2019.

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See Note (E) to the Condensed Financial Statements herein for additional information on the sale of Triton and Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information on the Atlanta Gas Light stipulation reflecting the impacts of the Tax Reform Legislation. Also see Note (G) to the Condensed Financial Statements herein for additional information.

Performance and Non-GAAP Measures

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, and loss on disposition, 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.

Adjusted operating margin should not be considered an alternative to, or a more meaningful indicator of, Southern Company Gas' operating performance than 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.

	Second Quarter 2019			Second Quarter 2018			Year-to-Date 2019			Year-to-Date 2018
	(in millions)
Operating Income	$	134		$	49		$	487		$	436
Other operating expenses(a)	364			448			799			972
Revenue taxes(b)	(22		)	(23		)	(76		)	(73		)
Adjusted Operating Margin	$	476		$	474		$	1,210		$	1,335

(a) Includes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, goodwill impairment, and loss on disposition.

(b) Nicor Gas' revenue tax expenses, which are passed through directly to customers.

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Segment Information

Adjusted operating margin, operating expenses, and net income for each segment are provided in the table below. See Note (M) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

	Second Quarter 2019									Second Quarter 2018
	Adjusted Operating Margin(a)			Operating Expenses(a)			Net Income (Loss)			Adjusted Operating Margin(a)(b)			Operating Expenses(a)(b)			Net Income (Loss)(b)
	(in millions)									(in millions)
Gas distribution operations	$	394		$	287		$	58		$	429		$	296		$	68
Gas pipeline investments	8			3			25			8			3			21
Wholesale gas services	41			10			23			(16		)	14			(21		)
Gas marketing services	27			31			(3		)	48			87			(76		)
All other	7			12			3			6			26			(23		)
Intercompany eliminations	(1		)	(1		)	—			(1		)	(1		)	—
Consolidated	$	476		$	342		$	106		$	474		$	425		$	(31	)

(a) Adjusted operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers.

(b) 2018 adjusted operating margin, operating expenses, and net income for gas distribution operations and gas marketing services include the impacts of the Southern Company Gas Dispositions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

	Year-to-Date 2019								Year-to-Date 2018
	Adjusted Operating Margin(a)			Operating Expenses(a)			Net Income (Loss)		Adjusted Operating Margin(a)(b)			Operating Expenses(a)(b)			Net Income (Loss)(b)
	(in millions)								(in millions)
Gas distribution operations	$	918		$	601		$	191	$	986		$	620		$	216
Gas pipeline investments	16			6			57		16			6			48
Wholesale gas services	125			29			70		147			36			83
Gas marketing services	142			62			58		175			181			(63		)
All other	13			29			—		15			60			(36		)
Intercompany eliminations	(4		)	(4		)	—		(4		)	(4		)	—
Consolidated	$	1,210		$	723		$	376	$	1,335		$	899		$	248

(a) Adjusted operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers.

(b) 2018 adjusted operating margin, operating expenses, and net income for gas distribution operations and gas marketing services include the impacts of the Southern Company Gas Dispositions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

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

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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.

In July 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. Also in July 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 in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

Excluding the impact of the utilities sold in 2018, the second quarter and year-to-date 2019 results of gas distribution operations are as follows:

	Second Quarter 2019									Year-to-Date 2019
Favorable (Unfavorable)	Variance to Prior Period			Impact of Utilities Sold in 2018			Variance Excluding Utilities Sold in 2018			Variance to Prior Period			Impact of Utilities Sold in 2018			Variance Excluding Utilities Sold in 2018
	(in millions)									(in millions)
Adjusted Operating Margin	$	(35	)	$	45		$	10		$	(68	)	$	133		$	65
Operating expenses	9			(35		)	(26		)	19			(75		)	(56		)
Other income (expense), net	—			—			—			(7		)	—			(7		)
Interest expense	(3		)	(6		)	(9		)	(4		)	(13		)	(17		)
Income tax expense	19			(1		)	18			35			(12		)	23
Net Income	$	(10	)	$	3		$	(7	)	$	(25	)	$	33		$	8

Second Quarter 2019 vs. Second Quarter 2018

In the second quarter 2019, net income decreased $7 million, or 10.8%, compared to the corresponding period in 2018. The $10 million increase in adjusted operating margin primarily reflects additional revenue from continued investments recovered through infrastructure replacement programs, partially offset by warmer weather in Illinois during the second quarter 2019 compared to the corresponding period in 2018. The $26 million increase in operating expenses includes increased compensation and benefit costs, higher expenses passed through directly to customers, increased expenses for pipeline compliance and maintenance activities, and additional depreciation primarily due to additional assets placed in service. The $9 million increase in interest expense results from the issuance of first mortgage bonds at Nicor Gas in the prior year. Income tax expense decreased $18 million primarily due to an increase in the flowback of excess deferred income taxes at Atlanta Gas Light in 2019 and lower pre-tax earnings.

Year-to-Date 2019 vs. Year-to-Date 2018

For year-to-date 2019, net income increased $8 million, or 4.4%, compared to the corresponding period in 2018. The $65 million increase in adjusted operating margin primarily reflects additional revenue from continued investments recovered through infrastructure replacement programs and base rate increases, the effect of revenues deferred in 2018 as a result of the Tax Reform Legislation, and colder weather in Illinois during the first quarter 2019 compared to the corresponding period in 2018. The $56 million increase in operating expenses includes increased compensation and benefit costs, higher expenses passed through directly to customers, increased expenses for pipeline compliance and maintenance activities, and additional depreciation primarily due to additional assets placed in service. The decrease in other income (expense), net is primarily due to a contractor litigation settlement in the first quarter 2018. The $17 million increase in interest expense is primarily from the issuance of first mortgage bonds at Nicor Gas in the prior year. The $23 million decrease in income tax expense is primarily due to

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an increase in the flowback of excess deferred income taxes in 2019, primarily at Atlanta Gas Light and lower pre-tax earnings.

See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings – Atlanta Gas Light" and " – Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light – PRP" in Item 8 of the Form 10-K for additional information on Atlanta Gas Light's stipulation reflecting the impacts of the Tax Reform Legislation and the contractor litigation settlement, respectively.

Gas Pipeline Investments

Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including SNG, Atlantic Coast Pipeline, PennEast Pipeline, and a 50% joint ownership interest in the Dalton Pipeline. See Note (E) to the Condensed Financial Statements herein and Note 7 to the financial statements in Item 8 of the Form 10-K for additional information.

In the second quarter and year-to-date 2019, net income increased $4 million, or 19.0%, and $9 million, or 18.8%, respectively, compared to the corresponding periods in 2018. These increases primarily relate to higher earnings from SNG.

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.

In the second quarter 2019, net income increased $44 million, or 209.5%, compared to the corresponding period in 2018. This increase primarily relates to a $57 million increase in adjusted operating margin and a $4 million decrease in operating expenses, partially offset by an increase of $18 million in income tax expense due to higher pre-tax earnings. For year-to-date 2019, net income decreased $13 million, or 15.7%, compared to the corresponding period in 2018. This decrease primarily relates to a $22 million decrease in adjusted operating margin, partially offset by a $7 million decrease in operating expenses.

Details of the changes in adjusted operating margin are provided in the table below. The decreases in operating expenses primarily reflect lower compensation and benefit expenses.

	Second Quarter 2019			Second Quarter 2018			Year-to-Date 2019			Year-to-Date 2018
	(in millions)
Commercial activity recognized	$	(1	)	$	17		$	37		$	189
Gain on storage derivatives	2			—			5			1
Gain (loss) on transportation and forward commodity derivatives	48			(28		)	77			(44		)
LOCOM adjustments, net of current period recoveries	(6		)	—			(8		)	(3		)
Purchase accounting adjustments to fair value inventory and contracts	(2		)	(5		)	14			4
Adjusted operating margin	$	41		$	(16	)	$	125		$	147

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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 decrease in commercial activity in the second quarter and year-to-date 2019 compared to the corresponding period in 2018 was primarily due to significant natural gas price volatility that resulted from prolonged cold weather during the first quarter 2018 coupled with low 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 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 2019 resulted in storage derivative gains. Transportation and forward commodity derivative gains in 2019 are primarily the result of narrowing transportation spreads due to supply constraints and increases in natural gas supply, which impacted forward prices at natural gas receipt and delivery points, primarily in the Northeast and Midwest regions.

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 June 30, 2019. 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 schedule
	Total storage(a)	Expected net operating gains(b)		Physical transportation transactions – expected net operating losses(c)
	(in mmBtu in millions)	(in millions)		(in millions)
2019	16	$	2	$	(15	)
2020 and thereafter	18	8		(62		)
Total at June 30, 2019	34	$	10	$	(77	)

(a) At June 30, 2019, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $2.05 per mmBtu.

(b) Represents expected operating gains 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 transportation derivative gains and (losses) that will be settled during the period and the physical transportation transactions that offset the derivative gains and losses previously recognized.

The unrealized storage and transportation derivative gains do not change the underlying economic value of wholesale gas services' storage and transportation positions and will be reversed when the related transactions occur and are recognized. For more information on wholesale gas services' energy marketing and risk management activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K.

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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 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

Second Quarter 2019 vs. Second Quarter 2018

In the second quarter 2019, net loss decreased $73 million compared to the corresponding period in 2018. This decrease primarily relates to a $56 million decrease in operating expenses and a $36 million decrease in income tax expense, partially offset by a $21 million decrease in adjusted operating margin. The decrease in net loss is primarily attributable to the 2018 disposition of Pivotal Home Solutions.

Year-to-Date 2019 vs. Year-to-Date 2018

For year-to-date 2019, net income increased $121 million compared to the corresponding period in 2018. This increase primarily relates to a $119 million decrease in operating expenses and a $33 million decrease in income tax expense, partially offset by a $33 million decrease in adjusted operating margin.

Excluding a $43 million decrease attributable to the 2018 disposition of Pivotal Home Solutions, adjusted operating margin increased $10 million, which primarily reflects favorable margins and recovery of prior period hedge losses. Excluding a $118 million decrease attributable to the 2018 disposition of Pivotal Home Solutions that includes the related goodwill impairment charge, operating expense decreased $1 million.

All Other

All other includes Southern Company Gas' storage and fuels operations and its investment in Triton through completion of its sale on May 29, 2019, 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.

Second Quarter 2019 vs. Second Quarter 2018

In the second quarter 2019, net income increased $26 million compared to the corresponding period in 2018. This increase primarily reflects a $14 million decrease in operating expenses and a $13 million decrease in income taxes. The decrease in operating expenses was primarily due to disposition-related costs incurred during 2018. The decrease in income taxes reflects lower taxes due to the reversal of a federal income tax valuation allowance in connection with the sale of Triton.

Year-to-Date 2019 vs. Year-to-Date 2018

For year-to-date 2019, net income increased $36 million compared to the corresponding period in 2018. This increase primarily reflects a $31 million decrease in operating expenses and a $10 million decrease in income taxes, partially offset by a $2 million decrease in adjusted operating margin. The decrease in operating expenses primarily reflects a one-time adjustment in the first quarter 2018 for the adoption of a new paid time off policy, disposition-related costs incurred during 2018, and a decrease in depreciation and amortization. The decrease in income taxes reflects lower taxes due to the reversal of a federal income tax valuation allowance in connection with the sale of Triton.

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Segment Reconciliations

Reconciliations of operating income to adjusted operating margin for the second quarter and year-to-date 2019 and 2018 are reflected in the following tables. See Note (M) to the Condensed Financial Statements herein for additional information.

	Second Quarter 2019
	Gas Distribution Operations			Gas Pipeline Investments		Wholesale Gas Services		Gas Marketing Services			All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	107		$	5	$	31	$	(4	)	$	(5	)	$	—		$	134
Other operating expenses(a)	309			3		10		31			12			(1		)	364
Revenue tax expense(b)	(22		)	—		—		—			—			—			(22		)
Adjusted Operating Margin	$	394		$	8	$	41	$	27		$	7		$	(1	)	$	476

	Second Quarter 2018
	Gas Distribution Operations			Gas Pipeline Investments		Wholesale Gas Services			Gas Marketing Services			All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	133		$	5	$	(30	)	$	(39	)	$	(20	)	$	—		$	49
Other operating expenses(a)	319			3		14			87			26			(1		)	448
Revenue tax expense(b)	(23		)	—		—			—			—			—			(23		)
Adjusted Operating Margin	$	429		$	8	$	(16	)	$	48		$	6		$	(1	)	$	474

	Year-to-Date 2019
	Gas Distribution Operations			Gas Pipeline Investments		Wholesale Gas Services		Gas Marketing Services		All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	317		$	10	$	96	$	80	$	(16	)	$	—		$	487
Other operating expenses(a)	677			6		29		62		29			(4		)	799
Revenue tax expense(b)	(76		)	—		—		—		—			—			(76		)
Adjusted Operating Margin	$	918		$	16	$	125	$	142	$	13		$	(4	)	$	1,210

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	Year-to-Date 2018
	Gas Distribution Operations			Gas Pipeline Investments		Wholesale Gas Services		Gas Marketing Services			All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	366		$	10	$	111	$	(6	)	$	(45	)	$	—		$	436
Other operating expenses(a)	693			6		36		181			60			(4		)	972
Revenue tax expense(b)	(73		)	—		—		—			—			—			(73		)
Adjusted Operating Margin	$	986		$	16	$	147	$	175		$	15		$	(4	)	$	1,335

(a) Includes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, goodwill impairment, and loss on disposition.

(b) Nicor Gas' revenue tax expenses, which are passed through directly to customers.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Company Gas' future earnings potential. The Southern Company Gas Dispositions are expected to materially decrease future earnings and cash flows to Southern Company Gas. In the second quarter and year-to-date 2018, net income attributable to these dispositions, excluding the related goodwill impairment and loss on disposition, was $38 million and $3 million, respectively. 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 MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Company Gas in Item 7 of the Form 10-K 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, including the new housing market, 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.

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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, the second quarter and year-to-date 2019 results are not necessarily indicative of the results to be expected for any other period.

Environmental Matters

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 fully 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. See Note (C) to the Condensed Financial Statements under "Environmental Remediation" herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company Gas in Item 7 and Note 3 to the financial statements under "Environmental Remediation" in Item 8 of the Form 10-K for additional information.

Regulatory Matters

See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information regarding Southern Company Gas' regulatory matters.

Rate Proceedings

Nicor Gas

In November 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% to 54% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation.

On April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with the Staff of the Illinois Commission, including a ROE of 9.86% and an equity ratio of 54%. Also on April 16, 2019, Nicor Gas filed its rebuttal testimony with the Illinois Commission incorporating the stipulation agreement and addressing the remaining items outstanding with the other two intervenors. As a result of the stipulation agreement and rebuttal testimony, the revised requested annual revenue increase is $180 million.

The Illinois Commission is expected to rule on the requested increase by early October 2019, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.

Atlanta Gas Light

On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia PSC requesting a $96 million increase in annual base rate revenues. The requested increase is based on a forward-looking test year for the 12-month period ending July 31, 2020, a ROE of 10.75% with an earnings band based on a ROE between 10.55% and 10.95%, and a continued equity ratio of 55%. The filing also requests the continuation of the Georgia rate adjustment mechanism, as previously authorized. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter on December 19, 2019 with the new rates becoming effective January 1, 2020. The ultimate outcome of this matter cannot be determined at this time.

Virginia Natural Gas

In December 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 Tax Reform Legislation. This approval also required Virginia Natural Gas to issue customer refunds, via bill credits, for

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$14 million related to 2018 tax benefits deferred as a regulatory liability, current, on the balance sheet at December 31, 2018. These customer refunds were completed in the first quarter 2019.

Regulatory Infrastructure Programs

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 for timely recovery of capital expenditures for specific infrastructure replacement programs. Infrastructure expenditures incurred under these programs in the first six months of 2019 were as follows:

Utility	Program	Year-to-Date 2019
		(in millions)
Nicor Gas	Investing in Illinois	$	107
Virginia Natural Gas	Steps to Advance Virginia's Energy (SAVE)	21
Total		$	128

On April 8, 2019, Virginia Natural Gas filed an application with the Virginia Commission to amend and extend its SAVE program. The proposal would allow Virginia Natural Gas to continue replacing aging pipeline infrastructure and increase its authorized investment under the currently-approved plan. Virginia Natural Gas seeks to amend its currently-approved plan by increasing the authorized investment in 2019 from $35 million to $40 million and to extend the plan for an additional five years until 2024, with proposed annual investments of $50 million in 2020, $60 million in 2021, and $70 million in each year from 2022 through 2024, for a maximum total investment over the six-year term (2019 through 2024) of $370 million. The proposed investment schedule would also allow for variances of up to $6 million in 2019, $8 million in 2020, $9 million in 2021, and $10 million in each year from 2022 through 2024, with a total potential net variance of up to $10 million allowed for the program. The Virginia Commission is expected to rule on the request in the fourth quarter 2019. The ultimate outcome of this matter cannot be determined at this time.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Infrastructure Replacement Programs and Capital Projects" of Southern Company Gas in Item 7 and Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" in Item 8 of the Form 10-K for additional information.

Affiliate Asset Management Agreements

On March 15, 2019, the Virginia Commission approved an extension of Virginia Natural Gas' asset management agreement with Sequent to March 31, 2021. Southern Company Gas does not expect this new agreement to have a material impact on its financial statements.

FERC Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Company Gas in Item 7 of the Form 10-K and Notes 7 and 9 to the financial statements under "Southern Company Gas – Equity Method Investments" and "Guarantees," respectively, in Item 8 of the Form 10-K for additional information regarding Southern Company Gas' gas pipeline construction projects.

Other Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" and "FERC Matters" of Southern Company Gas in Item 7 of the Form 10-K for additional information.

Southern Company Gas is involved in various other matters that could affect future earnings, including matters being litigated, as well as other regulatory matters and matters that could result in asset impairments. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the ordinary course of business. The

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ultimate outcome of such pending or potential litigation, regulatory matters, or potential asset impairments cannot be determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) to the Condensed Financial Statements herein, 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 (B) and (C) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

See Note 3 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Southern Company Gas" for information on a natural gas storage facility consisting of two salt dome caverns in Louisiana. The future performance of this facility, as well as Southern Company Gas' two other natural gas storage facilities located in California and Texas, could be impacted by ongoing changes in the U.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and may imply an impact on future rates and/or asset values. Southern Company Gas is evaluating these recent market transactions for impacts on its plans to return one of the salt dome caverns in Louisiana back to service in 2021. Sustained diminished natural gas storage values could trigger impairment of one or all of these natural gas storage facilities, which have a combined net book value of $438 million at June 30, 2019. The ultimate outcome of these matters cannot be determined at this time, but could have a material impact on Southern Company Gas' financial statements.

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 Item 8 of the Form 10-K. 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company Gas in Item 7 of the Form 10-K for a complete discussion of Southern Company Gas' critical accounting policies and estimates.

Recently Issued Accounting Standards

See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company Gas' recently adopted accounting standards.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company Gas in Item 7 of the Form 10-K for additional information. Southern Company Gas' financial condition remained stable at June 30, 2019. Southern Company Gas intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" 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 June 30, 2019, the amount of subsidiary retained earnings restricted to dividend totaled $888 million. This restriction did not impact Southern Company Gas' ability to meet its cash obligations.

Net cash provided from operating activities totaled $931 million for the first six months of 2019, a decrease of $387 million from the corresponding period in 2018. The decrease was primarily due to the impacts of the Southern Company Gas Dispositions and the timing of vendor payments, partially offset by the timing of collection of customer receivables. Net cash used for investing activities totaled $586 million for the first six months of 2019

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primarily due to gross property additions related to utility capital expenditures and infrastructure investments recovered through replacement programs at gas distribution operations and capital contributed to equity method pipeline investments, partially offset by proceeds from the sale of Triton. Net cash used for financing activities totaled $355 million for the first six months of 2019 primarily due to repayments of commercial paper borrowings and a common stock dividend payment to Southern Company. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2019 include a decrease of $256 million in natural gas for sale due to the use of stored natural gas and a $158 million decrease in notes payable primarily related to net repayments of commercial paper borrowings. Other significant balance sheet changes include decreases of $440 million and $463 million in energy marketing receivables and payables, respectively, due to lower natural gas prices and volumes of natural gas sold, and an increase of $429 million in total property, plant, and equipment primarily due to utility capital expenditures and infrastructure investments recovered through replacement programs. Balance sheet changes for the first six months of 2019 also include recording $95 million in operating lease right-of use assets and $94 million in operating lease obligations related to the adoption of ASU No. 2016-02, Leases (Topic 842) (ASC 842). See Note (L) to the Condensed Financial Statements herein for additional information on the adoption of ASC 842.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company Gas in Item 7 of the Form 10-K for a description of Southern Company Gas' capital requirements and contractual obligations. Subsequent to June 30, 2019, Nicor Gas repaid at maturity $50 million aggregate principal amount of first mortgage bonds due July 30, 2019. An additional $300 million will be required through June 30, 2020 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

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 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. See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for information regarding additional factors that may impact infrastructure investment expenditures.

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. The issuance of securities by Nicor Gas is generally subject to the approval of the Illinois Commission. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company Gas in Item 7 of the Form 10-K for additional information.

Subsequent to June 30, 2019, Southern Company Gas received a $400 million capital contribution from Southern Company.

Southern Company Gas' current liabilities exceeded current assets by $682 million primarily as a result of $492 million in notes payable and $351 million in 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.

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At June 30, 2019, Southern Company Gas had $56 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2019 were as follows:

Company	Expires 2024		Unused
	(in millions)
Southern Company Gas Capital(a)	$	1,250	$	1,245
Nicor Gas	500		500
Total(b)	$	1,750	$	1,745

(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 consolidated financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

In May 2019, Southern Company Gas Capital, along with Nicor Gas, amended and restated its multi-year credit arrangement to extend the maturity date to 2024 and decrease the aggregate borrowing capacity from $1.9 billion to $1.75 billion.

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 June 30, 2019, 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.

Details of short-term borrowings were as follows:

	Short-Term Debt at June 30, 2019				Short-Term Debt During the Period(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
Commercial paper:	(in millions)				(in millions)				(in millions)
Southern Company Gas Capital	$	372	2.6	%	$	297	2.7	%	$	436
Nicor Gas	120		2.6		27		2.6		120
Total	$	492	2.6	%	$	324	2.7	%

(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2019.

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.

157

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 natural gas purchases and sales, fuel transportation and storage, and energy price risk management. The maximum potential collateral requirement under these contracts at June 30, 2019 was approximately $13 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.

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" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Southern Company Gas" herein for information on additional requests for increased equity ratios included in rate case proceedings for Nicor Gas and Atlanta Gas Light expected to conclude later in 2019.

Financing Activities

The long-term debt on Southern Company Gas' balance sheets includes both principal and non-principal components. As of June 30, 2019, the non-principal components totaled $432 million, which consisted of the unamortized portions of the fair value adjustment recorded in purchase accounting, debt premiums, debt discounts, and debt issuance costs.

Southern Company Gas did not issue or redeem any securities during the six months ended June 30, 2019.

Subsequent to June 30, 2019, Nicor Gas repaid at maturity $50 million aggregate principal amount of 4.7% first mortgage bonds due July 30, 2019.

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.

Market Price Risk

Other than the items discussed below, there were no material changes to Southern Company Gas' disclosures about market price risk during the second quarter 2019. For an in-depth discussion of Southern Company Gas' market price risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K. Also see Notes (I) and (J) to the Condensed Financial Statements herein for information relating to derivative instruments.

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. Certain natural gas distribution utilities of Southern Company Gas may 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

158

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Gas has a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower 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 over-the-counter energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Some of these economic hedge activities may not qualify, or are not designated, for hedge accounting treatment. For the periods presented below, the changes in net fair value of Southern Company Gas' derivative contracts were as follows:

	Second Quarter 2019			Second Quarter 2018			Year-to-Date 2019			Year-to-Date 2018
	(in millions)
Contracts outstanding at beginning of period, assets (liabilities), net	$	(128	)	$	(70	)	$	(167	)	$	(106	)
Contracts realized or otherwise settled	5			2			—			51
Current period changes(a)	33			(22		)	77			(35		)
Contracts outstanding at the end of period, assets (liabilities), net	$	(90	)	$	(90	)	$	(90	)	$	(90	)
Netting of cash collateral	178			183			178			183
Cash collateral and net fair value of contracts outstanding at end of period(b)	$	88		$	93		$	88		$	93

(a) Current period changes also include the fair value of new contracts entered into during the period, if any.

(b) Net fair value of derivative contracts outstanding excludes premium and the intrinsic value associated with weather derivatives of $0 million and $3 million at June 30, 2019 and 2018, respectively.

The maturities of Southern Company Gas' energy-related derivative contracts at June 30, 2019 were as follows:

				Fair Value Measurements
				June 30, 2019
	Total Fair Value			Maturity
				Year 1			Years 2 & 3			Years 4 and thereafter
	(in millions)
Level 1(a)	$	(135	)	$	(46	)	$	(62	)	$	(27	)
Level 2(b)	55			27			25			3
Level 3(c)	(10		)	1			—			(11		)
Fair value of contracts outstanding at end of period(d)	$	(90	)	$	(18	)	$	(37	)	$	(35	)

(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) Valued using a combination of observable and unobservable inputs.

(d) Excludes cash collateral of $178 million as well as premium and associated intrinsic value associated with weather derivatives of $0 million at June 30, 2019.

159

NOTES TO THE CONDENSED FINANCIAL STATEMENTS

FOR

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

(UNAUDITED)

INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS

Note		Page Number
A	Introduction	161
B	Regulatory Matters	166
C	Contingencies	174
D	Revenue from Contracts with Customers	179
E	Consolidated Entities and Equity Method Investments	187
F	Financing	188
G	Income Taxes	193
H	Retirement Benefits	194
I	Fair Value Measurements	199
J	Derivatives	204
K	Acquisitions and Dispositions	216
L	Leases	219
M	Segment and Related Information	226

INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT

The following unaudited notes to the condensed financial statements are a combined presentation. The list below indicates the registrants to which each footnote applies.

Registrant	Applicable Notes
Southern Company	A, B, C, D, E, F, G, H, I, J, K, L, M
Alabama Power	A, B, C, D, F, G, H, I, J, L
Georgia Power	A, B, C, D, F, G, H, I, J, L
Mississippi Power	A, B, C, D, F, G, H, I, J, L
Southern Power	A, C, D, E, F, G, H, I, J, K, L
Southern Company Gas	A, B, C, D, E, F, G, H, I, J, K, L, M

160

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:

(UNAUDITED)

(A) INTRODUCTION

The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2018 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended June 30, 2019 and 2018. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.

Recently Adopted Accounting Standards

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. The registrants adopted the new standard effective January 1, 2019. See Note (L) for additional information and related disclosures.

161

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Goodwill and Other Intangible Assets

Goodwill at June 30, 2019 and December 31, 2018 was as follows:

	At June 30, 2019		At December 31, 2018
	(in millions)
Southern Company	$	5,282	$	5,315
Southern Company Gas:
Gas distribution operations	$	4,034	$	4,034
Gas marketing services	981		981
Southern Company Gas total	$	5,015	$	5,015

Goodwill is not amortized but is subject to an annual impairment test during the fourth quarter of each year or more frequently if impairment indicators arise. A goodwill impairment charge of $32 million was recorded in the second quarter 2019 in contemplation of the July 22, 2019 sale of one of PowerSecure's business units. See Note (K) under "Southern Company" for additional information.

162

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Other intangible assets were as follows:

	At June 30, 2019							At December 31, 2018
	Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net
	(in millions)							(in millions)
Southern Company
Other intangible assets subject to amortization:
Customer relationships	$	211	$	(105	)	$	106	$	223	$	(94	)	$	129
Trade names	70		(23		)	47		70		(21		)	49
Storage and transportation contracts	64		(58		)	6		64		(54		)	10
PPA fair value adjustments	371		(60		)	311		405		(61		)	344
Other	12		(7		)	5		11		(5		)	6
Total other intangible assets subject to amortization	$	728	$	(253	)	$	475	$	773	$	(235	)	$	538
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—			75		75		—			75
Total other intangible assets	$	803	$	(253	)	$	550	$	848	$	(235	)	$	613
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	371	$	(60	)	$	311	$	405	$	(61	)	$	344
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156	$	(95	)	$	61	$	156	$	(84	)	$	72
Trade names	26		(8		)	18		26		(7		)	19
Wholesale gas services
Storage and transportation contracts	64		(58		)	6		64		(54		)	10
Total other intangible assets subject to amortization	$	246	$	(161	)	$	85	$	246	$	(145	)	$	101

163

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Six Months Ended
	June 30, 2019
	(in millions)
Southern Company	$	15	$	32
Southern Power(a)	$	4	$	10
Southern Company Gas
Gas marketing services(b)	$	6	$	12
Wholesale gas services(a)	2		4
Southern Company Gas total	$	8	$	16

(a) Recorded as a reduction to operating revenues.

(b) Included in depreciation and amortization.

Restricted Cash

At December 31, 2018, Georgia Power had restricted cash related to the redemption of pollution control revenue bonds, which were redeemed in January 2019. See Note (F) under "Financing Activities" for additional information. At both June 30, 2019 and December 31, 2018, Southern Company Gas had restricted cash held as collateral for worker's compensation, life insurance, and long-term disability insurance.

The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the registrants that had restricted cash at June 30, 2019 and/or December 31, 2018:

	Southern Company			Southern Company Gas
	(in millions)
At June 30, 2019
Cash and cash equivalents	$	1,383		$	56
Restricted cash:
Other accounts and notes receivable	4			4
Total cash, cash equivalents, and restricted cash	$	1,386	(*)	$	60

(*) Total does not add due to rounding.

	Southern Company		Georgia Power		Southern Company Gas
	(in millions)
At December 31, 2018
Cash and cash equivalents	$	1,396	$	4	$	64
Cash and cash equivalents held for sale	9		—		—
Restricted cash:
Restricted cash	—		108		—
Other accounts and notes receivable	114		—		6
Total cash, cash equivalents, and restricted cash	$	1,519	$	112	$	70

164

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Natural Gas for Sale

Southern Company Gas, with the exception of Nicor Gas, carries natural gas inventory on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Southern Company Gas recorded adjustments of $7 million and $10 million for the three and six months ended June 30, 2019, respectively, and no material adjustments for the comparable periods in 2018.

Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. Nicor Gas had no inventory decrement at June 30, 2019.

Asset Retirement Obligations

See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding AROs.

Details of the AROs included in the condensed balance sheets of Southern Company, Alabama Power, and Mississippi Power at June 30, 2019 are shown in the following table. There were no material changes in the AROs of Georgia Power or Southern Power during the first six months of 2019.

	Southern Company			Alabama Power			Mississippi Power
	(in millions)
Balance at December 31, 2018	$	9,394		$	3,210		$	160
Liabilities incurred	6			—			—
Liabilities settled	(142		)	(43		)	(17		)
Accretion	197			70			2
Cash flow revisions	452			308			59
Balance at June 30, 2019	$	9,907		$	3,545		$	204

In June 2019, Alabama Power recorded an increase of approximately $308 million to its AROs primarily related to the CCR Rule and the related state rule based on management's completion of closure designs during the second quarter 2019 for all but two of its ash pond facilities. Mississippi Power also recorded an increase of approximately $58 million to its AROs related to the CCR Rule, primarily associated with the ash pond facility at Plant Greene County, which is jointly owned with Alabama Power. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and increases in the estimated ash volumes. The cost estimate for the remaining Alabama Power ash pond facilities will be updated within the next 12 months and the change could be material.

As further analysis is performed and additional details are developed with respect to ash pond closures, the traditional electric operating companies expect to periodically update their ARO cost estimates. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, Southern Company's and the traditional electric operating companies' results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of these matters cannot be determined at this time.

165

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(B) REGULATORY MATTERS

See Note 2 to the financial statements in Item 8 of the Form 10-K for additional information relating to regulatory matters.

The recovery balances for certain of Alabama Power's, Georgia Power's, and Mississippi Power's regulatory clauses at June 30, 2019 and December 31, 2018 were as follows:

Regulatory Clause	Balance Sheet Line Item	June 30, 2019		December 31, 2018
		(in millions)
Alabama Power
Rate CNP Compliance	Deferred under recovered regulatory clause revenues	$	—	$	42
	Customer accounts receivable	10		—
Rate CNP PPA	Deferred under recovered regulatory clause revenues	25		25
Retail Energy Cost Recovery(*)	Deferred under recovered regulatory clause revenues	—		109
	Customer accounts receivable	8		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	19		20
Georgia Power
Fuel Cost Recovery	Receivables – under recovered fuel clause revenues	$	69	$	115
Mississippi Power
Fuel Cost Recovery	Over recovered regulatory clause liabilities	$	9	$	8

(*) In accordance with an accounting order issued on February 5, 2019 by the Alabama PSC, Alabama Power utilized $75 million of the 2018 Rate RSE refund liability to reduce the Rate ECR under recovered balance. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information.

Alabama Power

Environmental Accounting Order

On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" and Note 6 in Item 8 of the Form 10-K for additional information.

Georgia Power

Rate Plans

On June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.

166

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:

Tariff	2020		2021		2022
	(in millions)
Traditional base:
Levelized	$	209	$	—	$	—
CCR AROs	158		140		227
Environmental Compliance Cost Recovery	165		—		—
Demand-Side Management	14		2		1
Municipal Franchise Fee	17		3		5
Total(*)	$	563	$	145	$	234

(*) Totals may not add due to rounding.

Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:

• Continuation of an allowed retail ROE range of 10.00% to 12.00%.

• Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the remaining one-third are retained by Georgia Power.

• Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.

Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be determined at this time.

Integrated Resource Plan

In 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan, including 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 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. In accordance with the Georgia PSC's order, costs incurred of approximately $50 million have been recorded as a regulatory asset.

On July 16, 2019, the Georgia PSC voted to approve Georgia Power's triennial Integrated Resource Plan (2019 IRP) as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.

In the 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively, at June 30, 2019), as well as any unusable materials and supplies inventory balances, upon retirement to a regulatory asset. Recovery of each unit's net book value will continue through December 31, 2019 as provided in the 2013 ARP.

For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case as follows: (i) the net book values of Plant Mitchell Unit 3 (approximately $8 million at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book

167

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The ultimate outcome of these matters cannot be determined at this time.

Also in the 2019 IRP, the Georgia PSC rejected 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. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future Integrated Resource Plan. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Georgia Power's or Southern Company's financial statements.

Additionally, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $135 million at June 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.

The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.

See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.

Nuclear Construction

See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, the joint ownership agreements and related funding agreement, VCM reports, and the NCCR tariff.

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. In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work,

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certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

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 June 30, 2019(b)	(5.2		)
Remaining estimate to complete(a)	$	3.2

(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 $2.0 billion had been incurred through June 30, 2019.

In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the estimated total project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.

As construction continues and testing and system turnover activities increase, challenges with management of contractors, subcontractors, and vendors; supervision of craft labor and related craft labor productivity, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures, or components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.

The April 2019 cost and schedule validation process established target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the approved in-service dates. To support that strategy, monthly production and activity target values will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers (particularly electrical and pipefitter craft labor), as well as additional supervision and other field support resources, must be retained and deployed.

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 submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, 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.

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The ultimate outcome of these matters cannot be determined at this time. However, any extension of the regulatory-approved 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

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

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 in conjunction with the nineteenth VCM report, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 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 at pre-established prices, 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 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.

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 June 30, 2019, Georgia Power had recovered approximately $2.0 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. In December 2018, the Georgia PSC approved Georgia Power's request to increase the NCCR tariff by $88 million annually, effective January 1, 2019.

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Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the 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 in 2018 and are estimated to have negative earnings impacts of approximately $70 million in 2019 and an aggregate of approximately $630 million from 2020 to 2022.

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.

In February 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. In March 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. In December 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 August 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

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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).

On April 30, 2019, as requested by the staff of the Georgia PSC, Georgia Power reported the results of the cost and schedule validation process to the Georgia PSC. On August 30, 2019, Georgia Power will file its twentieth VCM report concurrently with its twenty-first VCM report with the Georgia PSC, which will reflect the capital cost forecast discussed previously and request approval of $1.2 billion of construction capital costs incurred from June 30, 2018 through June 30, 2019. In addition, on June 20, 2019, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a settlement agreement related to the administrative claim filed in the Westinghouse bankruptcy proceedings. Accordingly, in the twentieth/twenty-first VCM report, Georgia Power will also request approval of the $51.6 million of associated expenditures previously deferred by the Georgia PSC.

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

DOE Financing

At June 30, 2019, Georgia Power had borrowed $3.46 billion related to Plant Vogtle Units 3 and 4 costs as provided through the Amended and Restated Loan Guarantee Agreement and related multi-advance credit facilities among Georgia Power, the DOE, and the FFB, which provide for borrowings of up to approximately $5.130 billion, subject to the satisfaction of certain conditions. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

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

Mississippi Power

Municipal and Rural Association Tariff

On May 7, 2019, the FERC accepted Mississippi Power's March 28, 2019 request for a decrease in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with its wholesale customers resolving all matters related to the Kemper County energy facility similar to the retail rate settlement agreement approved by the Mississippi PSC in February 2018 and reflecting the impacts of the Tax Reform Legislation. Pursuant to the MRA settlement agreement, base rates decreased $3.7 million annually, effective January 1, 2019.

Environmental Compliance Overview Plan

On July 9, 2019, Mississippi Power filed a request with the Mississippi PSC for a Certificate of Public Convenience and Necessity to complete certain environmental compliance projects, primarily associated with the Plant Daniel coal units co-owned 50% with Gulf Power. The total estimated cost is approximately $125 million, with Mississippi Power's share of approximately $66 million being proposed for recovery through its ECO Plan. Approximately $17 million of Mississippi Power's share is associated with ash pond closure and is reflected in Mississippi Power's ARO liabilities. See Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information on Mississippi Power's ECO Plan. See Note (A) under "Asset Retirement Obligations" for additional information on AROs and Note (C) under "Other Matters – Mississippi Power" herein for additional information on Gulf Power's ownership in Plant Daniel.

Kemper County Energy Facility

As the mining permit holder, Liberty Fuels Company, LLC 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,

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with monitoring expected to continue through 2027. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

During the second quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $6 million ($5 million after tax), respectively, 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 dismantlement costs, net of salvage), 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 at $7 million for the remainder of 2019 and $2 million to $6 million annually in 2020 through 2023.

In addition, Mississippi Power constructed the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery and 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 and could have a material impact on Southern Company's financial statements.

In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of 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. In connection with the DOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the Kemper County energy facility. The ultimate outcome of these matters cannot be determined at this time; however, they could have a material impact on Mississippi Power's and Southern Company's financial statements.

Southern Company Gas

Rate Proceedings

Nicor Gas

In November 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% to 54% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation.

On April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with the Staff of the Illinois Commission, including a ROE of 9.86% and an equity ratio of 54%. Also on April 16, 2019, Nicor Gas filed its rebuttal testimony with the Illinois Commission incorporating the stipulation agreement and addressing the remaining items outstanding with the other two intervenors. As a result of the stipulation agreement and rebuttal testimony, the revised requested annual revenue increase is $180 million.

The Illinois Commission is expected to rule on the requested increase by early October 2019, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.

Atlanta Gas Light

On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia PSC requesting a $96 million increase in annual base rate revenues. The requested increase is based on a forward-looking test year for the 12-month period ending July 31, 2020, a ROE of 10.75% with an earnings band based on a ROE between 10.55% and 10.95%, and a continued equity ratio of 55%. The filing also requests the continuation of the Georgia rate adjustment mechanism, as previously authorized. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter on December 19, 2019 with the new rates becoming effective January 1, 2020. The ultimate outcome of this matter cannot be determined at this time.

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Virginia Natural Gas

In December 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 Tax Reform Legislation. This approval also required Virginia Natural Gas to issue customer refunds, via bill credits, for $14 million related to 2018 tax benefits deferred as a regulatory liability, current, on the balance sheet at December 31, 2018. These customer refunds were completed in the first quarter 2019.

Regulatory Infrastructure Programs

Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and help ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs. 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 for timely recovery of capital expenditures for specific infrastructure replacement programs.

Virginia Natural Gas

On April 8, 2019, Virginia Natural Gas filed an application with the Virginia Commission to amend and extend its Steps to Advance Virginia's Energy program. The proposal would allow Virginia Natural Gas to continue replacing aging pipeline infrastructure and increase its authorized investment under the currently-approved plan. Virginia Natural Gas seeks to amend its currently-approved plan by increasing the authorized investment in 2019 from $35 million to $40 million and to extend the plan for an additional five years until 2024, with proposed annual investments of $50 million in 2020, $60 million in 2021, and $70 million in each year from 2022 through 2024, for a maximum total investment over the six-year term (2019 through 2024) of $370 million. The proposed investment schedule would also allow for variances of up to $6 million in 2019, $8 million in 2020, $9 million in 2021, and $10 million in each year from 2022 through 2024, with a total potential net variance of up to $10 million allowed for the program. The Virginia Commission is expected to rule on the request in the fourth quarter 2019. The ultimate outcome of this matter cannot be determined at this time.

Affiliate Asset Management Agreements

On March 15, 2019, the Virginia Commission approved an extension of Virginia Natural Gas' asset management agreement with Sequent to March 31, 2021.

FERC Matters

See Note 2 to the financial statements under "FERC Matters – Open Access Transmission Tariff" in Item 8 of the Form 10-K for additional information.

On June 28, 2019, the FERC approved a settlement agreement between Alabama Municipal Electric Authority and Cooperative Energy and SCS and the traditional electric operating companies agreeing to an OATT rate reduction based on a 10.6% ROE, with a retroactive effective date of May 10, 2018, and a five-year moratorium on these parties seeking changes to the OATT formula rate. The terms of the OATT settlement agreement will not have a material impact on the financial statements of any of the traditional electric operating companies or Southern Company.

(C) CONTINGENCIES

See Note 3 to the financial statements in Item 8 of the Form 10-K for information relating to various lawsuits and other contingencies.

General Litigation Matters

Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, 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

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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 against each registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.

Southern Company

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 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 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. Also in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition. In March 2018, the court 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. In April 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. In August 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal.

In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. 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. In April 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, 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. In May 2018, the court entered an

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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.

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

Georgia Power

In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. In 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court. Georgia Power filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted in 2017. In June 2018, the Georgia Supreme Court affirmed the judgment of the Georgia Court of Appeals and remanded the case to the trial court for further proceedings. Following a motion by Georgia Power, on February 13, 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling to address certain terms the court previously held were ambiguous as used in the Georgia PSC's orders. The order entered by the Superior Court of Fulton County also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Georgia Power also filed a notice of appeal with the Georgia Court of Appeals regarding the Superior Court of Fulton County's February 2019 order. Georgia Power believes the plaintiffs' claims have no merit. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether conditional class certification will be upheld and the ultimate composition of any class and whether any losses would be subject to recovery from any municipalities. The ultimate outcome of this matter cannot be determined at this time.

Mississippi Power

In May 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 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, which were denied by the arbitration panel on May 10, 2019. Southern Company and Mississippi Power believe this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity. The ultimate outcome of this matter cannot be determined at this time.

In November 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 by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint on March 14, 2019. The amended complaint included four additional plaintiffs and additional claims for

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gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint. Mississippi Power believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. The ultimate outcome of this matter cannot be determined at this time.

Southern Power

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 withheld payment of approximately $26 million to the construction contractor, which placed a lien on the Roserock facility for the same amount. In 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas against XL Insurance America, Inc. and North American Elite Insurance Company seeking recovery from an insurance policy for damages resulting from the hail event and McCarthy's installation practices. In June 2018, the court 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. Separate lawsuits were filed between Roserock and McCarthy, as well as other parties, and that litigation was consolidated in the U.S. District Court for the Western District of Texas. On April 18, 2019, Roserock and the parties to the state and federal lawsuits executed a settlement agreement and mutual release that resolved both lawsuits. Following execution of the agreement, the lawsuits were dismissed, Southern Power paid McCarthy the amounts previously withheld, and McCarthy released its lien. As part of the settlement, Roserock received funds that covered all related legal costs, damages, and the replacement costs of certain solar panels. Funds received by Southern Power in excess of the initial replacement costs were recognized as a gain and included in other income (expense), net in 2019. A portion of the pre-tax gain was allocated to noncontrolling interests and Southern Power recognized a $12 million after-tax gain.

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 in Illinois and Georgia have each 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.

Georgia Power's environmental remediation liability was $18 million and $23 million as of June 30, 2019 and December 31, 2018, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.

Southern Company Gas' environmental remediation liability was $283 million and $294 million as of June 30, 2019 and December 31, 2018, respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities, with the exception of one site representing $2 million of the total accrued remediation costs.

The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of Southern Company, Georgia Power, or Southern Company Gas.

177

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Nuclear Fuel Disposal Costs

In 2014, Alabama Power and Georgia Power filed lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley, Hatch, and Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. On June 12, 2019, the Court of Federal Claims granted Alabama Power's and Georgia Power's motion for summary judgment on damages not disputed by the U.S. government, awarding those undisputed damages to Alabama Power and Georgia Power. However, those undisputed damages are not collectible and no amounts will be recognized in the financial statements until the court enters final judgment on the remaining damages. The final outcome of these matters cannot be determined at this time. However, Alabama Power and Georgia Power expect to credit any recoveries for the benefit of customers in accordance with direction from their respective PSC; therefore, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.

Other Matters

Alabama Power

On May 17, 2019, the Alabama Department of Environmental Management (ADEM) issued a proposed administrative order assessing a penalty of $250,000 to Alabama Power for unpermitted discharge of fluids and/or pollutants to groundwater and/or soils at Plant Gadsden. The proposed order also requires the submission to the ADEM of a plan with a schedule for implementation of a comprehensive groundwater investigation, an assessment of corrective measures, a report evaluating any deficiencies at the facility that may have led to the unpermitted discharge, and quarterly progress reports. Alabama Power is awaiting finalization of the order and the ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on Alabama Power's net income.

Mississippi Power

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 by the FERC and the Mississippi PSC, and cannot be determined at this time. See Note (K) under "Southern Company" for information regarding the sale of Gulf Power.

Southern Company Gas

The future performance of Southern Company Gas' natural gas storage facility consisting of two salt dome caverns in Louisiana, as well as Southern Company Gas' two other natural gas storage facilities located in California and Texas, could be impacted by ongoing changes in the U.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and may imply an impact on future rates and/or asset values. Southern Company Gas is evaluating these recent market transactions for impacts on its plans to return one of the salt dome caverns in Louisiana back to service in 2021. Sustained diminished natural gas storage values could trigger impairment of one or all of these natural gas storage facilities, which have a combined net book value of $438 million at June 30, 2019. The ultimate outcome of these matters cannot be determined at this time, but could have a material impact on Southern Company's and Southern Company Gas' financial statements.

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(UNAUDITED)

(D) REVENUE FROM CONTRACTS WITH CUSTOMERS

The registrants generate revenues from a variety of sources, some of which are excluded from the scope of ASC 606, Revenue from Contracts with Customers (ASC 606), such as leases, derivatives, and certain cost recovery mechanisms. See Note 1 to the financial statements under "Recently Adopted Accounting Standards – Revenue" in Item 8 of the Form 10-K for additional information on the adoption of ASC 606 for revenue from contracts with customers and Note 1 to the financial statements under "Revenues" and "Other Taxes" in Item 8 of the Form 10-K for additional information on the revenue policies of the registrants. For additional information on revenues accounted for under other accounting guidance, see Notes (J) and (L) for energy-related derivative contracts and lessor revenues, respectively, Note 1 to the financial statements under "Revenues – Southern Company Gas" in Item 8 of the Form 10-K for alternative revenue programs at the natural gas distribution utilities, and Note 2 to the financial statements in Item 8 of the Form 10-K for cost recovery mechanisms.

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(UNAUDITED)

The following tables disaggregate revenue sources for the three and six months ended June 30, 2019 and 2018:

	For the Three Months Ended June 30, 2019		For the Three Months Ended June 30, 2018			For the Six Months Ended June 30, 2019		For the Six Months Ended June 30, 2018
	(in millions)
Southern Company
Operating revenues
Retail electric revenues(a)
Residential	$	1,488	$	1,579		$	2,776	$	3,118
Commercial	1,258		1,315			2,350		2,557
Industrial	763		814			1,440		1,569
Other	31		32			57		64
Natural gas distribution revenues(b)	562		642			1,724		1,865
Alternative revenue programs(c)	1		(4		)	—		(27		)
Total retail electric and gas distribution revenues	$	4,103	$	4,378		$	8,347	$	9,146
Wholesale energy revenues(d)(e)	410		464			777		937
Wholesale capacity revenues(e)	132		152			264		302
Other natural gas revenues(f)(g)	126		68			439		476
Other revenues(h)	327		565			683		1,138
Total operating revenues	$	5,098	$	5,627		$	10,510	$	11,999

(a) Retail electric revenues include $8 million, $18 million, $16 million, and $36 million of revenues accounted for as leases for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, and a (net reduction) or net increase of $(14) million, $68 million, $(117) million and $101 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, from certain cost recovery mechanisms that are not accounted for as revenue under ASC 606.

(b) Natural gas distribution revenues include $5 million for each of the three months ended June 30, 2019 and 2018 and $8 million for each of the six months ended June 30, 2019 and 2018 of revenues not accounted for under ASC 606.

(c) Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(d) Wholesale energy revenues include $30 million, $61 million, $82 million, and $155 million of revenues accounted for as derivatives for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, primarily related to physical energy sales in the wholesale electricity market.

(e) Wholesale energy revenues include $115 million, $118 million, $182 million, and $187 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, and wholesale capacity revenues include $22 million, $31 million, $47 million, and $61 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, related to PPAs accounted for as leases.

(f) Other natural gas revenues related to Southern Company Gas' energy and risk management activities are presented net of the related costs of those activities and include gross third-party revenues of $1.2 billion, $1.3 billion, $3.1 billion, and $3.3 billion for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of which $0.8 billion, $0.7 billion, $2.0 billion, and $1.8 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (M) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.

(g) Other natural gas revenues include $10 million and $27 million for the three and six months ended June 30, 2019, respectively, of revenues not accounted for under ASC 606, including $8 million and $16 million, respectively, of revenues accounted for as leases.

(h) Other revenues include $89 million, $89 million, $180 million, and $183 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of revenues not accounted for under ASC 606, including $28 million, $33 million, $59 million, and $66 million, respectively, accounted for as leases.

180

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(UNAUDITED)

	Alabama Power		Georgia Power		Mississippi Power
	(in millions)
For the Three Months Ended June 30, 2019
Operating revenues
Retail revenues(a)(b)
Residential	$	588	$	831	$	69
Commercial	418		767		73
Industrial	366		327		70
Other	6		21		3
Total retail electric revenues	$	1,378	$	1,946	$	215
Wholesale energy revenues(c)	41		14		93
Wholesale capacity revenues	25		22		1
Other revenues(b)(d)	69		135		4
Total operating revenues	$	1,513	$	2,117	$	313
For the Three Months Ended June 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	557	$	785	$	65
Commercial	402		749		68
Industrial	372		335		76
Other	7		20		3
Total retail electric revenues	$	1,338	$	1,889	$	212
Wholesale energy revenues(c)	71		26		77
Wholesale capacity revenues	25		13		1
Other revenues(b)(d)	69		120		7
Total operating revenues	$	1,503	$	2,048	$	297

(a) Retail revenues at Alabama Power, Georgia Power, and Mississippi Power include a net increase or (net reduction) of $(11) million, $(5) million, and $2 million, respectively, for the three months ended June 30, 2019 and $78 million, $3 million, and $(1) million, respectively, for the three months ended June 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606.

(b) Retail revenues and other revenues at Georgia Power include $8 million and $11 million, respectively, for the three months ended June 30, 2019 and $18 million and $33 million, respectively, for the three months ended June 30, 2018 of revenues accounted for as leases.

(c) Wholesale energy revenues at Alabama Power, Georgia Power, and Mississippi Power include $3 million, $4 million, and $1 million, respectively, for the three months ended June 30, 2019 and $4 million, $5 million, and $1 million, respectively, for the three months ended June 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market.

(d) Other revenues at Alabama Power and Georgia Power include $31 million and $30 million, respectively, for the three months ended June 30, 2019 and $26 million and $26 million, respectively, for the three months ended June 30, 2018 of revenues not accounted for under ASC 606.

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(UNAUDITED)

	Alabama Power		Georgia Power		Mississippi Power
	(in millions)
For the Six Months Ended June 30, 2019
Operating revenues
Retail revenues(a)(b)
Residential	$	1,128	$	1,519	$	129
Commercial	772		1,440		138
Industrial	679		616		145
Other	13		39		6
Total retail electric revenues	$	2,592	$	3,614	$	418
Wholesale energy revenues(c)	135		27		170
Wholesale capacity revenues	51		40		2
Other revenues(b)(d)	143		270		10
Total operating revenues	$	2,921	$	3,951	$	600
For the Six Months Ended June 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	1,127	$	1,529	$	125
Commercial	774		1,466		130
Industrial	710		650		146
Other	13		43		5
Total retail electric revenues	$	2,624	$	3,688	$	406
Wholesale energy revenues(c)	172		66		176
Wholesale capacity revenues	49		27		5
Other revenues(b)(d)	131		227		11
Total operating revenues	$	2,976	$	4,008	$	598

(a) Retail revenues at Alabama Power, Georgia Power, and Mississippi Power include a net increase or (net reduction) of $(68) million, $(52) million, and $3 million, respectively, for the six months ended June 30, 2019 and $125 million, $12 million, and $(8) million, respectively, for the six months ended June 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606.

(b) Retail revenues and other revenues at Georgia Power include $16 million and $23 million, respectively, for the six months ended June 30, 2019 and $36 million and $66 million, respectively, for the six months ended June 30, 2018 of revenues accounted for as leases.

(c) Wholesale energy revenues at Alabama Power, Georgia Power, and Mississippi Power include $6 million, $8 million, and $1 million, respectively, for the six months ended June 30, 2019 and $9 million, $13 million, and $2 million, respectively, for the six months ended June 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market.

(d) Other revenues at Alabama Power and Georgia Power include $59 million and $61 million, respectively, for the six months ended June 30, 2019 and $52 million and $53 million, respectively, for the six months ended June 30, 2018 of revenues not accounted for under ASC 606.

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(UNAUDITED)

	For the Three Months Ended June 30, 2019		For the Three Months Ended June 30, 2018		For the Six Months Ended June 30, 2019		For the Six Months Ended  June 30, 2018
	(in millions)
Southern Power
PPA capacity revenues(a)	$	125	$	144	$	252	$	282
PPA energy revenues(a)	291		302		518		556
Non-PPA revenues(b)	91		106		177		221
Other revenues	3		3		6		5
Total operating revenues	$	510	$	555	$	953	$	1,064

(a) PPA capacity revenues include $39 million, $47 million, $80 million, and $94 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, and PPA energy revenues include $125 million, $127 million, $198 million, and $203 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, related to PPAs accounted for as leases.

(b) Non-PPA revenues include $22 million, $50 million, $67 million, and $129 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of revenues from short-term sales related to physical energy sales from uncovered capacity in the wholesale electricity market.

183

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	For the Three Months Ended June 30, 2019		For the Three Months Ended June 30, 2018			For the Six Months Ended June 30, 2019		For the Six Months Ended  June 30, 2018
	(in millions)
Southern Company Gas
Operating revenues
Natural gas distribution revenues(a)
Residential	$	229	$	273		$	830	$	933
Commercial	65		76			235		268
Transportation	213		228			469		505
Industrial	5		7			22		24
Other	50		58			168		135
Alternative revenue programs(b)	1		(4		)	—		(27		)
Total natural gas distribution revenues	$	563	$	638		$	1,724	$	1,838
Gas pipeline investments(c)	8		8			16		16
Wholesale gas services(d)	48		(15		)	114		131
Gas marketing services(e)	58		89			287		359
Other revenues	12		10			22		25
Total operating revenues	$	689	$	730		$	2,163	$	2,369

(a) Natural gas distribution revenues include $5 million for each of the three months ended June 30, 2019 and 2018 and $8 million for each of the six months ended June 30, 2019 and 2018 of revenues not accounted for under ASC 606.

(b) Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(c) Revenues from gas pipeline investments include $8 million and $16 million for the three and six months ended June 30, 2019, respectively, accounted for as leases.

(d) Wholesale gas services revenues are presented net of the related costs associated with its energy trading and risk management activities. Operating revenues, as presented, include gross third-party revenues of $1.2 billion, $1.3 billion, $3.1 billion, and $3.3 billion for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of which $0.8 billion, $0.7 billion, $2.0 billion, and $1.8 billion, respectively, relates to contracts accounted for as derivatives. See Note (M) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.

(e) Gas marketing services include $2 million for the three months ended June 30, 2019 and $11 million and $4 million for the six months ended June 30, 2019 and 2018, respectively, of revenues not accounted for under ASC 606.

184

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Contract Balances

The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers as of June 30, 2019 and December 31, 2018:

	Receivables				Contract Assets				Contract Liabilities
	June 30, 2019		December 31, 2018		June 30, 2019		December 31, 2018		June 30, 2019		December 31, 2018
	(in millions)
Southern Company(*)	$	2,343	$	2,630	$	70	$	102	$	58	$	32
Alabama Power	629		520		—		—		10		12
Georgia Power	807		721		30		58		26		7
Mississippi Power	93		100		—		—		7		—
Southern Power	119		118		—		—		1		11
Southern Company Gas	550		952		—		—		1		2

(*) Includes amounts related to held for sale investments.

As of June 30, 2019 and December 31, 2018, Georgia Power had contract assets primarily related to unregulated service agreements where payment is contingent on project completion and fixed retail customer bill programs where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over the one-year contract term. Alabama Power had contract liabilities for outstanding performance obligations primarily related to extended service agreements. Contract liabilities for Georgia Power and Southern Power relate to cash collections recognized in advance of revenue for certain unregulated service agreements and certain levelized PPAs, respectively. Mississippi Power had contract liabilities for cash collections recognized in advance of revenue for operating agreements associated with a tolling arrangement accounted for as a sales-type lease. Southern Company's unregulated distributed generation business had $32 million and $39 million of contract assets and $14 million and $11 million of contract liabilities at June 30, 2019 and December 31, 2018, respectively, remaining for outstanding performance obligations.

The following table reflects revenue from contracts with customers recognized in the three and six months ended June 30, 2019 included in the contract liability at December 31, 2018:

	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
	(in millions)
Southern Company	$	11	$	27
Southern Power	1		11

Revenues recognized in the three and six months ended June 30, 2019, which were included in contract liabilities at December 31, 2018, were immaterial for Alabama Power, Georgia Power, and Southern Company Gas.

185

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Remaining Performance Obligations

The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized when the performance obligations are satisfied during the contract term. These contracts primarily relate to PPAs whereby the traditional electric operating companies and Southern Power provide electricity and generation capacity to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain fixed price contracts. Registrants with revenues from contracts with customers related to these performance obligations remaining at June 30, 2019 expect the revenues to be recognized as follows:

	2019 (remaining)		2020		2021		2022		2023		Thereafter
	(in millions)
Southern Company	$	282	$	490	$	320	$	311	$	302	$	2,230
Alabama Power	11		23		27		23		22		140
Georgia Power	27		51		44		31		31		83
Southern Power	169		295		270		276		269		2,154

Revenues expected to be recognized for performance obligations remaining at June 30, 2019 were immaterial for Mississippi Power.

186

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(E) CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS

Southern Power

Consolidated Variable Interest Entities

See Note 7 to the financial statements in Item 8 of the Form 10-K for additional information on Southern Power's consolidated VIEs.

Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests. In 2018, Southern Power sold noncontrolling interests in SP Solar and SP Wind. Southern Power continues to consolidate each entity, as the primary beneficiary of each VIE, since it controls the most significant activities of each entity, including operating and maintaining their assets. Transfers and sales of the assets in the VIEs are subject to limited partner consent and the liabilities are non-recourse to the general credit of Southern Power. Liabilities consist of customary working capital items and do not include any long-term debt.

SP Solar

At June 30, 2019, SP Solar had total assets of $6.5 billion, total liabilities of $374 million, and noncontrolling interests of $1.1 billion. Cash distributions from SP Solar are allocated 67% to Southern Power and 33% to Global Atlantic in accordance with their partnership interest percentage. Under the terms of the limited partnership agreement, distributions without limited partner consent are limited to available cash and SP Solar is obligated to distribute all such available cash to its partners each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves.

SP Wind

At June 30, 2019, SP Wind had total assets of $2.5 billion, total liabilities of $136 million, and noncontrolling interests of $46 million. Under the terms of the limited liability agreement, distributions without Class A member consent are limited to available cash and SP Wind is obligated to distribute all such available cash to its members each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves. Cash distributions from SP Wind are generally allocated 60% to Southern Power and 40% to the three financial investors in accordance with the limited liability agreement.

Equity Method Investments

In June 2019, Southern Power made investments in certain legal entities that are considered VIEs but for which Southern Power is not the primary beneficiary because it does not control the most significant activities of the VIEs. These investments are accounted for as equity method investments. The total carrying amount of these investments is $144 million as of June 30, 2019, of which $116 million relates to membership interests in DSGP, an affiliate of Bloom Energy, that owns and operates fuel cell generation facilities in Delaware. Southern Power expects to consolidate DSGP, and record a noncontrolling interest, pending FERC approval of the transfer of the facilities. FERC approval is expected to occur in the third quarter 2019; however, the ultimate outcome of this matter cannot be determined at this time.

Southern Company Gas

See Note 7 to the financial statements in Item 8 of the Form 10-K for additional information on Southern Company Gas' equity method investments.

187

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments as of June 30, 2019 and December 31, 2018 and related income from those investments for the three- and six-month periods ended June 30, 2019 and 2018 were as follows:

Investment Balance	June 30, 2019		December 31, 2018
	(in millions)
SNG	$	1,243	$	1,261
Atlantic Coast Pipeline	101		83
PennEast Pipeline	77		71
Other(*)	88		123
Total	$	1,509	$	1,538

(*) Decrease primarily relates to the sale of Triton.

Earnings from Equity Method Investments	Three Months Ended June 30, 2019			Three Months Ended June 30, 2018		Six Months Ended June 30, 2019			Six Months Ended June 30, 2018
	(in millions)
SNG	$	32		$	27	$	74		$	66
Atlantic Coast Pipeline	3			1		6			3
PennEast Pipeline	1			1		3			2
Other(*)	(5		)	2		(3		)	3
Total	$	31		$	31	$	80		$	74

(*) Decrease primarily relates to the sale of Triton.

Triton

On May 29, 2019, Southern Company Gas sold its investment in Triton, a cargo container leasing company that was aggregated into Southern Company Gas' all other segment. This disposition resulted in a pre-tax loss of $6 million and a net after-tax gain of $7 million as a result of reversing a $13 million federal income tax valuation allowance.

SNG

Selected financial information of SNG for the three and six months ended June 30, 2019 and 2018 is as follows:

Income Statement Information	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
	(in millions)
Revenues	$	155	$	146	$	321	$	306
Operating income	86		60		192		159
Net income	64		54		148		132

(F) FINANCING

Bank Credit Arrangements

Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional electric operating companies' revenue bonds. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of June 30, 2019 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia

188

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Power, and $40 million at Mississippi Power). In addition, at June 30, 2019, the traditional electric operating companies had approximately $272 million (comprised of approximately $87 million at Alabama Power and $185 million at Georgia Power) of revenue bonds outstanding that were required to be remarketed within the next 12 months. See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and "Financing Activities" herein for additional information.

The following table outlines the committed credit arrangements by company as of June 30, 2019:

	Expires
Company	2019		2020		2022		2024		Total		Unused		Due within One Year
	(in millions)
Southern Company(a)	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—
Alabama Power	3		500		—		800		1,303		1,303		3
Georgia Power	—		—		—		1,750		1,750		1,736		—
Mississippi Power	—		—		150		—		150		150		—
Southern Power(b)	—		—		—		600		600		561		—
Southern Company Gas(c)	—		—		—		1,750		1,750		1,745		—
Other	—		30		—		—		30		30		30
Southern Company Consolidated	$	3	$	530	$	150	$	6,900	$	7,583	$	7,524	$	33

(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 $30 million was unused at June 30, 2019. 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 $1.25 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.

As reflected in the table above, in May 2019, Southern Company, Alabama Power, Georgia Power, and Southern Power each amended and restated certain of their multi-year credit arrangements, which, among other things, extended the maturity dates to 2024. Southern Power also decreased its borrowing capacity from $750 million to $600 million. In addition, Southern Company Gas Capital, along with Nicor Gas, amended and restated its multi-year credit arrangement to extend the maturity date to 2024 and decrease the aggregate borrowing capacity from $1.9 billion to $1.75 billion. In June 2019, Mississippi Power entered into a new $50 million credit arrangement that matures in 2022 and amended its existing credit arrangements, which, among other things, extended the maturity dates from 2019 to 2022.

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.

DOE Loan Guarantee Borrowings

See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding Georgia Power's 2014 loan guarantee agreement.

Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power and the DOE entered into a loan guarantee agreement in 2014 and the Amended and Restated Loan Guarantee Agreement in March 2019. Under the Amended and Restated Loan Guarantee Agreement, the DOE has agreed to guarantee the obligations of Georgia Power under note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities (FFB Credit Facilities). Under the FFB Credit Facilities, Georgia Power may make term loan borrowings through the FFB in an amount up to approximately $5.130 billion, provided that total

189

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

aggregate borrowings under the FFB Credit Facilities may not exceed 70% of (i) Eligible Project Costs minus (ii) approximately $1.492 billion (reflecting the amounts received by Georgia Power under the Guarantee Settlement Agreement less the Customer Refunds).

In March 2019, Georgia Power made borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million at an interest rate of 3.213% through the final maturity date of February 20, 2044. At June 30, 2019, Georgia Power had a total of $3.46 billion of borrowings outstanding under the FFB Credit Facilities.

All borrowings under the FFB Credit Facilities are full recourse to Georgia Power, and Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under its guarantee. Georgia Power's reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on Georgia Power's ability to grant liens on other property.

In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, 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 Eligible Project Costs.

Upon satisfaction of all conditions described above, advances may be requested on a quarterly basis through 2023. The final maturity date for each advance under the FFB Credit Facilities is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facilities will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.

Under the Amended and Restated Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default.

In the event certain mandatory prepayment events occur, the FFB's commitment to make further advances under the FFB Credit Facilities will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facilities over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle Services Agreement or rejection of the Vogtle Services Agreement in any Westinghouse bankruptcy if Georgia Power does not maintain access to intellectual property rights under the related intellectual property licenses; (ii) termination of the Bechtel Agreement, unless the Vogtle Owners enter into a replacement agreement; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC or by Georgia Power; (iv) failure of the holders of 90% of the ownership interests in Plant Vogtle Units 3 and 4 to vote to continue construction following certain schedule extensions; (v) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facilities; or (vi) loss of or failure to receive necessary regulatory approvals. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facilities. In addition, if Georgia Power discontinues construction of Plant Vogtle Units 3 and 4, Georgia Power would be obligated to immediately repay a portion of the outstanding borrowings under the FFB Credit Facilities to the extent such outstanding borrowings exceed 70% of Eligible Project Costs, net of the proceeds received by Georgia Power under the Guarantee Settlement Agreement less the Customer Refunds. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facilities. Under the FFB Credit Facilities, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.

190

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

In connection with any cancellation of Plant Vogtle Units 3 and 4, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume Georgia Power's rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of Georgia Power's ownership interest in Plant Vogtle Units 3 and 4.

Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2019:

Company	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)	$	2,100	$	—	$	—	$	—	$	—
Alabama Power	200		—		—		—		—
Georgia Power	—		513		223		835		3
Mississippi Power	—		43		—		—		—
Other	—		—		25		—		9
Southern Company Consolidated	$	2,300	$	556	$	248	$	835	$	12

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

(b) Represents the Southern Company parent entity.

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.

Southern Company

In January 2019, Southern Company repaid a $250 million short-term uncommitted bank credit arrangement and a $1.5 billion short-term floating rate bank loan.

Also in January 2019, 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, following the completion of the cash tender offers, in February 2019, Southern Company completed the redemption of all of the Series 2018A Notes, 1.85% Notes, and Series 2014B Notes remaining outstanding.

Georgia Power

In January 2019, 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.

191

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

In March 2019, Georgia Power reoffered to the public the following pollution control revenue bonds that previously had been purchased and held by Georgia Power:

• $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;

• 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; and

• $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.

In April 2019, Georgia Power purchased and held the following pollution control revenue bonds. In May 2019, Georgia Power reoffered these pollution control revenue bonds to the public.

• $55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1994;

• $30 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1995;

• $20 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Ninth Series 1994; and

• $10 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 1994.

In June 2019, Georgia Power reoffered to the public $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, which had been previously purchased and held by Georgia Power.

Also in June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR.

Mississippi Power

In March 2019, Mississippi Power reoffered to the public $43 million of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002, which previously had been purchased and held by Mississippi Power.

Southern Power

In May 2019, Southern Power repaid at maturity a $100 million aggregate principal amount short-term bank loan.

Earnings per Share

For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under stock-based compensation plans. See Note 12 to the financial statements in Item 8 of the Form 10-K for information on stock-based compensation plans. The effect of stock-based compensation plans was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:

	Three Months Ended June 30, 2019	Three Months Ended June 30, 2018	Six Months Ended June 30, 2019	Six Months Ended June 30, 2018
	(in millions)
As reported shares	1,044	1,014	1,041	1,012
Effect of stock-based compensation	8	—	8	5
Diluted shares	1,052	1,014	1,049	1,017

192

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

There were no stock-based compensation awards that were not included in the diluted earnings per share calculation because they were anti-dilutive for the three and six months ended June 30, 2019 and an immaterial amount of such awards was not included for the six months ended June 30, 2018. For the three months ended June 30, 2018, approximately 5.3 million shares of stock-based compensation awards were not included in the diluted earnings per share calculation because they were anti-dilutive.

(G) INCOME TAXES

See Note 10 to the financial statements in Item 8 of the Form 10-K for additional tax information.

Current and Deferred Income Taxes

Tax Credit Carryforwards

Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $2.0 billion as of June 30, 2019 compared to $2.4 billion as of December 31, 2018.

The federal ITC and PTC carryforwards begin expiring in 2034 and 2032, respectively, but are expected to be fully utilized by 2023. The estimated tax credit utilization reflects the projected taxable gains on the various sale transactions describe in Note (K) and could be further delayed by numerous factors, including the acquisition of additional renewable projects, the purchase of rights to additional PTCs of Plant Vogtle Units 3 and 4 pursuant to certain joint ownership agreements, and changes in taxable income projections. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

Effective Tax Rate

Details of significant changes in the effective tax rate for the applicable registrants are provided herein.

Southern Company

Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity and flowback of excess deferred income taxes at the regulated utilities, and federal income tax benefits from ITCs and PTCs, primarily at Southern Power.

Southern Company's effective tax rate was 33.5% for the six months ended June 30, 2019 compared to an effective tax benefit rate of (3.2)% for the corresponding period in 2018. The effective tax rate increase was primarily due to the tax impact from the sale of Gulf Power in 2019 and the 2018 charge to earnings related to the construction of Plant Vogtle Units 3 and 4. See Note (K) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.

Georgia Power

Georgia Power's effective tax rate was 21.7% for the six months ended June 30, 2019 compared to a benefit rate of (53.5)% for the corresponding period in 2018. The effective tax rate increase was primarily due to the 2018 charge to earnings related to the construction of Plant Vogtle Units 3 and 4, partially offset by an increase in state ITCs. See Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.

Mississippi Power

Mississippi Power's effective tax rate was 14.0% for the six months ended June 30, 2019 compared to 18.7% for the corresponding period in 2018. The effective tax rate decrease was primarily due to an increase in the flowback of excess deferred income taxes as a result of a settlement agreement reached with wholesale customers under the MRA tariff. See Note (B) under "Mississippi Power" for additional information.

193

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Southern Power

Southern Power's effective tax benefit rate was (35.5)% for the six months ended June 30, 2019 compared to (1,386.5)% for the corresponding period in 2018. The effective tax benefit rate decrease was primarily due to reductions of tax benefits from wind PTCs primarily as a result of the 2018 sale of the noncontrolling tax equity interest in SPC Wind and from changes in state apportionment rates following the reorganization of Southern Power's legal entities that own and operate certain solar facilities, partially offset by the net tax benefits from the sale of Plant Nacogdoches in 2019. See Note (K) and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power" for additional information.

Southern Company Gas

Southern Company Gas' effective tax rate was 18.0% for the six months ended June 30, 2019 compared to 39.1% for the corresponding period in 2018. This decrease was primarily related to an increase in the flowback of excess deferred income taxes in 2019, primarily at Atlanta Gas Light as previously authorized by the Georgia PSC, and the reversal of a federal tax valuation allowance in connection with Southern Company Gas' sale of its investment in Triton in 2019, as well as the tax impacts of the Southern Company Gas Dispositions in 2018. See Note (E) under "Southern Company Gas" and Notes 2 and 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.

(H) RETIREMENT BENEFITS

The Southern Company system has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2019. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.

See Note 11 to the financial statements in Item 8 of the Form 10-K for additional information.

194

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

On each registrant's condensed statements of income, the service cost component of net periodic benefit costs is included in other operations and maintenance expenses and all other components of net periodic benefit costs are included in other income (expense), net. Components of the net periodic benefit costs for the three and six months ended June 30, 2019 and 2018 are presented in the following tables.

Three Months Ended June 30, 2019	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	73		$	17		$	18		$	3		$	1		$	6
Interest cost	123			29			39			5			2			9
Expected return on plan assets	(221		)	(52		)	(73		)	(10		)	(3		)	(15		)
Amortization:
Prior service costs	1			1			1			—			—			—
Regulatory asset	—			—			—			—			—			4
Net (gain)/loss	30			9			11			2			—			—
Net periodic pension cost (income)	$	6		$	4		$	(4	)	$	—		$	—		$	4
Postretirement Benefits
Service cost	$	4		$	1		$	1		$	—		$	—		$	—
Interest cost	17			4			6			1			—			3
Expected return on plan assets	(17		)	(7		)	(6		)	(1		)	—			(1		)
Amortization:
Prior service costs	1			1			—			—			—			—
Regulatory asset	—			—			—			—			—			1
Net (gain)/loss	—			—			—			—			—			(1		)
Net periodic postretirement benefit cost	$	5		$	(1	)	$	1		$	—		$	—		$	2

195

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Six Months Ended June 30, 2019	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	146		$	34		$	37		$	6		$	3		$	12
Interest cost	246			57			78			11			3			18
Expected return on plan assets	(442		)	(103		)	(146		)	(20		)	(5		)	(30		)
Amortization:
Prior service costs	1			1			1			—			—			(1		)
Regulatory asset	—			—			—			—			—			7
Net (gain)/loss	60			18			22			3			—			1
Net periodic pension cost (income)	$	11		$	7		$	(8	)	$	—		$	1		$	7
Postretirement Benefits
Service cost	$	9		$	2		$	2		$	—		$	—		$	1
Interest cost	34			8			13			2			—			5
Expected return on plan assets	(33		)	(13		)	(12		)	(1		)	—			(3		)
Amortization:
Prior service costs	2			2			—			—			—			—
Regulatory asset	—			—			—			—			—			3
Net (gain)/loss	(1		)	—			—			—			—			(2		)
Net periodic postretirement benefit cost	$	11		$	(1	)	$	3		$	1		$	—		$	4

196

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Three Months Ended June 30, 2018	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	89		$	20		$	21		$	4		$	2		$	8
Interest cost	116			25			35			5			2			9
Expected return on plan assets	(235		)	(53		)	(74		)	(10		)	(2		)	(17		)
Amortization:
Prior service costs	1			1			1			—			—			—
Regulatory asset	—			—			—			—			—			4
Net (gain)/loss	54			13			17			2			—			3
Net periodic pension cost (income)	$	25		$	6		$	—		$	1		$	2		$	7
Postretirement Benefits
Service cost	$	6		$	2		$	1		$	1		$	—		$	—
Interest cost	18			4			7			1			—			3
Expected return on plan assets	(17		)	(7		)	(7		)	(1		)	—			(2		)
Amortization:
Prior service costs	1			1			1			—			—			—
Regulatory asset	—			—			—			—			—			2
Net (gain)/loss	4			1			2			—			—			—
Net periodic postretirement benefit cost	$	12		$	1		$	4		$	1		$	—		$	3

197

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Six Months Ended June 30, 2018	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	179		$	39		$	43		$	8		$	4		$	16
Interest cost	232			50			70			10			3			19
Expected return on plan assets	(471		)	(104		)	(148		)	(20		)	(5		)	(35		)
Amortization:
Prior service costs	2			1			1			—			—			(1		)
Regulatory asset	—			—			—			—			—			7
Net (gain)/loss	107			27			34			5			1			6
Net periodic pension cost (income)	$	49		$	13		$	—		$	3		$	3		$	12
Postretirement Benefits
Service cost	$	12		$	3		$	3		$	1		$	—		$	1
Interest cost	37			8			14			2			—			5
Expected return on plan assets	(34		)	(13		)	(13		)	(1		)	—			(4		)
Amortization:
Prior service costs	3			2			1			—			—			—
Regulatory asset	—			—			—			—			—			3
Net (gain)/loss	7			1			4			—			—			—
Net periodic postretirement benefit cost	$	25		$	1		$	9		$	2		$	—		$	5

198

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(I) FAIR VALUE MEASUREMENTS

As of June 30, 2019, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using:
As of June 30, 2019:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives(a)	$	270	$	177	$	12	$	—	$	459
Foreign currency derivatives	—		60		—		—		60
Investments in trusts:(b)(c)
Domestic equity	703		124		—		—		827
Foreign equity	62		206		—		—		268
U.S. Treasury and government agency securities	—		307		—		—		307
Municipal bonds	—		72		—		—		72
Pooled funds – fixed income	—		16		—		—		16
Corporate bonds	23		299		—		—		322
Mortgage and asset backed securities	—		74		—		—		74
Private equity	—		—		—		54		54
Cash and cash equivalents	1		—		—		—		1
Other	27		2		—		—		29
Cash equivalents	841		5		—		—		846
Other investments	9		17		—		—		26
Total	$	1,936	$	1,359	$	12	$	54	$	3,361
Liabilities:
Energy-related derivatives(a)	$	405	$	189	$	22	$	—	$	616
Interest rate derivatives	—		52		—		—		52
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		21		—		21
Total	$	405	$	264	$	43	$	—	$	712

199

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	Fair Value Measurements Using:
As of June 30, 2019:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Alabama Power
Assets:
Energy-related derivatives	$	—	$	6	$	—	$	—	$	6
Nuclear decommissioning trusts:(b)
Domestic equity	456		113		—		—		569
Foreign equity	62		60		—		—		122
U.S. Treasury and government agency securities	—		21		—		—		21
Municipal bonds	—		1		—		—		1
Corporate bonds	23		141		—		—		164
Mortgage and asset backed securities	—		25		—		—		25
Private equity	—		—		—		54		54
Other	7		—		—		—		7
Cash equivalents	430		5		—		—		435
Other investments	—		17		—		—		17
Total	$	978	$	389	$	—	$	54	$	1,421
Liabilities:
Energy-related derivatives	$	—	$	18	$	—	$	—	$	18
Georgia Power
Assets:
Energy-related derivatives	$	—	$	6	$	—	$	—	$	6
Nuclear decommissioning trusts:(b)(c)
Domestic equity	247		1		—		—		248
Foreign equity	—		143		—		—		143
U.S. Treasury and government agency securities	—		286		—		—		286
Municipal bonds	—		71		—		—		71
Corporate bonds	—		158		—		—		158
Mortgage and asset backed securities	—		50		—		—		50
Other	20		2		—		—		22
Total	$	267	$	717	$	—	$	—	$	984
Liabilities:
Energy-related derivatives	$	—	$	43	$	—	$	—	$	43
Interest rate derivatives	—		37		—		—		37
Total	$	—	$	80	$	—	$	—	$	80

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(UNAUDITED)

	Fair Value Measurements Using:
As of June 30, 2019:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Cash equivalents	170		—		—		—		170
Total	$	170	$	3	$	—	$	—	$	173
Liabilities:
Energy-related derivatives	$	—	$	19	$	—	$	—	$	19
Southern Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	—	$	2
Foreign currency derivatives	—		60		—		—		60
Cash equivalents	177		—		—		—		177
Total	$	177	$	62	$	—	$	—	$	239
Liabilities:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		21		—		21
Total	$	—	$	27	$	21	$	—	$	48
Southern Company Gas
Assets:
Energy-related derivatives(a)	$	270	$	160	$	12	$	—	$	442
Non-qualified deferred compensation trusts:
Domestic equity	—		10		—		—		10
Foreign equity	—		4		—		—		4
Pooled funds – fixed income	—		16		—		—		16
Cash equivalents	1		—		—		—		1
Total	$	271	$	190	$	12	$	—	$	473
Liabilities:
Energy-related derivatives(a)	$	405	$	105	$	22	$	—	$	532

(a) Energy-related derivatives exclude cash collateral of $178 million.

(b) Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

(c) Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of June 30, 2019, approximately $30 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds, including reinvested interest

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(UNAUDITED)

and dividends and excluding the funds' expenses, increased (decreased) by the amounts shown in the table below for the three and six months ended June 30, 2019 and 2018. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.

	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018			Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
	(in millions)
Southern Company	$	75	$	14		$	227	$	4
Alabama Power	38		15			125		10
Georgia Power	37		(1		)	102		(6		)

Valuation Methodologies

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

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

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. See Note 6 to the financial statements under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

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

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(UNAUDITED)

As of June 30, 2019, the fair value measurements of private equity investments held in Alabama Power's nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient totaled $54 million and unfunded commitments related to the private equity investments totaled $45 million. Private equity funds include funds-of-funds that invest in high-quality private equity funds across several market sectors, funds that invest in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.

As of June 30, 2019, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas(*)
	(in millions)
Long-term debt, including securities due within one year:
Carrying amount	$	42,596	$	7,922	$	10,969	$	1,618	$	5,011	$	5,916
Fair value	45,394		8,717		11,749		1,657		5,261		6,420

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

The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas.

Commodity Contracts with Level 3 Valuation Inputs

As of June 30, 2019, the fair value of Southern Company Gas' Level 3 physical natural gas forward contracts was $10 million. Since commodity contracts classified as Level 3 typically include a combination of observable and unobservable components, the changes in fair value may include amounts due in part to observable market factors, or changes to assumptions on the unobservable components. The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period.

	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	(in millions)
Beginning balance	$	(19	)	$	—
Transfers to Level 3	(3		)	(33		)
Changes in fair value	12			23
Ending balance	$	(10	)	$	(10	)

Changes in fair value of Level 3 instruments represent changes in gains and losses for the periods that are reported on Southern Company Gas' statements of income in natural gas revenues.

The valuation of certain commodity contracts requires the use of certain unobservable inputs. All forward pricing used in the valuation of such contracts is directly based on third-party market data, such as broker quotes and exchange settlements, when that data is available. If third-party market data is not available, then industry standard methodologies are used to develop inputs that maximize the use of relevant observable inputs and minimize the use of unobservable inputs. Observable inputs, including some forward prices used for determining fair value, reflect the best available market information. Unobservable inputs are updated using industry standard techniques such as extrapolation, combining observable forward inputs supplemented by historical market and other relevant data. Level 3 physical natural gas forward contracts include unobservable forward price inputs (ranging from $0.09

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(UNAUDITED)

to $1.39 per mmBtu). Forward price increases (decreases) as of June 30, 2019 would have resulted in higher (lower) values on a net basis.

(J) DERIVATIVES

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. 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. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information.

Energy-Related Derivatives

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

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

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(UNAUDITED)

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

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

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

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

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

At June 30, 2019, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:

	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)
Southern Company(*)	536	2023	2029
Alabama Power	88	2022	—
Georgia Power	200	2022	—
Mississippi Power	101	2023	—
Southern Power	8	2020	—
Southern Company Gas(*)	139	2021	2029

(*) Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 4.0 billion mmBtu and short natural gas positions of 3.9 billion mmBtu as of June 30, 2019, which is also included in Southern Company's total volume.

In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 25 million mmBtu for Southern Company, which includes 4 million mmBtu for Alabama Power, 8 million mmBtu for Georgia Power, 4 million mmBtu for Mississippi Power, and 9 million mmBtu for Southern Power.

For cash flow hedges of energy-related derivatives, the estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to earnings for the 12-month period ending June 30, 2020 are immaterial for all registrants.

Interest Rate Derivatives

Southern Company and certain subsidiaries may enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the

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(UNAUDITED)

same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

At June 30, 2019, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date	Fair Value Gain (Loss) at June 30, 2019
	(in millions)					(in millions)
Cash Flow Hedges of Forecasted Debt
Georgia Power	$	250	3-month LIBOR	2.23%	March 2025	$	(6	)
Georgia Power	250		3-month LIBOR	2.39%	September 2029	(10		)
Georgia Power	250		3-month LIBOR	2.40%	March 2030	(9		)
Georgia Power	250		3-month LIBOR	2.48%	February 2044	(12		)
Fair Value Hedges of Existing Debt
Southern Company(*)	300		2.75%	3-month LIBOR+0.92%	June 2020	(1		)
Southern Company(*)	1,500		2.35%	1-month LIBOR+0.87%	July 2021	(14		)
Georgia Power	200		4.25%	3-month LIBOR+2.46%	December 2019	(1		)
Southern Company Consolidated	$	3,000				$	(53	)

(*) Represents the Southern Company parent entity.

The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the 12-month period ending June 30, 2020 are $(18) million for Southern Company and immaterial for all other registrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2046 for the Southern Company parent entity, 2035 for Alabama Power, 2044 for Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.

Foreign Currency Derivatives

Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

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(UNAUDITED)

At June 30, 2019, the following foreign currency derivatives were outstanding:

	Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at June 30, 2019
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	14
Southern Power	564		3.78%	500		1.85%	June 2026	23
Total	$	1,241		€	1,100			$	37

The estimated pre-tax gains (losses) related to Southern Power's foreign currency derivatives expected to be reclassified from accumulated OCI to earnings for the 12-month period ending June 30, 2020 are $(23) million.

Derivative Financial Statement Presentation and Amounts

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

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(UNAUDITED)

The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:

	As of June 30, 2019						As of December 31, 2018
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Southern Company
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	7		$	57		$	8		$	23
Other deferred charges and assets/Other deferred credits and liabilities	9			34			9			26
Assets held for sale, current/Liabilities held for sale, current	—			—			—			6
Total derivatives designated as hedging instruments for regulatory purposes	$	16		$	91		$	17		$	55
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	7		$	3		$	7
Other deferred charges and assets/Other deferred credits and liabilities	—			1			1			2
Interest rate derivatives:
Other current assets/Other current liabilities	—			50			—			19
Other deferred charges and assets/Other deferred credits and liabilities	—			2			—			30
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	60			—			75			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	61		$	83		$	79		$	81
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	286		$	298		$	561		$	575
Other deferred charges and assets/Other deferred credits and liabilities	156			219			180			325
Total derivatives not designated as hedging instruments	$	442		$	517		$	741		$	900
Gross amounts recognized	$	519		$	691		$	837		$	1,036
Gross amounts offset(a)	$	(328	)	$	(506	)	$	(524	)	$	(801	)
Net amounts recognized in the Balance Sheets(b)	$	191		$	185		$	313		$	235

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(UNAUDITED)

	As of June 30, 2019						As of December 31, 2018
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Alabama Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	4		$	11		$	3		$	4
Other deferred charges and assets/Other deferred credits and liabilities	2			7			3			6
Total derivatives designated as hedging instruments for regulatory purposes	$	6		$	18		$	6		$	10
Gross amounts recognized	$	6		$	18		$	6		$	10
Gross amounts offset	$	(3	)	$	(3	)	$	(4	)	$	(4	)
Net amounts recognized in the Balance Sheets	$	3		$	15		$	2		$	6
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	26		$	2		$	8
Other deferred charges and assets/Other deferred credits and liabilities	5			17			4			13
Total derivatives designated as hedging instruments for regulatory purposes	$	6		$	43		$	6		$	21
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	37		$	—		$	2
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	37		$	—		$	2
Gross amounts recognized	$	6		$	80		$	6		$	23
Gross amounts offset	$	(6	)	$	(6	)	$	(6	)	$	(6	)
Net amounts recognized in the Balance Sheets	$	—		$	74		$	—		$	17

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(UNAUDITED)

	As of June 30, 2019						As of December 31, 2018
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	10		$	1		$	3
Other deferred charges and assets/Other deferred credits and liabilities	2			9			2			6
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	19		$	3		$	9
Gross amounts recognized	$	3		$	19		$	3		$	9
Gross amounts offset	$	(3	)	$	(3	)	$	(2	)	$	(2	)
Net amounts recognized in the Balance Sheets	$	—		$	16		$	1		$	7
Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	3		$	3		$	6
Other deferred charges and assets/Other deferred credits and liabilities	—			1			1			2
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	60			—			75			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	61		$	27		$	79		$	31
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	—		$	—		$	—
Total derivatives not designated as hedging instruments	$	1		$	—		$	—		$	—
Gross amounts recognized	$	62		$	27		$	79		$	31
Gross amounts offset	$	(1	)	$	(1	)	$	(3	)	$	(3	)
Net amounts recognized in the Balance Sheets	$	61		$	26		$	76		$	28

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(UNAUDITED)

	As of June 30, 2019						As of December 31, 2018
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Southern Company Gas
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	1		$	10		$	2		$	8
Other deferred charges and assets/Other deferred credits and liabilities	—			1			—			1
Total derivatives designated as hedging instruments for regulatory purposes	$	1		$	11		$	2		$	9
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	—		$	4		$	—		$	1
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	4		$	—		$	1
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	285		$	298		$	559		$	574
Other deferred charges and assets/Other deferred credits and liabilities	156			219			180			325
Total derivatives not designated as hedging instruments	$	441		$	517		$	739		$	899
Gross amounts of recognized	$	442		$	532		$	741		$	909
Gross amounts offset(a)	$	(315	)	$	(493	)	$	(508	)	$	(785	)
Net amounts recognized in the Balance Sheets(b)	$	127		$	39		$	233		$	124

(a) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $178 million and $277 million as of June 30, 2019 and December 31, 2018, respectively.

(b) Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $8 million as of December 31, 2018.

At June 30, 2019 and December 31, 2018, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at June 30, 2019
Derivative Category and Balance Sheet Location	Southern Company(*)			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas(*)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(48	)	$	(11	)	$	(25	)	$	(10	)	$	(2	)
Other regulatory assets, deferred	(23		)	(5		)	(12		)	(6		)	—
Other regulatory liabilities, current	6			3			—			—			3
Total energy-related derivative gains (losses)	$	(65	)	$	(13	)	$	(37	)	$	(16	)	$	1

(*) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $12 million at June 30, 2019.

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(UNAUDITED)

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2018
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(19	)	$	(3	)	$	(6	)	$	(2	)	$	(8	)
Other regulatory assets, deferred	(16		)	(3		)	(9		)	(4		)	—
Assets held for sale, current	(6		)	—			—			—			—
Other regulatory liabilities, current	1			—			—			—			1
Total energy-related derivative gains (losses)	$	(40	)	$	(6	)	$	(15	)	$	(6	)	$	(7	)

For the three and six months ended June 30, 2019 and 2018, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:

Gain (Loss) Recognized in OCI on Derivative	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)						(in millions)
Southern Company
Energy-related derivatives	$	(6	)	$	—		$	(6	)	$	12
Interest rate derivatives	(37		)	—			(37		)	(2		)
Foreign currency derivatives	(1		)	(73		)	(39		)	(21		)
Total	$	(44	)	$	(73	)	$	(82	)	$	(11	)
Georgia Power
Interest rate derivatives	$	(37	)	$	—		$	(37	)	$	—
Total	$	(37	)	$	—		$	(37	)	$	—
Southern Power
Energy-related derivatives	$	(2	)	$	(1	)	$	(2	)	$	10
Foreign currency derivatives	(1		)	(73		)	(39		)	(21		)
Total	$	(3	)	$	(74	)	$	(41	)	$	(11	)

For the three and six months ended June 30, 2019 and 2018, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other registrants.

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(UNAUDITED)

For the three and six months ended June 30, 2019 and 2018, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)						(in millions)
Southern Company
Total depreciation and amortization	$	755		$	783		$	1,506		$	1,552
Gain (loss) on energy-related cash flow hedges(a)	(1		)	1			(4		)	2
Total interest expense, net of amounts capitalized	(429		)	(470		)	(859		)	(928		)
Gain (loss) on interest rate cash flow hedges(a)	(5		)	(6		)	(9		)	(11		)
Gain (loss) on foreign currency cash flow hedges(a)	(6		)	(7		)	(12		)	(12		)
Gain (loss) on interest rate fair value hedges(b)	19			(7		)	33			(31		)
Total other income (expense), net	99			78			176			138
Gain (loss) on foreign currency cash flow hedges(a)(c)	16			(73		)	(8		)	(37		)
Southern Power
Total depreciation and amortization	$	119		$	125		$	237		$	240
Gain (loss) on energy-related cash flow hedges(a)	(1		)	1			(4		)	2
Total interest expense, net of amounts capitalized	(41		)	(46		)	(84		)	(93		)
Gain (loss) on foreign currency cash flow hedges(a)	(6		)	(7		)	(12		)	(12		)
Total other income (expense), net	40			2			41			5
Gain (loss) on foreign currency cash flow hedges(a)(c)	16			(73		)	(8		)	(37		)

(a) Reclassified from accumulated OCI into earnings.

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

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

For the three and six months ended June 30, 2019 and 2018, the pre-tax effects of cash flow and fair value hedge accounting on income for energy-related derivatives and interest rate derivatives were immaterial for the traditional electric operating companies and Southern Company Gas.

As of June 30, 2019 and December 31, 2018, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

	Carrying Amount of the Hedged Item						Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	As of June 30, 2019			As of December 31, 2018			As of June 30, 2019		As of December 31, 2018
	(in millions)						(in millions)
Southern Company
Securities due within one year	$	(499	)	$	(498	)	$	1	$	2
Long-term debt	(2,087		)	(2,052		)	7		41
Georgia Power
Securities due within one year	$	(499	)	$	(498	)	$	1	$	2

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the three and six months ended June 30, 2019 and 2018, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:

		Gain (Loss)
		Three Months Ended June 30,						Six Months Ended June 30,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2019			2018			2019		2018
		(in millions)						(in millions)
Southern Company
Energy-related derivatives:	Natural gas revenues(*)	$	50		$	(28	)	$	83	$	(43	)
	Cost of natural gas	(5		)	2			3		4
Total derivatives in non-designated hedging relationships		$	45		$	(26	)	$	86	$	(39	)
Southern Company Gas
Energy-related derivatives:	Natural gas revenues(*)	$	50		$	(28	)	$	83	$	(43	)
	Cost of natural gas	(5		)	2			3		4
Total derivatives in non-designated hedging relationships		$	45		$	(26	)	$	86	$	(39	)

(*) Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for all periods presented.

For the three and six months ended June 30, 2019 and 2018, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies and Southern Power.

Contingent Features

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At June 30, 2019, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

For the registrants with interest rate derivatives at June 30, 2019, the fair value of interest rate derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, was immaterial. At June 30, 2019, the fair value of energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial for all registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade. Following the sale of Gulf Power to NextEra Energy, Gulf Power is continuing to participate in the Southern Company power pool for a defined transition period that, subject to certain potential adjustments, is scheduled to end on January 1, 2024.

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

Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Alabama Power and Southern Power may be required to post collateral. At June 30, 2019, cash

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(UNAUDITED)

collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At June 30, 2019, cash collateral held on deposit in broker margin accounts was $178 million.

The registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The registrants only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk. Prior to entering into a physical transaction, Southern Company Gas assigns physical wholesale counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch Ratings Inc. ratings, commercially available credit reports, and audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the 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.

Southern Company Gas also utilizes master 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 it 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. Master 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 master netting and cash collateral agreements include such provisions. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

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

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(UNAUDITED)

(K) ACQUISITIONS AND DISPOSITIONS

See Note 15 to the financial statements in Item 8 of the Form 10-K for additional information.

Southern Company

On January 1, 2019, Southern Company completed the sale of all of the capital stock of Gulf Power to 700 Universe, LLC, a wholly-owned subsidiary of NextEra Energy, for an aggregate cash purchase price of approximately $5.8 billion (less $1.3 billion of indebtedness assumed), subject to customary working capital adjustments. The preliminary gain associated with the sale of Gulf Power totaled $2.5 billion pre-tax ($1.3 billion after tax). The assets and liabilities of Gulf Power were classified as assets held for sale and liabilities held for sale on Southern Company's balance sheet as of December 31, 2018.

On July 22, 2019, PowerSecure completed the sale of its utility infrastructure services business unit for approximately $71 million, subject to customary working capital adjustments. The related assets and liabilities were classified as held for sale on Southern Company's balance sheet as of June 30, 2019. In contemplation of this sale, a goodwill impairment charge of $32 million was recorded in the second quarter 2019.

See "Assets Held for Sale" herein for additional information.

Southern Power

Construction Projects

During the six months ended June 30, 2019, Southern Power completed construction of and placed in service the 385-MW Plant Mankato expansion and continued construction of two other projects as described in the table below. Total aggregate construction costs, excluding acquisition costs, are expected to be between $405 million and $450 million for the Wildhorse Mountain and Reading facilities. At June 30, 2019, total costs of construction incurred for these projects were $186 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Projects Completed During the Six Months Ended June 30, 2019
Mankato expansion(a)	Natural Gas	385	Mankato, MN	May 2019	20 years
Projects Under Construction as of June 30, 2019
Wildhorse Mountain(b)	Wind	100	Pushmataha County, OK	Fourth quarter 2019	20 years
Reading(c)	Wind	200	Osage and Lyon Counties, KS	Second quarter 2020	12 years

(a) In November 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato, including this expansion that was completed during May 2019. This transaction is subject to state commission approvals and is expected to close in fall 2019. The expansion unit started providing energy under a PPA with Northern States Power on June 1, 2019. See "Sales of Natural Gas and Biomass Plants" below.

(b) In May 2018, Southern Power purchased 100% of the Wildhorse Mountain facility. Southern Power entered into a tax equity partnership in June 2019 with funding of tax equity amounts expected to occur upon commercial operation.

(c) 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. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the class B membership interests.

Development Projects

Southern Power continues to evaluate and refine the deployment of wind turbine equipment purchased in 2016 and 2017 to potential joint development and construction projects as well as the amount of MW capacity to be

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(UNAUDITED)

constructed. During the six months ended June 30, 2019, certain wind turbine equipment was sold, resulting in a gain on the sale of approximately $14 million.

On June 14, 2019, Southern Power entered into an agreement with Bloom Energy to acquire a majority interest in its affiliate DSGP, which owns and operates fuel cell generation facilities in Delaware, for a total amount not to exceed $173 million. In June 2019, Southern Power, through an affiliate, contributed a total of $116 million in exchange for Class B membership interests in DSGP, with the remainder expected to be contributed by the end of 2019. FERC approval of the transfer of the facilities is expected to occur in the third quarter 2019; however, the ultimate outcome of this matter cannot be determined at this time.

Sales of Natural Gas and Biomass Plants

On June 13, 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for an aggregate cash purchase price of approximately $461 million, including working capital adjustments. This sale resulted in an $88 million after-tax gain.

On May 4, 2019, Southern Power achieved commercial operation of the 385-MW natural gas expansion unit at Plant Mankato and started providing energy under a PPA with Northern States Power on June 1, 2019. The sale of Plant Mankato to Northern States Power remains subject to Minnesota and North Dakota state commission approvals and is expected to close in fall 2019. If these state commission approvals are not obtained by October 1, 2019, either party has the option to terminate the sale, which, if elected, would result in the payment of a $15 million termination fee by Northern States Power to Southern Power. The ultimate outcome of this matter cannot be determined at this time. The assets and liabilities of Plant Mankato are classified as assets held for sale and liabilities held for sale on Southern Company's and Southern Power's balance sheets as of June 30, 2019 and December 31, 2018. See "Assets Held for Sale" herein for additional information.

Assets Subject to Lien

Under the terms of the PPAs for Plant Mankato, approximately $545 million of assets, primarily related to property, plant, and equipment, are subject to lien at June 30, 2019.

Assets Held for Sale

As discussed above, Southern Company and Southern Power each have assets and liabilities held for sale on their balance sheets at June 30, 2019 and December 31, 2018. Assets and liabilities held for sale have been classified separately on each company's balance sheet at the lower of carrying value or fair value less costs to sell at the time the criteria for held-for-sale classification were met. For assets and liabilities held for sale recorded at fair value on a nonrecurring basis, the fair value of assets held for sale is based primarily on unobservable inputs (Level 3), which includes the agreed upon sales prices in executed sales agreements.

Upon classification as held for sale in November 2018 and April 2019 for Plant Mankato and Plant Nacogdoches, respectively, Southern Power ceased recognizing depreciation and amortization on the long-lived assets to be sold.

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(UNAUDITED)

The following table provides Southern Company's and Southern Power's major classes of assets and liabilities classified as held for sale at June 30, 2019 and December 31, 2018:

	Southern Company		Southern Power
	(in millions)
At June 30, 2019
Assets Held for Sale:
Current assets	$	58	$	10
Total property, plant, and equipment	588		559
Goodwill and other intangible assets	51		40
Other non-current assets	46		—
Total Assets Held for Sale	$	743	$	609
Liabilities Held for Sale:
Current liabilities	$	36	$	10
Other non-current liabilities	39		—
Total Liabilities Held for Sale	$	75	$	10
At December 31, 2018
Assets Held for Sale:
Current assets	$	393	$	8
Total property, plant, and equipment	4,583		536
Other intangible assets	40		40
Other non-current assets	727		—
Total Assets Held for Sale	$	5,743	$	584
Liabilities Held for Sale:
Current liabilities	$	425	$	15
Long-term debt	1,286		—
Accumulated deferred income taxes	618		—
Other non-current liabilities	932		—
Total Liabilities Held for Sale	$	3,261	$	15

Southern Company and Southern Power each concluded that the sale of their assets, both individually and combined, did not represent a strategic shift in operations that has, or is expected to have, a major effect on its operations and financial results; therefore, none of the assets related to the sales have been classified as discontinued operations for any of the periods presented.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Gulf Power and Southern Power's equity interests in Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) and Plant Nacogdoches represented individually significant components of Southern Company and Southern Power, respectively; therefore, pre-tax profit for these components for the three and six months ended June 30, 2019 and 2018 is presented below:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
	(in millions)
Earnings before income taxes:
Gulf Power	$	—	$	31	$	—	$	87
Southern Power's Florida Plants	$	—	$	14	$	—	$	24
Southern Power's Plant Nacogdoches(*)	$	9	$	7	$	16	$	13

(*) Earnings before income taxes for Plant Nacogdoches for the three and six months ended June 30, 2019 represents the beginning of the corresponding period through June 13, 2019 (the divestiture date).

(L) LEASES

On January 1, 2019, the registrants adopted the provisions of FASB ASC Topic 842 (as amended), Leases (ASC 842), which require lessees to recognize leases with a term of greater than 12 months on the balance sheet as lease obligations, representing the discounted future fixed payments due, along with right-of-use (ROU) assets that will be amortized over the term of each lease.

The registrants elected the transition methodology provided by ASC 842, whereby the applicable requirements are applied on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. The registrants also elected the package of practical expedients provided by ASC 842 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, the registrants applied the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and elected the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed.

Lessee

As lessee, the registrants lease certain electric generating units (including renewable energy facilities), real estate/land, communication towers, railcars, and other equipment and vehicles. The major categories of lease obligations are as follows:

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Electric generating units	$	1,072	$	150	$	1,580	$	—	$	—	$	—
Real estate/land	800		4		62		2		395		81
Communication towers	147		1		3		—		—		13
Railcars	54		25		27		3		—		—
Other	145		10		14		2		—		—
Total	$	2,218	$	190	$	1,686	$	7	$	395	$	94

Real estate/land leases primarily consist of commercial real estate leases at Southern Company, Georgia Power, and Southern Company Gas and various land leases primarily associated with renewable energy facilities at Southern

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Power. The commercial real estate leases have remaining terms of up to 25 years while the land leases have remaining terms of up to 48 years, including renewal periods.

Communication towers are leased for the installation of equipment to provide cellular phone service to customers and to support the automated meter infrastructure programs at the traditional electric operating companies. Communication tower leases have terms of up to 10 years with options to renew for periods up to 20 years.

While renewal options exist in many of the leases, other than for land leases associated with renewable energy facilities, the expected term used in calculating the lease obligation generally reflects only the noncancelable period of the lease as it is not considered reasonably certain that the lease will be extended. The expected term of land leases associated with renewable energy facilities includes renewal periods reasonably certain of exercise resulting in an expected lease term at least equal to the expected life of the renewable energy facilities.

Contracts that Contain a Lease

While not specifically structured as a lease, some of the PPAs at Alabama Power and Georgia Power are deemed to represent a lease of the underlying electric generating units when the terms of the PPA convey the right to control the use of the underlying assets. Amounts recorded for leases of electric generating units are generally based on the amount of scheduled capacity payments due over the remaining term of the affiliate PPA, which varies between four and 18 years. Georgia Power has several PPAs with Southern Power that Georgia Power accounts for as leases with a lease obligation of approximately $660 million at June 30, 2019. The amount paid for energy under these affiliate PPAs reflects a price that would be paid in an arm's-length transaction as those amounts have been reviewed and approved by the Georgia PSC.

Short-term Leases

Leases with an initial term of 12 months or less are not recorded on the balance sheet; the registrants generally recognize lease expense for these leases on a straight-line basis over the lease term.

Residual Value Guarantees

Residual value guarantees exist primarily in railcar leases at Alabama Power and Georgia Power and the amounts probable of being paid under those guarantees are included in the lease payments. All such amounts are immaterial as of June 30, 2019.

Lease and Nonlease Components

For all asset categories, with the exception of electric generating units, gas pipelines, and real estate leases, the registrants combine lease payments and any nonlease components, such as asset maintenance, for purposes of calculating the lease obligation and the right-of-use asset.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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

	As of June 30, 2019
	Southern  Company(*)		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Operating Leases
Operating lease ROU assets, net	$	1,907	$	152	$	1,492	$	7	$	370	$	95
Operating lease obligations - current	$	241	$	48	$	140	$	2	$	22	$	15
Operating lease obligations - non current	1,733		137		1,377		5		373		79
Total operating lease obligations	$	1,974	$	185	$	1,517	$	7	$	395	$	94
Finance Leases
Finance lease ROU assets, net	$	237	$	5	$	142	$	—	$	—	$	—
Finance lease obligations - current	$	24	$	1	$	10	$	—	$	—	$	—
Finance lease obligations - noncurrent	220		4		159		—		—		—
Total finance lease obligations	$	244	$	5	$	169	$	—	$	—	$	—

(*) Includes operating lease ROU assets, net and operating lease obligations classified as held for sale.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Lease costs for the three and six months ended June 30, 2019, which includes both amounts recognized as operations and maintenance expense and amounts capitalized as part of the cost of another asset, are as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended June 30, 2019
Lease cost
Operating lease cost	$	77	$	13	$	50	$	1	$	7	$	5
Finance lease cost:
Amortization of ROU assets	7		—		4		—		—		—
Interest on lease obligations	3		—		4		—		—		—
Total finance lease cost	10		—		8		—		—		—
Short-term lease costs	13		6		6		—		—		—
Variable lease cost	29		1		25		—		1		—
Sublease income	—		—		—		—		—		—
Total lease cost	$	129	$	20	$	89	$	1	$	8	$	5
For the Six Months Ended June 30, 2019
Lease cost
Operating lease cost	$	147	$	20	$	99	$	1	$	14	$	9
Finance lease cost:
Amortization of ROU assets	14		—		7		—		—		—
Interest on lease obligations	6		—		9		—		—		—
Total finance lease cost	20		—		16		—		—		—
Short-term lease costs	30		11		12		—		—		—
Variable lease cost	48		1		41		—		3		—
Sublease income	—		—		—		—		—		—
Total lease cost	$	245	$	32	$	168	$	1	$	17	$	9

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Georgia Power has variable lease payments that are based on the amount of energy produced by certain renewable generating facilities subject to PPAs.

Other information with respect to cash and noncash activities related to leases, as well as weighted-average lease terms and discount rates, is as follows:

	For the Six Months Ended June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Other information
Cash paid for amounts included in the measurements of lease obligations:
Operating cash flows from operating leases	$	129	$	20	$	75	$	1	$	12	$	9
Operating cash flows from finance leases	2		—		10		—		—		—
Financing cash flows from finance leases	16		—		3		—		—		—
ROU assets obtained in exchange for new operating lease obligations	55		5		13		—		—		13
ROU assets obtained in exchange for new finance lease obligations	33		1		28		—		—		—

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
Weighted-average remaining lease term in years:
Operating leases	14.0		3.6		10.5		7.0		33.5		9.7
Finance leases	18.3		12.8		11.0		N/A		N/A		N/A
Weighted-average discount rate:
Operating leases	4.53	%	3.33	%	4.46	%	4.06	%	5.68	%	3.73	%
Finance leases	5.05	%	3.67	%	10.69	%	N/A		N/A		N/A

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Maturities of lease liabilities are as follows:

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Maturity Analysis
Operating leases:
2019 (remaining)	$	178	$	33	$	129	$	1	$	13	$	9
2020	295		53		203		2		22		17
2021	279		52		198		1		23		16
2022	268		52		196		1		23		13
2023	204		4		197		1		24		11
Thereafter	1,661		2		990		2		849		49
Total	2,885		196		1,913		8		954		115
Less: Present value discount	911		11		396		1		559		21
Operating lease obligations	$	1,974	$	185	$	1,517	$	7	$	395	$	94
Finance leases:
2019 (remaining)	$	16	$	—	$	16	$	—	$	—	$	—
2020	33		1		28		—		—		—
2021	27		1		25		—		—		—
2022	23		1		25		—		—		—
2023	18		1		25		—		—		—
Thereafter	266		1		165		—		—		—
Total	383		5		284		—		—		—
Less: Present value discount	139		—		115		—		—		—
Finance lease obligations	$	244	$	5	$	169	$	—	$	—	$	—

Payments made under PPAs at Georgia Power for energy generated from certain renewable energy facilities accounted for as operating and finance leases are considered variable lease costs and are therefore not reflected in the above maturity analysis. As of June 30, 2019, Southern Company and Southern Power have additional operating leases, primarily for land, that have not yet commenced. These operating leases are expected to commence during the remainder of 2019 through 2022, with lease terms of up to 31 years, and have estimated total obligations of $81 million.

For additional information on each registrant's operating lease obligations at December 31, 2018, see Note 9 to the financial statements in Item 8 of the Form 10-K.

Lessor

With the exception of Southern Company Gas, the registrants are each considered lessors in various arrangements that have been determined to contain a lease due to the customer's ability to control the use of the underlying asset owned by the applicable registrant. For the traditional electric operating companies, these arrangements consist of outdoor lighting contracts accounted for as operating leases with initial terms of up to five years, after which the contracts renew on a month-to-month basis at the customer's option. For Mississippi Power, these arrangements also include tolling arrangements related to electric generating units accounted for as sales-type leases with terms of up to 20 years. For Southern Power, these arrangements consist of PPAs related to electric generating units, including renewable energy facilities, accounted for as operating leases with terms of up to 28 years. For Southern Company, these arrangements also include PPAs related to fuel cells accounted for as operating leases with terms of up to 15

224

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

years. Southern Company Gas is the lessor in operating leases related to gas pipelines with remaining terms of up to 24 years.

Lease income for the three and six months ended June 30, 2019 is as follows:

	Southern Company		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended June 30, 2019
Lease income - interest income on sales-type leases	$	2	$	—	$	2	$	—	$	—
Lease income - operating leases	67		19		—		39		9
Variable lease income	115		—		—		125		—
Total lease income	$	184	$	19	$	2	$	164	$	9
For the Six Months Ended June 30, 2019
Lease income - interest income on sales-type leases	$	5	$	—	$	5	$	—	$	—
Lease income - operating leases	139		39		—		80		17
Variable lease income	182		—		—		198		—
Total lease income	$	326	$	39	$	5	$	278	$	17

No profit or loss was recognized by Mississippi Power upon commencement of a sales-type lease during the first quarter 2019.

Lease income for Southern Power is included in wholesale revenues. Lease payments received under tolling arrangements and PPAs consist of either scheduled payments or variable payments based on the amount of energy produced by the underlying electric generating units. Scheduled payments to be received under outdoor lighting contracts, tolling arrangements, and PPAs accounted for as leases are presented in the following maturity analyses.

The undiscounted cash flows to be received under tolling arrangements accounted for as sales-type leases are as follows:

	As of June 30, 2019
	Southern Company		Mississippi Power
	(in millions)
2019 (remaining)	$	7	$	7
2020	14		14
2021	14		14
2022	13		13
2023	12		12
Thereafter	135		135
Total undiscounted cash flows	$	195	$	195
Lease receivable	106		106
Difference between undiscounted cash flows and discounted cash flows	$	89	$	89

225

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

The undiscounted cash flows to be received under operating leases and contracts accounted for as operating leases (adjusted for intercompany eliminations) are as follows:

	As of June 30, 2019
	Southern Company		Georgia Power		Southern Power		Southern Company Gas
	(in millions)
2019 (remaining)	$	75	$	13	$	52	$	17
2020	125		26		65		35
2021	118		18		66		35
2022	109		8		68		34
2023	103		2		69		34
Thereafter	1,142		—		350		497
Total	$	1,672	$	67	$	670	$	652

Southern Power receives payments for renewable energy under PPAs accounted for as operating leases that are considered contingent rents and are therefore not reflected in the table above. Southern Power allocates revenue to the nonlease components of PPAs based on the stand-alone selling price of capacity and energy. The undiscounted cash flows to be received under outdoor lighting contracts accounted for as operating leases at Alabama Power and Mississippi Power are immaterial.

(M) SEGMENT AND RELATED INFORMATION

Southern Company

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 – Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in three Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas pipeline investments, wholesale gas services, and gas marketing services.

Southern Company's reportable business segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $117 million and $204 million for the three and six months ended June 30, 2019, respectively, and $109 million and $192 million for the three and six months ended June 30, 2018, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were immaterial for both the three and six months ended June 30, 2019 and 2018. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $16 million and $33 million for the three and six months ended June 30, 2019, respectively, and $22 million and $58 million for the three and six months ended June 30, 2018, respectively. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy solutions, such as distributed energy infrastructure and energy efficiency products and services, to customers, as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.

226

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Financial data for business segments and products and services for the three and six months ended June 30, 2019 and 2018 was as follows:

	Electric Utilities
	Traditional Electric Operating Companies			Southern Power		Eliminations			Total			Southern Company Gas			All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2019
Operating revenues	$	3,899		$	510	$	(119	)	$	4,290		$	689		$	186		$	(67	)	$	5,098
Segment net income (loss)(a)(b)(c)(d)	782			174		—			956			106			(154		)	(9		)	899
Six Months Ended June 30, 2019
Operating revenues	$	7,343		$	953	$	(211	)	$	8,085		$	2,163		$	368		$	(106	)	$	10,510
Segment net income (loss)(a)(b)(c)(d)	1,346			230		—			1,576			376			1,041			(11		)	2,982
At June 30, 2019
Goodwill	$	—		$	2	$	—		$	2		$	5,015		$	265		$	—		$	5,282
Total assets	78,314			14,518		(783		)	92,049			20,761			3,343			(1,286		)	114,867
Three Months Ended June 30, 2018
Operating revenues	$	4,124		$	555	$	(114	)	$	4,565		$	730		$	381		$	(49	)	$	5,627
Segment net income (loss)(a)(b)(d)	(48		)	22		—			(26		)	(31		)	(100		)	3			(154		)
Six Months Ended June 30, 2018
Operating revenues	$	8,104		$	1,064	$	(220	)	$	8,948		$	2,369		$	782		$	(100	)	$	11,999
Segment net income (loss)(a)(b)(d)(e)	563			143		—			706			248			(174		)	4			784
At December 31, 2018
Goodwill	$	—		$	2	$	—		$	2		$	5,015		$	298		$	—		$	5,315
Total assets	79,382			14,883		(306		)	93,959			21,448			3,285			(1,778		)	116,914

(a) Attributable to Southern Company.

(b) Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated losses on plants under construction of $4 million ($3 million after tax) and $1.1 billion ($0.8 billion after tax) for the three months ended June 30, 2019 and 2018, respectively, and $6 million ($5 million after tax) and $1.1 billion ($0.8 billion after tax) for the six months ended June 30, 2019 and 2018, respectively. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) under "Georgia Power – Nuclear Construction" and "Mississippi Power – Kemper County Energy Facility" for additional information.

(c) Segment net income (loss) for the "All Other" column includes the preliminary pre-tax gain associated with the sale of Gulf Power of $2.5 billion ($1.3 billion after tax) for the six months ended June 30, 2019, of which $(15) million ($(11) million after tax) was recorded in the three months ended June 30, 2019, as well as a goodwill impairment charge of $32 million for the three and six months ended June 30, 2019 in contemplation of the sale of one of PowerSecure's business units. See Note (K) under "Southern Company" for additional information.

(d) Segment net income (loss) for Southern Power includes a $23 million pre-tax gain ($88 million gain after tax) on the sale of Plant Nacogdoches for the three and six months ended June 30, 2019 and a pre-tax impairment charge of $119 million ($89 million after tax) for the three and six months ended June 30, 2018 related to the sale of Southern Power's Florida Plants. See Note (K) under "Southern Power" and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Sale of Natural Gas Plants" for additional information.

(e) Segment net income (loss) for Southern Company Gas includes a goodwill impairment charge of $42 million for the six months ended June 30, 2018 related to the sale of Pivotal Home Solutions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

227

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Products and Services

	Electric Utilities' Revenues
	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended June 30, 2019	$	3,540	$	542	$	208	$	4,290
Three Months Ended June 30, 2018	3,740		616		209		4,565
Six Months Ended June 30, 2019	$	6,623	$	1,041	$	421	$	8,085
Six Months Ended June 30, 2018	7,308		1,239		401		8,948

	Southern Company Gas' Revenues
	Gas Distribution Operations(a)		Gas Marketing Services(b)		Other		Total
	(in millions)
Three Months Ended June 30, 2019	$	563	$	58	$	68	$	689
Three Months Ended June 30, 2018	638		89		3		730
Six Months Ended June 30, 2019	$	1,724	$	287	$	152	$	2,163
Six Months Ended June 30, 2018	1,838		359		172		2,369

(a) Operating revenues for the three gas distribution operations dispositions were $70 million and $237 million for the three and six months ended June 30, 2018, respectively.

(b) Operating revenues for Pivotal Home Solutions were $24 million and $55 million for the three and six months ended June 30, 2018, respectively.

Southern Company Gas

Southern Company Gas manages its business through four reportable segments – gas distribution operations, gas pipeline investments, wholesale gas services, and gas marketing services. The non-reportable segments are combined and presented as all other.

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

Gas pipeline investments consists of joint ventures in natural gas pipeline investments including a 50% interest in SNG, two significant pipeline construction projects, and a 50% joint ownership interest in the Dalton Pipeline. These natural gas pipelines enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas.

Wholesale gas services provides natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services engages in natural gas storage and gas pipeline arbitrage and related activities.

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

The all other column includes segments below the quantitative threshold for separate disclosure. This includes Southern Company Gas' storage and fuels operations, its investment in Triton through the completion of its sale on May 29, 2019, and other subsidiaries that fall below the quantitative threshold for separate disclosure. See Note (E) under "Southern Company Gas" for additional information and related disclosures.

228

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Business segment financial data for the three and six months ended June 30, 2019 and 2018 was as follows:

	Gas Distribution Operations(a)		Gas Pipeline Investments		Wholesale Gas Services(b)			Gas Marketing Services(c)(d)			Total			All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2019
Operating revenues	$	568	$	8	$	48		$	58		$	682		$	13		$	(6	)	$	689
Segment net income (loss)	58		25		23			(3		)	103			3			—			106
Six Months Ended June 30, 2019
Operating revenues	$	1,740	$	16	$	134		$	287		$	2,177		$	24		$	(38	)	$	2,163
Segment net income (loss)	191		57		70			58			376			—			—			376
Total assets at June 30, 2019	17,397		1,768		668			1,527			21,360			10,934			(11,533		)	20,761
Three Months Ended June 30, 2018
Operating revenues	$	643	$	8	$	(16	)	$	89		$	724		$	11		$	(5	)	$	730
Segment net income (loss)	68		21		(21		)	(76		)	(8		)	(23		)	—			(31		)
Six Months Ended June 30, 2018
Operating revenues	$	1,856	$	16	$	150		$	359		$	2,381		$	26		$	(38	)	$	2,369
Segment net income (loss)	216		48		83			(63		)	284			(36		)	—			248
Total assets at December 31, 2018	17,266		1,763		1,302			1,587			21,918			11,112			(11,582		)	21,448

(a) Operating revenues for the three gas distribution operations dispositions were $70 million and $237 million for the three and six months ended June 30, 2018, respectively. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

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

	Third Party Gross Revenues		Intercompany Revenues		Total Gross Revenues		Less Gross Gas Costs		Operating Revenues
	(in millions)
Three Months Ended June 30, 2019	$	1,223	$	63	$	1,286	$	1,238	$	48
Three Months Ended June 30, 2018	1,336		102		1,438		1,454		(16		)
Six Months Ended June 30, 2019	$	3,148	$	151	$	3,299	$	3,165	$	134
Six Months Ended June 30, 2018	3,274		269		3,543		3,393		150

(c) Operating revenues for Pivotal Home Solutions were $24 million and $55 million for the three and six months ended June 30, 2018, respectively. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information on the sale of Pivotal Home Solutions.

(d) Segment net income (loss) for gas marketing services includes a loss on disposition of $36 million for the three and six months ended June 30, 2018 and a goodwill impairment charge of $42 million for the six months ended June 30, 2018 related to the sale of Pivotal Home Solutions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

229

PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrants are involved.

Item 1A. Risk Factors.

See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. There have been no material changes to these risk factors from those previously disclosed in the Form 10-K.

Item 6.    Exhibits.

The exhibits below with an asterisk (*) preceding the exhibit number are filed herewith. The remaining exhibits have previously been filed with the SEC and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements.

	(2) Plan of acquisition, reorganization, arrangement, liquidation or succession
	Southern Power
	(e)1	-	Membership Interest Purchase Agreement, dated as of April 17, 2019, by and between Southern Power and The City of Austin d/b/a Austin Energy. (Designated in Form 8-K dated June 13, 2019, File No. 001-37803, as Exhibit 2.1.)
	(e)2	-	Letter Agreement, dated as of May 24, 2019, by and between Southern Power and The City of Austin d/b/a Austin Energy. (Designated in Form 8-K dated June 13, 2019, File No. 001-37803, as Exhibit 2.2.)
	(3) Articles of Incorporation and By-Laws
	Mississippi Power
*	(d)	-	By-laws of Mississippi Power as amended.
	Southern Company Gas
*	(e)	-	By-laws of Southern Company Gas as amended.
	(24) Power of Attorney and Resolutions
	Southern Company
	(a)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2018, File No. 1-3526 as Exhibit 24(a)1.)
	Alabama Power
	(b)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2018, File No. 1-3164 as Exhibit 24(b).)
	Georgia Power
	(c)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2018, File No. 1-6468 as Exhibit 24(c).)
	Mississippi Power
	(d)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2018, File No. 001-11229 as Exhibit 24(d).)

230

	Southern Power
	(e)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2018, File No. 001-37803 as Exhibit 24(e)1.)
	Southern Company Gas
	(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2018, File No. 1-14174 as Exhibit 24(f)1.)
	(f)2	-	Power of Attorney of Daniel S. Tucker. (Designated in the Form 10-K for the year ended December 31, 2018, File No. 1-14174 as Exhibit 24(f)2.)
	(31) Section 302 Certifications
	Southern Company
*	(a)1	-	Certificate of Southern Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(a)2	-	Certificate of Southern Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Alabama Power
*	(b)1	-	Certificate of Alabama Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(b)2	-	Certificate of Alabama Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Georgia Power
*	(c)1	-	Certificate of Georgia Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(c)2	-	Certificate of Georgia Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Mississippi Power
*	(d)1	-	Certificate of Mississippi Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(d)2	-	Certificate of Mississippi Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Southern Power
*	(e)1	-	Certificate of Southern Power Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(e)2	-	Certificate of Southern Power Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Southern Company Gas
*	(f)1	-	Certificate of Southern Company Gas' Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(f)2	-	Certificate of Southern Company Gas' Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

231

	(32) Section 906 Certifications
	Southern Company
*	(a)	-	Certificate of Southern Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Alabama Power
*	(b)	-	Certificate of Alabama Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Georgia Power
*	(c)	-	Certificate of Georgia Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Mississippi Power
*	(d)	-	Certificate of Mississippi Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Southern Power
*	(e)	-	Certificate of Southern Power Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Southern Company Gas
*	(f)	-	Certificate of Southern Company Gas' Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	(101) Interactive Data Files
*	INS	-	XBRL Instance Document – The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
*	SCH	-	XBRL Taxonomy Extension Schema Document
*	CAL	-	XBRL Taxonomy Calculation Linkbase Document
*	DEF	-	XBRL Definition Linkbase Document
*	LAB	-	XBRL Taxonomy Label Linkbase Document
*	PRE	-	XBRL Taxonomy Presentation Linkbase Document

232

THE SOUTHERN COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	THE SOUTHERN COMPANY
By	Thomas A. Fanning
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Andrew W. Evans
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: July 30, 2019

233

ALABAMA POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	ALABAMA POWER COMPANY
By	Mark A. Crosswhite
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Philip C. Raymond
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: July 30, 2019

234

GEORGIA POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	GEORGIA POWER COMPANY
By	W. Paul Bowers
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	David P. Poroch
	Executive Vice President, Chief Financial Officer, Treasurer, and Comptroller
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: July 30, 2019

235

MISSISSIPPI POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	MISSISSIPPI POWER COMPANY
By	Anthony L. Wilson
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Moses H. Feagin
	Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: July 30, 2019

236

SOUTHERN POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	SOUTHERN POWER COMPANY
By	Mark S. Lantrip
	Chairman and Chief Executive Officer
	(Principal Executive Officer)
By	Elliott L. Spencer
	Senior Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: July 30, 2019

237

SOUTHERN COMPANY GAS

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	SOUTHERN COMPANY GAS
By	Kimberly S. Greene
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Daniel S. Tucker
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: July 30, 2019

238

EX-3.D

Exhibit 3(d)

MISSISSIPPI POWER COMPANY

BYLAWS

AMENDED: July 23, 2019

MISSISSIPPI POWER COMPANY

BYLAWS

ARTICLE I

Stockholders

SECTION 1.01. Annual Meeting.

The annual meeting of the shareholders of the Corporation for the election of directors and for the transaction of such other corporate business as may properly come before such meeting shall be held at the Corporation’s office at Gulfport, in the State of Mississippi, or at such other place within or without the State of Mississippi as the Chairman of the Board, the President or the Board of Directors may determine on the last Tuesday in June in each year; provided, however, that the Chairman of the Board, the President or the Board of Directors may fix an earlier day for such annual meeting of shareholders in any particular year; and provided further that, if the day fixed for such annual meeting of shareholders is a legal holiday, such meeting shall be held on the first day thereafter which is not a legal holiday. [79‑4‑7.01]

SECTION 1.02. Special Meetings.

Subject to the provisions of Article Fourth of the Corporation’s Articles of Incorporation, special meetings of the shareholders of the Corporation may be held at such time and at such place within or without the State of Mississippi as the Chairman of the Board, the President or the Board of Directors may determine. A special meeting may be called at any time by the Chairman of the Board, the President, the Board of Directors, the Executive Committee or shareholders holding one‑tenth of the then outstanding capital stock entitled to vote. [79‑4‑7.02]

SECTION 1.03. Notice of Meetings of Stockholders.

Written or printed notice stating the place, day and hour of the meeting and, in case of a special meeting, the purpose or purposes for which the meeting is called, shall be delivered by the Secretary or the other officer performing his duties, or the officer or persons calling the

meeting not less than ten nor more than fifty days before the meeting, either personally or by mail, to each shareholder of record entitled to vote. If mailed, such notice shall be deemed to be delivered when deposited in the United States mail addressed to the shareholder at his address as it appears on the stock transfer books of the Corporation, with postage prepaid. [79‑4‑7.05] Whenever any notice is required to be given to any shareholder, a waiver thereof in writing signed by the person or persons entitled to such notice, whether before or after the time stated therein, shall be equivalent to the giving of such notice. [79‑4‑7.06]

SECTION 1.04. Fixing Date for Determination of Stockholders of Record.

In order to determine the shareholders entitled to notice of or to vote at any meeting of shareholders or any adjournment thereof, or entitled to receive payment of any dividend, or in order to make a determination of shareholders for any other purpose, the Board of Directors may provide that the stock transfer books of the Corporation shall be closed for a stated period but not to exceed fifty (50) days. If the stock transfer books shall be closed for the purpose of determining shareholders entitled to notice of or to vote at a meeting of shareholders, such books shall be closed for at least ten (10) days immediately preceding such meeting. In lieu of closing the stock transfer books, the Board of Directors may fix, in advance, a record date for any such determination of shareholders, which shall not be more than fifty (50) days and, in case of a meeting of shareholders, not less than ten (10) days prior to the date on which the particular action requiring such determination of shareholders is to be taken. If the stock transfer books are not closed and no record date is fixed for the determination of shareholders entitled to notice of or to vote at a meeting of shareholders, or shareholders entitled to receive payment of a dividend, the date on which notice of the meeting is mailed or the date on which the resolution of the Board of Directors declaring such dividend is adopted shall be the record date for such determination of shareholders. When a determination of shareholders entitled to vote at any meeting of shareholders has been made as provided in this section, such determination shall apply to any adjournment thereof. [79‑4‑7.07 & 79‑4‑7.20(a)]

SECTION 1.05. Quorum.

Subject to the provisions of Article Fourth of the Corporation’s Articles of Incorporation, at all meetings of shareholders, the holders of a majority of the shares entitled to vote, represented in person or by proxy, shall constitute a quorum for the transaction of any business. If a quorum is present, the affirmative vote of the majority of the shares represented at the meeting and entitled to vote on the subject matter shall constitute the act of shareholders. [79‑4‑7.25]

SECTION 1.06. Voting Rights of Shareholders.

Each shareholder of record entitled to vote in accordance with the laws of the State of Mississippi, the Corporation’s Articles of Incorporation, or these Bylaws, shall at every meeting of shareholders be entitled to one vote in person or by proxy for each share of stock entitled to vote, but no proxy shall be valid after eleven months from the date of its execution, unless otherwise provided in the proxy. [79‑4‑7.21 & 79‑4‑7.22]

SECTION 1.07. Voting List ‑ Shareholder Examination.

The officer or agent having charge of the stock transfer books for shares of the Corporation shall make, at least ten (10) days before each meeting of shareholders, a complete list of the shareholders entitled to vote at such meeting or any adjournment thereof, arranged in alphabetical order, with the address of and the number of shares held by each, which list, for a period of ten (10) days prior to such meeting, shall be kept on file at the registered office of the Corporation and shall be subject to inspection by any shareholder at any time during usual business hours. Such list shall also be produced and kept open at the time and place of the meeting and shall be subject to the inspection of any shareholder during the whole time of the meeting. No shareholder shall be entitled to inspect any such list or the stock transfer books unless such inspection shall be made in good faith for a proper purpose. The original stock transfer books shall be prima facie evidence as to who are the shareholders entitled to examine such list or transfer books or to vote at any meeting of shareholders. [79‑4‑7.20(b)‑(d)]

Failure to comply with the requirements of this section shall not affect the validity of any action taken at such meeting. [79‑4‑7.20(e)]

SECTION 1.08. Consent in Lieu of Meeting.

Any corporate action either required or permitted by the Business Corporation Act of Mississippi, the Corporation’s Articles of Incorporation, or these Bylaws, to be taken at a meeting of the shareholders, may be taken without a meeting if a consent in writing, setting forth the action so taken, shall be signed by all of the shareholders entitled to vote with respect to the subject matter thereof. [79‑4‑7.04(a)]

ARTICLE II

Directors

SECTION 2.01. Management of Business.

The business and affairs of the Corporation shall be managed by the Board of Directors.

The provisions of this Article II shall be subject to Article Fourth of the Corporation’s Articles of Incorporation. [79‑4‑8.01(b)]

SECTION 2.02. Number and Qualification of Directors.

The number of directors shall be not less than three nor more than fifteen, the number to be fixed at the annual or any special meeting of the stockholders entitled to vote for the election of directors, but no decrease shall have the effect of shortening the term of any incumbent director. [79‑4‑8.03(a)‑(c)]

Directors need not be residents of Mississippi or shareholders of the Corporation. [79‑4‑8.02]

No person who is engaged or interested in a competing business either individually or as an employee or stockholder, shall serve as a director without the consent of a majority of interest of the stockholders. [79‑4‑8.31]

A person being a full‑time executive employee of the Corporation or its parent company or any affiliated company when first elected a director of the Corporation (hereinafter sometimes referred to as an “employee‑director”) shall not be eligible to serve as a director when he or she ceases to be an executive employee, whether by reason of resignation, retirement or other cause.

No director, other than an employee-director of the Corporation, shall serve for more than a total of 12 years in that capacity. Therefore, the Board will not nominate for re-election any non-employee director if the director shall complete his or her twelfth year of service as a member of the Board on or prior to the date of the annual meeting of shareholders at which the nomination would be presented. Additionally, a person not an employee-director shall not be eligible to serve as a director of the Corporation (1) for a newly elected annual term starting after his or her 70th birthday, (2) after permanent separation from the business or professional organization with which he or she was primarily associated when first elected a director, (3) after any other material change in his or her primary occupation or executive position from that which he or she pursued or held when first elected a director, or (4) after moving his or her principal residence outside the service area in which he or she was a resident when first elected a director, whichever event first occurs. In special circumstances, the application to an individual of any provision of this section may be waived by the Board of Directors. Any such waiver shall only be effective on a year-to-year basis.

A person not an employee-director must tender a resignation from the Board of Directors when a change occurs in the director’s eligibility to serve as a director by reason of the foregoing provisions other than reaching his or her 70th birthday. In such case, the Board of Directors has the discretion of accepting the resignation or requesting that the director continue to serve on the Board for the remainder of his or her current term.

Any employee‑director who is not eligible to serve as a director by reason of the foregoing provisions shall be eligible to serve as an advisory director until he or she shall have

reached his or her 70th birthday, if elected or re‑elected by the Board of Directors, upon the recommendation of the Chief Executive Officer of the Corporation. The term of office of each advisory director shall terminate on the earlier of the date when he or she ceases to be eligible for such position or, subject to reappointment, the date of the first meeting of the Board of Directors after the annual meeting of stockholders next following his appointment. Any person eligible for election as an advisory director must be one whose services as such will be, in the opinion of the Board of Directors, of value to the Corporation. An advisory director shall be entitled to notice of, to attend, and to advise but not to vote at meetings of the Board of Directors and of any committees thereof to which he shall be appointed. An advisory director shall not be counted in determining the existence of a quorum, and for his or her services may be paid, in the discretion of the Board of Directors, compensation and reimbursement of expenses on the same basis as if he or she were a director.

SECTION 2.03. Election and Term.

The directors shall be elected at the annual meeting of shareholders, and each director shall be elected to hold office until his successor shall be elected and qualified, or until his earlier resignation or removal. The Board of Directors, as soon as may be convenient after the election of directors in each year, may appoint one of their number Chairman of the Board. [79‑4‑8.03(d)]

SECTION 2.04. Vacancies and Newly Created Directorships.

In case of any vacancies in the Board of Directors through death, resignation, disqualification or any other cause, including a vacancy resulting from an increase in the number of directors, the Board of Directors may fill the vacancy by the affirmative vote of a majority of the remaining directors, which shall constitute a quorum for such purpose, and the director or directors so chosen shall hold office until the next annual election by shareholders and until their successor or successors shall be elected and qualified. [79‑4‑8.10]

SECTION 2.05. Removal.

At a meeting called expressly for that purpose, any and all of the directors may at any time be removed, with or without cause, by a vote of the holders of a majority of the shares then entitled to vote at an election of directors. If less than the entire Board is to be removed, no one of the directors may be removed if the votes cast against his removal would be sufficient to elect him if then cumulatively voted at an election of the entire Board of Directors. [79‑4‑8.08]

SECTION 2.06. Quorum of Directors.

At all meetings of the Board of Directors, one‑half of the number of directors then in office or, if there shall be an odd number of directors, then a majority thereof, shall constitute a quorum for the transaction of business. The act of the majority of the directors present at a meeting at which a quorum is present shall be the act of the Board of Directors. [79‑4‑8.24]

SECTION 2.07. Annual Meeting.

The newly elected Board of Directors shall meet as soon as practicable after the annual meeting of shareholders, within or without the State of Mississippi, and no notice of such meeting shall be necessary. [79‑4‑8.20]

SECTION 2.08. Regular Meetings.

Regular meetings of the Board may be held at such time and place, within or without the State of Mississippi, as shall from time to time be fixed by the Chairman of the Board, the President or the Board of Directors, and no notice of such meeting shall be necessary. [79‑4‑8.20]

SECTION 2.09. Special Meetings.

Special meetings may be called at any time by the Chairman of the Board, the President, any Vice President, the Treasurer or the Secretary or by the Board of Directors. Special meetings shall be held at such place, within or without the State of Mississippi, as shall be fixed by the person or persons calling the meeting and stated in the notice or waiver of notice of the meeting. [79‑4‑8.20]

Notice of a special meeting shall be given by the Secretary, or such other officer performing his duties, to each director at least two days prior to such meeting, if delivered by express mail or courier, or one day’s notice if given by telegram or telecopy or personal communication by telephone or otherwise, or not later than the fourth day prior to the meeting if given by regular, postage‑prepaid U.S. mail. Attendance of a director at a special meeting shall constitute a waiver of notice of such meeting, except when a director attends a meeting for the express purpose of objecting to the transaction of any business because the meeting is not lawfully called or convened. Notice by mail or telegraph to the usual business or residence address of the director shall be sufficient. The business to be transacted at or the purpose of a special meeting of the Board of Directors need not be stated in such notice or waiver of notice and any and all business may be transacted at a special meeting of the Board of Directors. [79‑4‑8.22 & 79‑4‑8.23]

SECTION 2.10. Action Without a Meeting.

Any corporate action either required or permitted by the Business Corporation Act of Mississippi, the Corporation’s Articles of Incorporation, or these Bylaws, to be taken at a meeting of the Board of Directors may be taken without a meeting if a consent in writing, setting forth the action so taken, shall be signed by all of the directors entitled to vote with respect to the subject matter thereof. Members of the Board of Directors or any committee thereof may participate in a meeting of the Board or any committee thereof by means of conference telephone or similar communications equipment by means of which all persons participating in the meeting can hear each other, and such participation in a meeting shall constitute presence in person at the meeting. [79‑4‑8.21]

SECTION 2.11. Compensation.

Directors shall be entitled to a fee for attendance at each regular or special meeting of the Board of Directors, or a committee of the Board, and in otherwise performing duties as such directors, and/or to a monthly or annual fee or salary, provided that no fees or salaries shall be

paid to those directors who are officers or employees, other than retired employees, who are on a fixed basis of compensation from the Company or any subsidiary or affiliated company and who have duties and responsibilities to such companies other than those arising from the office of director. Directors shall be reimbursed for actual expenses incurred in attending meetings of the Board of Directors or any committee thereof and in otherwise performing duties as such directors or in lieu thereof to an allowance for expenses. The amount of fee or salary paid to directors and expense allowance, if any, shall be fixed by the Board of Directors. [79‑4‑8.11]

SECTION 2.12. Executive and Other Committees.

The Board of Directors may, by resolution or resolutions passed by a majority of the whole Board, designate an Executive Committee and one or more other committees, including without limitation Audit and Compensation Committees, each consisting of three or more directors, and each of which committees may act by a majority of its members. Such Executive Committee shall have and may exercise all the powers and authority of the Board of Directors in the management of the business and affairs of the Company when the Board is not meeting; and each other committee shall have such powers of the Board and otherwise as are provided in the resolution establishing such committee. Provided, however, notwithstanding anything to the contrary herein, the Executive Committee and all other committees established by the Board shall have no power or authority to take any action specifically prohibited under the Mississippi Business Corporation Act, Section 79‑4‑8.25(e), or any successor statute. Unless otherwise specifically permitted by the Board, the rules promulgated by these Bylaws with respect to meetings of directors, notice, quorums, voting and other procedures at such meetings shall be applicable to meetings of committees established by the Board. [79‑4‑8.25]

SECTION 2.13. Interest of Director in Corporate Act.

A director of this Corporation shall not be disqualified by his office from dealing or contracting with the Corporation, either as vendor, purchaser or otherwise, nor shall any transaction or contract of this Corporation be void or voidable by reason of the fact that any

director or any firm of which any director is a member or any corporation of which any director is a shareholder or director is in any way interested in such transaction or contract, provided that such transaction or contract is or shall be authorized, ratified or approved either (1) by vote of a majority or a quorum of the Board of Directors or the Executive Committee, without counting in such majority or quorum any directors so interested or being a member of a firm so interested or a shareholder or director of a corporation so interested, or (2) by vote at a stockholders’ meeting of the holders of a majority of all the outstanding shares of the stock of the Corporation entitled to vote or by a writing or writings signed by a majority of such holders; nor shall any director be liable to account to the Corporation for any profit realized by him from or through any transaction or contract of this Corporation authorized, ratified or approved as aforesaid, by reason of the fact that he or any firm of which he is a member or any corporation of which he is a shareholder or director was interested in such transaction or contract. Nothing herein contained shall create any liability in the events above described or prevent the authorization, ratification or approval of such contracts or transactions in any other manner provided by law.

ARTICLE III

Officers

SECTION 3.01. Number.

The officers of the Corporation shall be chosen by the Board of Directors. The officers shall be a President, a Secretary and a Treasurer, and such number of Vice Presidents, Assistant Secretaries and Assistant Treasurers, and such other officers, if any, as the Board of Directors may from time to time determine. The Board of Directors may from time to time, but shall not be required to, establish the office of Chairman of the Board and may, but shall not be required to, designate the holder of such office, if established, as Chief Executive Officer of the Corporation. The Board of Directors may choose such other agents as it shall deem

necessary. Any number of offices may be held by the same person, except the offices of President and Secretary. [79‑4‑8.40]

SECTION 3.02. Terms of Office.

Each officer shall hold his office until the next election of officers and until his successor is chosen and qualified or until his earlier resignation or removal. Any officer may resign at any time upon written notice to the Corporation. Vacancies in any office shall be filled by the Board of Directors.

SECTION 3.03. Removal of Officers.

Any officer or agent may be removed by the Board of Directors whenever in its judgment the best interest of the Corporation will be served thereby, but such removal shall be without prejudice to the contract rights, if any, of the person so removed. Election or appointment of an officer or agent shall not of itself create contract rights. [79‑4‑8.43(b)]

SECTION 3.04. Authority.

The officers of the Corporation shall have such duties as usually pertain to their offices, except as modified by the Board of Directors and shall also have such powers and duties as may from time to time be conferred upon them by the Board of Directors. Notwithstanding the provisions of Section 3.01 hereof, in the event of the absence or inability of the President to act, the powers and duties of the President shall, subject to the control of the Board of Directors, devolve successively upon such other persons as shall have been designated in a resolution adopted by the Board of Directors, and in accordance with the order of succession set forth therein. [79‑4‑8.41]

ARTICLE IV

Indemnification of Directors and Officers

SECTION 4.01. Indemnification and Related Matters.

To the fullest extent permitted by law, the Company shall indemnify each person made, or threatened to be made, a party to any threatened, pending, or completed claim, action, suit or proceeding, whether civil or criminal, administrative or investigative, and whether by or in the right of the Company or otherwise, by reason of the fact that such person, or such person’s testator or intestate, is or was a director, officer or was an employee of the Company holding one or more management positions through and inclusive of department managers (but not positions below the level of department managers) (such positions being hereinafter referred to as “Management Positions”) or is or was serving at the request of the Company as a director, officer, employee, agent or trustee of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, in any capacity at the request of the Company, against all loss and expense actually or reasonably incurred by him including, without limiting the generality of the foregoing, judgments, fines, penalties, liabilities, sanctions, and amounts paid in settlement and attorney’s fees and disbursements actually and necessarily incurred by him in defense of such action or proceeding, or any appeal therefrom. The indemnification provided by this Section shall inure to the benefit of the heirs, executors and administrators of such person.

In any case in which a director, officer of the Company or employee of the Company holding one or more Management Positions requests indemnification with respect to the defense of any such claim, action or suit or proceedings, the Company may advance expenses (including attorney’s fees) incurred by such person prior to the final disposition of such claim, action, suit or proceeding, as authorized by the Board of Directors in the specific case, upon receipt of a written undertaking by or on behalf of such person to repay amounts advanced if it shall ultimately be determined that such person was not entitled to be indemnified by the

Company under this Section or otherwise; provided, however, that the advancement of such expenses shall not be deemed to be indemnification unless and until it shall ultimately be determined that such person is entitled to be indemnified by the Company. Such a person claiming indemnification shall be entitled to indemnification upon a determination that no judgment or other final adjudication adverse to such person has established that such person’s acts were committed in bad faith or were the result of active and deliberate dishonesty and were material to the cause of action so adjudicated, or such person personally obtained an economic benefit including a financial profit or other advantage to which such person was not legally entitled.

Without limiting the generality of the foregoing provision, no former, present or future director or officer of the Company or employee of the Company holding one or more management positions, or his heirs, executors or administrators, shall be liable for any undertaking entered into by the Company or its subsidiaries or affiliates as required by the Securities and Exchange Commission pursuant to any rule or regulation of the Securities and Exchange Commission now or hereafter in effect or orders issued pursuant to the Public Utility Holding Company Act of 1935, the FederalPower Act, or any undertaking entered into by the Company due to environmental requirements including all legally enforceable environmental compliance obligations imposed by federal, state or local statute, regulation, permit, judicial or administrative decree, order and judgment or other similar means, or any undertaking entered into by the Company pursuant to any approved Company compliance plan or any federal or state or municipal ordinance which directly or indirectly regulates the Company, or its parent by reason of their being holding or investment companies, public utility companies, public utility holding companies or subsidiaries of public utility holding companies.

The foregoing rights shall not be exclusive of any other rights to which any such director, officer or employee may otherwise be entitled and shall be available whether or not the

director, officer or employee continues to be a director, officer or employee at the time of incurring any such expenses and liabilities.

If any word, clause or provision of the Bylaws or any indemnification made under this Section 4.01 shall for any reason be determined to be invalid, the remaining provisions of the Bylaws shall not otherwise be affected thereby but shall remain in full force and effect. The masculine pronoun, as used in the Bylaws, means the masculine and feminine wherever applicable. [79-4-8.51, 79-4-8.52, 79-4-8.53, 79-4-8.55 & 79-4-8.56]

SECTION 4.02. Liability Insurance.

The Company may purchase and maintain insurance on behalf of any person described in Section 4.01 against any liability or expense (including attorney’s fees) which may be asserted against such person whether or not the Company would have the power to indemnify such person against such liability or expense under this Article IV or otherwise. [79-4-8.57]

ARTICLE V

Capital Stock

SECTION 5.01. Stock Certificates.

The shares of the Corporation shall be represented by a certificate or shall be uncertificated and shall be entered in the books of the Corporation and registered as they are issued. The certificates shall be signed by the President or a Vice President of the Corporation, and by the Secretary or an Assistant Secretary of the Corporation, one of which may be facsimile signature, and may be sealed with the seal of the Corporation or a facsimile thereof. The signatures of the President or Vice President and the Secretary or Assistant Secretary upon a certificate may both be facsimiles if the certificate is countersigned by a transfer agent or registered by a registrar, other than the Corporation itself or an employee of the Corporation. In case any officer who has signed or whose facsimile signature has been placed upon a

certificate shall have ceased to be such officer before such certificate is issued, it may be issued by the Corporation with the same effect as if he were such officer at the date of issue.

The certificates of stock of the Corporation shall be numbered, shall exhibit the name of the registered holder and shall certify the number of shares owned by him. Within a reasonable time after the issue or transfer of shares without certificates, the Corporation shall send the shareholder a written statement of the information required on the certificates pursuant to the Mississippi Business Corporation Act. [79‑4‑6.25]

SECTION 5.02. Registered Holders.

Prior to due presentment for registration of transfer of any security of the Corporation in registered form, the Corporation shall treat the registered owner as the person exclusively entitled to vote, to receive notifications and to otherwise exercise all the rights and powers of an owner, and shall not be bound to recognize any equitable or other claim to, or interest in, any security, whether or not the Corporation shall have notice thereof, except as otherwise provided by the laws of the State of Mississippi.

SECTION 5.03. Transfers.

The stock of the Corporation shall be transferable or assignable on the books of the Corporation by the holders in person or by attorney on the surrender of the certificates therefor duly endorsed or upon receipt of proper transfer instructions from the registered owner of uncertificated shares or in any other manner prescribed by the laws of the State of Mississippi.

SECTION 5.04. Replacement Certificates.

The Corporation may issue a new certificate or uncertificated shares of stock in place of any certificates theretofore issued by it, alleged to have been lost or destroyed, provided the person seeking the issuance of the new certificate or uncertificated shares of stock shall be the owner or satisfy the Corporation he is the owner of the stock certificate alleged to have been lost or destroyed, and the directors shall require the owner of the lost or destroyed certificate, or his legal representatives, to give the Corporation a bond sufficient to indemnify the Corporation

against any claim that may be made against it on account of the alleged loss or destruction of any such certificate or the issuance of such new certificate or uncertificated shares of stock. The issuance of a new certificate or uncertificated shares of stock, as herein above provided, shall not relieve the Corporation or the directors from corporate or personal liability in damages to any person to whom the original certificate has been or shall be transferred for value without notice of the issuance of the new certificate or uncertificated shares of stock.

ARTICLE VI

Miscellaneous

SECTION 6.01. Seal.

The corporate seal of the Corporation shall be in such form as the Board of Directors shall prescribe.

SECTION 6.02. Checks.

The Board of Directors is authorized to select such depositories as they shall deem proper for the funds of the Corporation. All checks and drafts against such deposited funds shall be signed by such officers or such other persons as may be specified by the Board of Directors.

SECTION 6.03. Loans.

No loans shall be made by the Corporation to its officers or directors, except in the amounts and under the same terms and conditions as available to all regular employees of the Corporation, and no loans shall be made by the Corporation secured by its shares.

SECTION 6.04. Amendment of Bylaws.

These Bylaws may be amended or repealed and new Bylaws adopted by the Board of Directors or by vote of the holders of the shares at the time entitled to vote in the election of any director, except that any Bylaw adopted by such holders shall not be amended or repealed by the Board of Directors. [79‑4‑10.20]

SECTION 6.05. Section Headings and References.

The headings of the Articles and Sections of these Bylaws and the bracketed references to the Mississippi Business Corporation Act have been inserted for convenience of reference only and shall not be deemed to be a part of these Bylaws.

EX-3.E

Exhibit 3(e)

AMENDED AND RESTATED
BYLAWS
OF SOUTHERN COMPANY GAS

ARTICLE I
OFFICES

Section 1.The registered office shall be in the City of Atlanta, County of Fulton, State of Georgia.

Section 2.The corporation may also have offices at such other places both within and without the State of Georgia as the board of directors may from time to time determine or the business of the corporation may require.

ARTICLE II
MEETINGS OF SHAREHOLDERS

Section 1.All meetings of the shareholders for the election of directors shall be held at such place as may be fixed from time to time by the board of directors, or at such other place either within or without the State of Georgia as shall be designated from time to time by the board of directors and stated in the notice of the meeting. Meetings of shareholders for any other purpose may be held at such time and place, within or without the State of Georgia, as shall be stated in the notice of the meeting or in a duly executed waiver of notice thereof.

Section 2.Annual meetings of shareholders shall be held at such date and time as shall be designated from time to time by the board of directors and stated in the notice of the meeting, at which they shall elect by a plurality vote a board of directors, and transact such other business as may properly be brought before the meeting.

Section 3.Written notice of the annual meeting stating the place, date and hour of the meeting shall be given to each shareholder entitled to vote at such meeting not less than 10 nor more than 60 days before the date of the meeting.

Section 4.The officer who has charge of the stock ledger of the corporation shall prepare and make, at least ten days before every meeting of shareholders, a complete list of the shareholders entitled to vote at the meeting, arranged in alphabetical order, and showing the address of each shareholder and the number of shares registered in the name of each shareholder. Such list shall be open to the examination of any shareholder, for any purpose germane to the meeting, during ordinary business hours, for a period of at least 10 days prior to the meeting, either at a place within the city where the meeting is to be held, which place shall be specified in the notice of the meeting, or, if not so specified, at the place where the meeting is to be held. The list shall also be produced and kept at the time and place of the meeting during the whole time thereof, and may be inspected by any shareholder who is present.

Section 5.Special meetings of the shareholders, for any purpose or purposes, unless otherwise prescribed by statute or by the articles of incorporation, may be called by the president

and shall be called by the president or secretary at the request in writing of a majority of the board of directors, or at the request in writing of shareholders owning a majority in amount of the entire capital stock of the corporation issued and outstanding and entitled to vote. Such request shall state the purpose or purposes of the proposed meeting.

Section 6.Written notice of a special meeting stating the place, date and hour of the meeting and the purpose or purposes for which the meeting is called, shall be given not less than 10 nor more than 60 days before the date of the meeting, to each shareholder entitled to vote at such meeting.

Section 7.Business transacted at any special meeting of shareholders shall be limited to the purposes stated in the notice.

Section 8.The holders of a majority of the stock issued and outstanding and entitled to vote thereat, present in person or represented by proxy, shall constitute a quorum at all meetings of the shareholders for the transaction of business except as otherwise provided by statute or by the articles of incorporation. If, however, such quorum shall not be present or represented at any meeting of the shareholders, the shareholders entitled to vote thereat, present in person or represented by proxy, shall have power to adjourn the meeting from time to time, without notice other than announcement at the meeting, until a quorum shall be present or represented. At such adjourned meeting at which a quorum shall be present or represented any business may be transacted that might have been transacted at the meeting as originally notified. If the adjournment is for more than thirty days, or if after the adjournment a new record date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given to each shareholder of record entitled to vote at the meeting.

Section 9.When a quorum is present at any meeting, the vote of the holders of a majority of the stock having voting power present in person or represented by proxy shall decide any question brought before such meeting, unless the question is one upon which by express provision of the statutes or of the articles of incorporation a different vote is required, in which case such express provision shall govern and control the decision of such question.

Section 10.Unless otherwise provided in the articles of incorporation or in an agreement among shareholders as permitted under the Georgia Business Corporation Code (the “GBCC”), each shareholder shall at every meeting of the shareholders be entitled to one vote in person or by proxy for each share of the capital stock having voting power held by such shareholder, but no proxy shall be voted on after three years from its date, unless the proxy provides for a longer period.

Section 11.Unless otherwise provided in the articles of incorporation, any action required to be taken at any annual or special meeting of shareholders of the corporation, or any action that may be taken at any annual or special meeting of such shareholders, may be taken without a meeting, without prior notice and without a vote, if a consent in writing, setting forth the action so taken, shall be signed by the holders of outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted. Prompt notice of the taking

2

Southern Company Gas – Amended and Restated Bylaws – October 23, 2018

of the corporate action without a meeting by less than unanimous written consent shall be given to those shareholders who have not consented in writing.

ARTICLE III
DIRECTORS

Section 1.The number of directors which shall constitute the whole board shall be not less than one nor more than twenty. Within the limits above specified, the number of directors shall be determined by resolution of the board of directors or by the shareholders at the annual meeting. The directors shall be elected at the annual meeting of the shareholders, except as provided in Section 2 of this Article, and each director elected shall hold office until his or her successor is elected and qualified. Directors need not be shareholders.

Section 2.A director shall not be eligible for election or re-election as a director of the corporation (1) after his or her 75^th birthday; (2) after permanent separation from the business or professional organization with which he or she was primarily associated when elected a director; or (3) after other material change in his or her primary occupation or executive position from that which he or she pursued or held when elected a director, whichever event first occurs. The application to an individual of any provision of this Section 2 may be waived by the board of directors. Any such waiver shall only be effective on a year to year basis.

Section 3.Vacancies and newly created directorships resulting from any increase in the authorized number of directors may be filled by a majority of the directors then in office, though less than a quorum, or by a sole remaining director, and the directors so chosen shall hold office until the next annual election and until their successors are duly elected and shall qualify, unless sooner displaced. If there are no directors in office, then an election of directors may be held in the manner provided by statute.

Section 4.The business of the corporation shall be managed by or under the direction of its board of directors, which may exercise all such powers of the corporation and do all such lawful acts and things as are not by statute or by the articles of incorporation or by these bylaws directed or required to be exercised or done by the shareholders.

MEETINGS OF THE BOARD OF DIRECTORS

Section 5.The board of directors of the corporation may hold meetings, both regular and special, either within or without the State of Georgia.

Section 6.The first meeting of each newly elected board of directors shall be held at such time and place as shall be fixed by the vote of the shareholders at the annual meeting and no notice of such meeting shall be necessary to the newly elected directors in order legally to constitute the meeting, provided a quorum shall be present. In the event of the failure of the shareholders to fix the time or place of such first meeting of the newly elected board of directors, or in the event such meeting is not held at the time and place so fixed by the shareholders, the meeting may be held at such time and place as shall be specified in a notice given as hereinafter

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provided for special meetings of the board of directors, or as shall be specified in a written waiver signed by all of the directors.

Section 7.Regular meetings of the board of directors may be held without notice at such time and at such place as shall from time to time be determined by the board.

Section 8.Special meetings of the board may be called by the president on notice to each director, either personally or by mail or by telephone, fax or email; special meetings shall be called by the president or secretary in like manner and on like notice on the written request of two directors unless the board consists of only one director; in which case special meetings shall be called by the president or secretary in like manner and on like notice on the written request of the sole director.

Section 9.At all meetings of the board, a majority of the directors shall constitute a quorum for the transaction of business and the act of a majority of the directors present at any meeting at which there is a quorum shall be the act of the board of directors, except as may be otherwise specifically provided by statute or by the articles of incorporation. If a quorum shall not be present at any meeting of the board of directors, the directors present thereat may adjourn the meeting from time to time, without notice other than announcement at the meeting, until a quorum shall be present.

Section 10.Unless otherwise restricted by the articles of incorporation or these bylaws, any action required or permitted to be taken at any meeting of the board of directors or of any committee thereof may be taken without a meeting, if all members of the board or committee, as the case may be, consent thereto in writing, and the writing or writings are filed with the minutes of proceedings of the board or committee.

Section 11.Unless otherwise restricted by the articles of incorporation or these bylaws, members of the board of directors, or any committee designated by the board of directors, may participate in a meeting of the board of directors, or any committee, by means of conference telephone or similar communications equipment by means of which all persons participating in the meeting can hear each other, and such participation in a meeting shall constitute presence in person at the meeting.

COMMITTEES OF DIRECTORS

Section 12.The board of directors may, by resolution passed by a majority of the whole board, designate one or more committees, each committee to consist of one or more of the directors of the corporation. The board may designate one or more directors as alternate members of any committee, who may replace any absent or disqualified member at any meeting of the committee.

Any such committee, to the extent provided in the resolution of the board of directors, shall have and may exercise all the powers and authority of the board of directors in the management of the business and affairs of the corporation, and may authorize the seal of the corporation to be affixed to all papers that may require it; but no such committee shall have the power or authority to (1) approve or propose to shareholders action that the GBCC requires to be

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approved by such shareholders; (2) fill vacancies on the board of directors or on any of its committees; (3) amend articles of incorporation pursuant to Section 1002 of the GBCC except that a committee may, to the extent authorized in a resolution or resolutions adopted by the board of directors, amend the articles of incorporation to fix the designations, preferences, limitations, and relative rights of shares pursuant to Section 602 of the GBCC or to increase or decrease the number of shares contained in a series of shares established in accordance with Section 602 of the GBCC but not below the number of such shares then issued; (4) adopt, amend, or repeal bylaws; or (5) approve a plan of merger not requiring shareholder approval. Such committee or committees shall have such name or names as may be determined from time to time by resolution adopted by the board of directors.

Section 13.Unless otherwise specifically permitted by the board of directors, the provisions of these bylaws that govern meetings, actions without meetings, notice and waiver of notice and quorum and voting requirements of the board of directors, shall apply to meetings of committees and their members as well.

COMPENSATION OF DIRECTORS

Section 14.Unless otherwise restricted by the articles of incorporation or these bylaws, the board of directors shall have the authority to fix the compensation of directors. The directors may be paid their expenses, if any, of attendance at each meeting of the board of directors and may be paid a fixed sum for attendance at each meeting of the board of directors or a stated salary as director. No such payment shall preclude any director from serving the corporation in any other capacity and receiving compensation therefor. Members of special or standing committees may be allowed like compensation for attending committee meetings.

REMOVAL OF DIRECTORS

Section 15.Unless otherwise restricted by the articles of incorporation or by law, any director of the entire board of directors may be removed, with or without cause, by the holders of a majority of shares entitled to vote at an election of directors.

ARTICLE IV
NOTICES

Section 1.Whenever, under the provisions of the GBCC or of the articles of incorporation or of these bylaws, notice is required to be given to any director or shareholder, it shall not be construed to mean personal notice, but such notice may be given in writing, by mail, addressed to such director or shareholder, at his or her address as it appears on the records of the corporation, with postage thereon prepaid, and such notice shall be deemed to be given at the time when the same shall be deposited in the United States mail. Notice to directors may also be given by facsimile or email.

Section 2.Whenever any notice is required to be given under the provisions of the statutes or of the articles of incorporation or of these bylaws, a waiver thereof in writing, signed

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by the person or persons entitled to said notice, whether before or after the time stated therein, shall be deemed equivalent thereto.

ARTICLE V
OFFICERS

Section 1.The officers of the corporation shall be chosen by the board of directors and shall be at a minimum a president, secretary and treasurer. The board of directors may also choose one or more senior or executive vice-presidents, assistant secretaries and assistant treasurers. Any number of offices may be held by the same person, unless the articles of incorporation or these bylaws otherwise provides.

Section 2.The board of directors at its first meeting after each annual meeting of shareholders shall choose a president, one or more senior or executive vice-presidents, a secretary and a treasurer.

Section 3.The board of directors may appoint such other officers and agents as it shall deem necessary who shall hold their offices for such terms and shall exercise such powers and perform such duties as shall be determined from time to time by the board.

Section 4.The salaries of all officers and agents of the corporation shall be fixed by the board of directors or a committee thereof. The board of directors may authorize any officer, upon whom the power of appointing other officers may have been conferred (pursuant to this Article V, Section 15 below), to fix the compensation of such other officers.

Section 5.The officers of the corporation shall hold office until their successors are chosen and qualified. Any officer elected or appointed by the board of directors may be removed at any time by the affirmative vote of a majority of the board of directors. Any vacancy occurring in any office of the corporation shall be filled by the board of directors.

Section 6.Each officer of the corporation shall have the authority to execute and deliver any and all applications and filings as are necessary to be filed with federal, state and local regulatory agencies on behalf of the corporation.

THE PRESIDENT

Section 7.The president shall be the chief executive officer of the corporation, shall preside at all meetings of the shareholders and the board of directors, shall have general and active management of the business of the corporation and shall see that all orders and resolutions of the board of directors are carried into effect.

Section 8.The president shall execute bonds, mortgages and other contracts requiring a seal, under the seal of the corporation, except where required or permitted by law to be otherwise signed and executed and except where the signing and execution thereof shall be expressly delegated to some other officer or agent of the corporation.

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THE VICE-PRESIDENTS

Section 9.The senior or executive vice-presidents shall be senior in authority among the vice-presidents. In the absence of the president or in the event of his or her inability or refusal to act, the board of directors shall designate which of the senior or executive vice-presidents shall perform the duties of the president, and when so acting, shall have all the powers of, and be subject to, all the restrictions upon the president. The vice-presidents shall perform such other duties and have such other powers as the board of directors may from time to time prescribe.

THE SECRETARY AND ASSISTANT SECRETARY

Section 10.The secretary shall attend all meetings of the board of directors and all meetings of the shareholders and record all the proceedings of the meetings of the corporation and of the board of directors in a book to be kept for that purpose and shall perform like duties for the standing committees when required. The secretary shall give, or cause to be given, notice of all meetings of the shareholders and special meetings of the board of directors, and shall perform such other duties as may be prescribed by the board of directors or president, under whose supervision the secretary shall be. The secretary shall have custody of the corporate seal of the corporation and the secretary, or an assistant secretary, shall have authority to affix the same to any instrument requiring it and when so affixed, it may be attested by his or her signature or by the signature of such assistant secretary. The board of directors may give general authority to any other officer to affix the seal of the corporation and to attest the affixing by his or her signature.

Section 11.The assistant secretary, or if there be more than one, the assistant secretaries in the order determined by the board of directors (or if there be no such determination, then in the order of their election) shall, in the absence of the secretary or in the event of his or her inability or refusal to act, perform the duties and exercise the powers of the secretary and shall perform such other duties and have such other powers as the board of directors may from time to time prescribe.

THE TREASURER AND ASSISTANT TREASURERS

Section 12.The treasurer shall have the custody of the corporate funds and securities and shall keep full and accurate accounts of receipts and disbursements in books belonging to the corporation and shall deposit all moneys and other valuable effects in the name and to the credit of the corporation in such depositories as may be designated by the board of directors.

Section 13.The treasurer shall disburse the funds of the corporation as may be ordered by the board of directors, taking proper vouchers for such disbursements, and shall render to the president and the board of directors, at its regular meetings, or when the board of directors so requires, an account of all his or her transactions as treasurer and of the financial condition of the corporation.

Section 14.The assistant treasurer, or if there shall be more than one, the assistant treasurers in the order determined by the board of directors (or if there be no such determination,

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then in the order of their election) shall, in the absence of the treasurer or in the event of his or her inability or refusal to act, perform the duties and exercise the powers of the treasurer and shall perform such other duties and have such other powers as the board of directors may from time to time prescribe.

OTHER OFFICERS

Section 15.The board of directors may from time to time authorize any officer to appoint other officers of the corporation and its major subsidiaries, to prescribe the powers, term, duties and salary, if any, of such appointed officers, and to remove any officers thus appointed, consistent with the applicable bylaws and the resolutions of the board of directors authorizing such appointment and removal.

ARTICLE VI
CERTIFICATES FOR SHARES

Section 1.The shares of the corporation shall be represented by a certificate or shall be uncertificated. Certificates shall be signed by, or in the name of the corporation by, the chairman or vice-chairman of the board of directors, or the president or a vice-president and the treasurer or an assistant treasurer, or the secretary or an assistant secretary of the corporation.

Within a reasonable time after the issuance or transfer of uncertificated stock, the corporation shall send to the registered owner thereof a written notice containing the information required on certificates by Sections 625 and, if applicable, 627 of the GBCC.

Section 2.Any of or all the signatures on a certificate may be by facsimile. In case any officer, transfer agent or registrar who has signed or whose facsimile signature has been placed upon a certificate shall have ceased to be such officer, transfer agent or registrar before such certificate is issued, it may be issued by the corporation with the same effect as if he or she were such officer, transfer agent or registrar at the date of issue.

LOST CERTIFICATES

Section 3.The board of directors may direct a new certificate or certificates or uncertificated shares to be issued in place of any certificate or certificates theretofore issued by the corporation alleged to have been lost, stolen or destroyed, upon the making of an affidavit of that fact by the person claiming the certificate of stock to be lost, stolen or destroyed. When authorizing such issue of a new certificate or certificates or uncertificated shares, the board of directors may, in its discretion and as a condition precedent to the issuance thereof, require the owner of such lost, stolen or destroyed certificate or certificates, or his or her legal representative, to advertise the same in such manner as it shall require and/or to give the corporation a bond in such sum as it may direct as indemnity against any claim that may be made against the corporation with respect to the certificate alleged to have been lost, stolen or destroyed.

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TRANSFER OF STOCK

Section 4.Upon surrender to the corporation or the transfer agent of the corporation of a certificate for shares duly endorsed or accompanied by proper evidence of succession, assignation or authority to transfer, it shall be the duty of the corporation to issue a new certificate to the person entitled thereto, cancel the old certificate and record the transaction upon its books. Upon receipt of proper transfer instructions from the registered owner of uncertificated shares such uncertificated shares shall be cancelled and issuance of new equivalent uncertificated shares or certificated shares shall be made to the person entitled thereto and the transaction shall be recorded upon the books of the corporation.

FIXING RECORD DATE

Section 5.In order that the corporation may determine the shareholders entitled to notice of or to vote at any meeting of shareholders or any adjournment thereof, or to express consent to corporate action in writing without a meeting, or entitled to receive payment of any dividend or other distribution or allotment of any rights, or entitled to exercise any rights in respect of any change, conversion or exchange of stock or for the purpose of any other lawful action, the board of directors may fix, in advance, a record date, which shall not be more than 70 days before the date of such meeting or any other such action. A determination of shareholders of record entitled to notice of or to vote at a meeting of shareholders shall apply to any adjournment of the meeting; provided, however, that the board of directors may fix a new record date for the adjourned meeting, which it must do if the meeting is adjourned to a date more than 120 days after the date fixed for the original meeting.

REGISTERED SHAREHOLDERS

Section 6.The corporation shall be entitled to recognize the exclusive right of a person registered on its books as the owner of shares to receive dividends, and to vote as such owner, and to hold liable for calls and assessments a person registered on its books as the owner of shares, and shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other person, whether or not it shall have express or other notice thereof, except as otherwise provided by the laws of Georgia.

ARTICLE VII
INDEMNIFICATION

The indemnification authorized in the articles of incorporation shall be subject to the following provisions and procedures:

Section 1.In the case of actions brought by or in the right of the corporation, a director’s right to indemnification as authorized in the articles of incorporation shall be determined:

(a)if there are two or more directors not at the time parties to the proceeding (such directors, “Disinterested Directors”), by the board of directors by a majority vote of all the

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Disinterested Directors (a majority of whom shall for such purpose constitute a quorum), or by a majority of the members of a committee of two or more Disinterested Directors appointed by such a vote;

(b)by special legal counsel:

(i)selected in the manner prescribed in paragraph (a) of this Article VII, Section 1; or

(ii)if there are fewer than two Disinterested Directors, selected by the board of directors (in which directors who do not qualify as Disinterested Directors may participate); or

(c)by the shareholders, but shares owned by or voted under the control of a director who at the time does not qualify as a Disinterested Director may not be voted on the determination.

Section 2.The rights to indemnification and advance of expenses granted in the articles of incorporation and in these bylaws are not exclusive, and do not limit the corporation’s power to pay or reimburse expenses to which a director may be entitled, whether by agreement, vote of shareholders or Disinterested Directors or otherwise, both as to action in his or her official capacity and as to action in another capacity while holding office, and do not limit the corporation’s power to pay or reimburse expenses incurred by a director in connection with his or her appearance as a witness in a proceeding at a time when he or she is not a party.

Section 3.The corporation and its officers shall have the power to purchase and maintain insurance on behalf of an individual who is or was a director, officer, employee or agent of the corporation or who, while a director, officer, employee or agent of the corporation, is or was serving as a director, officer, partner, trustee, employee or agent of another foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, against liability asserted against or incurred by him or her in that capacity or arising from his or her status as director, officer, employee or agent, whether or not the corporation would have the power to indemnify him or her against the same liability under the provisions of these bylaws.

Section 4.If the corporation indemnifies or advances expenses to a director, otherwise than by action of the shareholders or by an insurance carrier pursuant to insurance maintained by the corporation, the corporation shall report the indemnification or advance in writing to the shareholders with or before the notice of the next annual shareholders’ meeting.

Section 5.The corporation shall indemnify any officer who was or is made a party to or is otherwise involved in any threatened, pending or completed action, suit or proceeding, whether civil, derivative, criminal, administrative or investigative, to the same extent as it is obligated to indemnify any director of the corporation, but without being subject to the same procedural conditions imposed for the indemnification of directors. The corporation may indemnify and advance expenses to an employee or agent who is not a director or officer to the extent, consistent with public policy, permitted by the articles of incorporation, these bylaws or by law.

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ARTICLE VIII
GENERAL PROVISIONS

DIVIDENDS

Section 1.Dividends upon the capital stock of the corporation, subject to the provisions of the articles of incorporation, if any, may be declared by the board of directors at any regular or special meeting, pursuant to law. Dividends may be paid in cash, in property or in shares of the capital stock, subject to the provisions of the articles of incorporation.

Section 2.Before payment of any dividend, there may be set aside out of any funds of the corporation available for dividends such sum or sums as the directors from time to time, in their absolute discretion, think proper as a reserve or reserves to meet contingencies, or for equalizing dividends, or for repairing or maintaining any property of the corporation, or for such other purpose as the directors shall think conducive to the interest of the corporation, and the directors may modify or abolish any such reserve in the manner in which it was created.

ANNUAL STATEMENT

Section 3.The board of directors shall present at each annual meeting, and at any special meeting of the shareholders when called for by vote of the shareholders, a full and clear statement of the business and condition of the corporation.

CHECKS

Section 4.All checks or demands for money and notes of the corporation shall be signed by such officer or officers or such other person or persons as the board of directors may from time to time designate.

FISCAL YEAR

Section 5.The fiscal year of the corporation shall be fixed by resolution of the board of directors.

SEAL

Section 6.The corporate seal shall have inscribed thereon the name of the corporation, the year of its organization and the words “Corporate Seal, Georgia.” The seal may be used by causing it or a facsimile thereof to be impressed or affixed or reproduced or otherwise.

ARTICLE IX
AMENDMENTS

Section 1.These bylaws may be altered, amended or repealed or new bylaws may be adopted by the shareholders or by the board of directors, when such power is conferred upon the board of directors by the articles of incorporation, at any regular meeting of the shareholders or

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of the board of directors or at any special meeting of the shareholders or of the board of directors if notice of such alteration, amendment, repeal or adoption of new bylaws be contained in the notice of such special meeting. If the power to adopt, amend or repeal bylaws is conferred upon the board of directors by the articles of incorporation, it shall not divest or limit the power of the shareholders to adopt, amend or repeal bylaws.

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EX-31.A1

Exhibit 31(a)1

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Thomas A. Fanning, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  July 30, 2019

/s/Thomas A. Fanning

Thomas A. Fanning

Chairman, President and

Chief Executive Officer

EX-31.A2

Exhibit 31(a)2

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Andrew W. Evans, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  July 30, 2019

/s/Andrew W. Evans

Andrew W. Evans

Executive Vice President and Chief Financial Officer

EX-31.B1

Exhibit 31(b)1

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Mark A. Crosswhite, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  July 30, 2019

/s/Mark A. Crosswhite

Mark A. Crosswhite

Chairman, President and Chief Executive Officer

EX-31.B2

Exhibit 31(b)2

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Philip C. Raymond, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  July 30, 2019

/s/Philip C. Raymond

Philip C. Raymond

Executive Vice President, Chief Financial Officer

and Treasurer

EX-31.C1

Exhibit 31(c)1

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, W. Paul Bowers, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  July 30, 2019

/s/W. Paul Bowers

W. Paul Bowers

Chairman, President and Chief Executive Officer

EX-31.C2

Exhibit 31(c)2

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, David P. Poroch, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  July 30, 2019

/s/David P. Poroch

David P. Poroch

Executive Vice President, Chief Financial Officer, Treasurer and Comptroller

EX-31.D1

Exhibit 31(d)1

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Anthony L. Wilson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  July 30, 2019

/s/Anthony L. Wilson

Anthony L. Wilson

Chairman, President and

 Chief Executive Officer

EX-31.D2

Exhibit 31(d)2

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Moses H. Feagin, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  July 30, 2019

/s/Moses H. Feagin

Moses H. Feagin

Vice President, Treasurer and

Chief Financial Officer

EX-31.E1

Exhibit 31(e)1

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Mark S. Lantrip, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Southern Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   July 30, 2019

/s/Mark S. Lantrip

Mark S. Lantrip

Chairman and Chief Executive Officer

EX-31.E2

Exhibit 31(e)2

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Elliott L. Spencer, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Southern Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  July 30, 2019

/s/Elliott L. Spencer

Elliott L. Spencer

Senior Vice President, Chief

Financial Officer and Treasurer

EX-31.F1

Exhibit 31(f)1

SOUTHERN COMPANY GAS

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Kimberly S. Greene, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Southern Company Gas;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  July 30, 2019

/s/Kimberly S. Greene

Kimberly S. Greene

Chairman, President and Chief Executive Officer

EX-31.F2

Exhibit 31(f)2

SOUTHERN COMPANY GAS

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Daniel S. Tucker, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Southern Company Gas;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  July 30, 2019

/s/Daniel S. Tucker

Daniel S. Tucker

Executive Vice President, Chief Financial

Officer and Treasurer

EX-32.A

Exhibit 32(a)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of The Southern Company for the quarter ended June 30, 2019, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of The Southern Company for the quarter ended June 30, 2019, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of The Southern Company for the quarter ended June 30, 2019, fairly presents, in all material respects, the financial condition and results of operations of The Southern Company.

/s/Thomas A. Fanning

Thomas A. Fanning

Chairman, President and

Chief Executive Officer

/s/Andrew W. Evans

Andrew W. Evans

Executive Vice President and

Chief Financial Officer

July 30, 2019

EX-32.B

Exhibit 32(b)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended June 30, 2019, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended June 30, 2019, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended June 30, 2019, fairly presents, in all material respects, the financial condition and results of operations of Alabama Power Company.

/s/Mark A. Crosswhite

Mark A. Crosswhite

Chairman, President and Chief Executive Officer

/s/Philip C. Raymond

Philip C. Raymond

Executive Vice President,

Chief Financial Officer and Treasurer

July 30, 2019

EX-32.C

Exhibit 32(c)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended June 30, 2019, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended June 30, 2019, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended June 30, 2019, fairly presents, in all material respects, the financial condition and results of operations of Georgia Power Company.

/s/W. Paul Bowers

W. Paul Bowers

Chairman, President and Chief Executive Officer

/s/David P. Poroch

David P. Poroch

Executive Vice President, Chief Financial Officer, Treasurer and Comptroller

July 30, 2019

EX-32.D

Exhibit 32(d)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended June 30, 2019, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended June 30, 2019, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended June 30, 2019, fairly presents, in all material respects, the financial condition and results of operations of Mississippi Power Company.

/s/Anthony L. Wilson

Anthony L. Wilson

Chairman, President and Chief Executive Officer

/s/Moses H. Feagin

Moses H. Feagin

Vice President, Treasurer and

Chief Financial Officer

July 30, 2019

EX-32.E

Exhibit 32(e)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended June 30, 2019, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended June 30, 2019, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended June 30, 2019, fairly presents, in all material respects, the financial condition and results of operations of Southern Power Company.

/s/Mark S. Lantrip

Mark S. Lantrip

 Chairman and Chief Executive Officer

/s/Elliott L. Spencer

Elliott L. Spencer

Senior Vice President, Chief Financial Officer and Treasurer

July 30, 2019

EX-32.F

Exhibit 32(f)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Southern Company Gas for the quarter ended June 30, 2019, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Southern Company Gas for the quarter ended June 30, 2019, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Southern Company Gas for the quarter ended June 30, 2019, fairly presents, in all material respects, the financial condition and results of operations of Southern Company Gas.

/s/Kimberly S. Greene

Kimberly S. Greene

Chairman, President and Chief Executive Officer

/s/Daniel S. Tucker

Daniel S. Tucker

Executive Vice President, Chief Financial

Officer and Treasurer

July 30, 2019

XML

Cover Page	6 Months Ended
	Jun. 30, 2019 shares
Document Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2019
Document Transition Report	false
Entity File Number	1-3526
Entity Registrant Name	The Southern Company
Entity Tax Identification Number	58-0690070
Entity Incorporation, State or Country Code	DE
Entity Address, Address Line One	30 Ivan Allen Jr. Boulevard, N.W.
Entity Address, City or Town	Atlanta
Entity Address, State or Province	GA
Entity Address, Postal Zip Code	30308
City Area Code	404
Local Phone Number	506-5000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Shell Company	false
Entity Common Stock, Shares Outstanding	1,045,231,646
Entity Central Index Key	0000092122
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Emerging Growth Company	false
Entity Small Business	false
Common Stock, par value $5 per share
Document Information [Line Items]
Title of 12(b) Security	Common Stock, par value $5 per share
Trading Symbol	SO
Security Exchange Name	NYSE
Series 2015A 6.25% Junior Subordinated Notes due 2075
Document Information [Line Items]
Title of 12(b) Security	Series 2015A 6.25% Junior Subordinated Notes due 2075
Trading Symbol	SOJA
Security Exchange Name	NYSE
Series 2016A 5.25% Junior Subordinated Notes due 2076
Document Information [Line Items]
Title of 12(b) Security	Series 2016A 5.25% Junior Subordinated Notes due 2076
Trading Symbol	SOJB
Security Exchange Name	NYSE
Series 2017B 5.25% Junior Subordinated Notes due 2077
Document Information [Line Items]
Title of 12(b) Security	Series 2017B 5.25% Junior Subordinated Notes due 2077
Trading Symbol	SOJC
Security Exchange Name	NYSE
ALABAMA POWER CO
Document Information [Line Items]
Entity File Number	1-3164
Entity Registrant Name	Alabama Power Company
Entity Tax Identification Number	63-0004250
Entity Incorporation, State or Country Code	AL
Entity Address, Address Line One	600 North 18th Street
Entity Address, City or Town	Birmingham
Entity Address, State or Province	AL
Entity Address, Postal Zip Code	35203
City Area Code	205
Local Phone Number	257-1000
Title of 12(b) Security	5.00% Series Class A Preferred Stock
Trading Symbol	ALP PR Q
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Shell Company	false
Entity Common Stock, Shares Outstanding	30,537,500
Entity Central Index Key	0000003153
Entity Emerging Growth Company	false
Entity Small Business	false
GEORGIA POWER CO
Document Information [Line Items]
Entity File Number	1-6468
Entity Registrant Name	Georgia Power Company
Entity Tax Identification Number	58-0257110
Entity Incorporation, State or Country Code	GA
Entity Address, Address Line One	241 Ralph McGill Boulevard, N.E.
Entity Address, City or Town	Atlanta
Entity Address, State or Province	GA
Entity Address, Postal Zip Code	30308
City Area Code	404
Local Phone Number	506-6526
Title of 12(b) Security	Series 2017A 5.00% Junior Subordinated Notes due 2077
Trading Symbol	GPJA
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Shell Company	false
Entity Common Stock, Shares Outstanding	9,261,500
Entity Central Index Key	0000041091
Entity Emerging Growth Company	false
Entity Small Business	false
MISSISSIPPI POWER CO
Document Information [Line Items]
Entity File Number	001-11229
Entity Registrant Name	Mississippi Power Company
Entity Tax Identification Number	64-0205820
Entity Incorporation, State or Country Code	MS
Entity Address, Address Line One	2992 West Beach Boulevard
Entity Address, City or Town	Gulfport
Entity Address, State or Province	MS
Entity Address, Postal Zip Code	39501
City Area Code	228
Local Phone Number	864-1211
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Shell Company	false
Entity Common Stock, Shares Outstanding	1,121,000
Entity Central Index Key	0000066904
Entity Emerging Growth Company	false
Entity Small Business	false
SOUTHERN POWER CO
Document Information [Line Items]
Entity File Number	001-37803
Entity Registrant Name	Southern Power Company
Entity Tax Identification Number	58-2598670
Entity Incorporation, State or Country Code	DE
Entity Address, Address Line One	30 Ivan Allen Jr. Boulevard, N.W.
Entity Address, City or Town	Atlanta
Entity Address, State or Province	GA
Entity Address, Postal Zip Code	30308
City Area Code	404
Local Phone Number	506-5000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Shell Company	false
Entity Common Stock, Shares Outstanding	1,000
Entity Central Index Key	0001160661
Entity Emerging Growth Company	false
Entity Small Business	false
SOUTHERN POWER CO | Series 2016A 1.000% Senior Notes due 2022
Document Information [Line Items]
Title of 12(b) Security	Series 2016A 1.000% Senior Notes due 2022
Trading Symbol	SO/22B
Security Exchange Name	NYSE
SOUTHERN POWER CO | Series 2016B 1.850% Senior Notes due 2026
Document Information [Line Items]
Title of 12(b) Security	Series 2016B 1.850% Senior Notes due 2026
Trading Symbol	SO/26A
Security Exchange Name	NYSE
SOUTHERN Co GAS
Document Information [Line Items]
Entity File Number	1-14174
Entity Registrant Name	Southern Company Gas
Entity Tax Identification Number	58-2210952
Entity Incorporation, State or Country Code	GA
Entity Address, Address Line One	Ten Peachtree Place, N.E.
Entity Address, City or Town	Atlanta
Entity Address, State or Province	GA
Entity Address, Postal Zip Code	30309
City Area Code	404
Local Phone Number	584-4000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Shell Company	false
Entity Common Stock, Shares Outstanding	100
Entity Central Index Key	0001004155
Entity Emerging Growth Company	false
Entity Small Business	false

XML

Condensed Consolidated Statements of Income (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Operating Revenues:
Total operating revenues	$ 5,098	$ 5,627	$ 10,510	$ 11,999
Operating Expenses:
Other operations and maintenance	1,316	1,523	2,628	2,972
Depreciation and amortization	755	783	1,506	1,552
Taxes other than income taxes	299	316	628	671
Estimated loss on plants under construction	4	1,060	6	1,105
(Gain) loss on dispositions, net	(8)	36	(2,506)	36
Asset impairment			32	161
Goodwill impairment	32		32
Total operating expenses	3,756	5,564	5,477	10,560
Operating Income	1,342	63	5,033	1,439
Other Income and (Expense):
Allowance for equity funds used during construction	31	32	63	63
Earnings from equity method investments	33	31	81	72
Interest expense, net of amounts capitalized	(429)	(470)	(859)	(928)
Other income (expense), net	99	78	176	138
Total other income and (expense)	(266)	(329)	(539)	(655)
Earnings (Loss) Before Income Taxes	1,076	(266)	4,494	784
Income taxes (benefit)	145	(139)	1,505	(25)
Consolidated Net Income (Loss)	931	(127)	2,989	809
Dividends on preferred stock of subsidiaries	3	4	7	8
Net income attributable to noncontrolling interests	29	23	0	17
Net Income (Loss)	$ 899	$ (154)	$ 2,982	$ 784
Earnings (loss) per share -
Basic (in dollars per share)	$ 0.86	$ (0.15)	$ 2.86	$ 0.77
Diluted (in dollars per share)	$ 0.85	$ (0.15)	$ 2.84	$ 0.77
Average number of shares of common stock outstanding (in millions)
Basic (in shares)	1,044	1,014	1,041	1,012
Diluted (in shares)	1,052	1,014	1,049	1,017
Retail electric revenues
Operating Revenues:
Total operating revenues	$ 3,540	$ 3,740	$ 6,623	$ 7,308
Wholesale electric revenues
Operating Revenues:
Total operating revenues	542	616	1,041	1,239
Other electric revenues
Operating Revenues:
Total operating revenues	161	170	331	330
Natural gas
Operating Revenues:
Total operating revenues	689	706	2,163	2,314
Operating Expenses:
Total cost of natural gas	191	228	877	949
Other
Operating Revenues:
Total operating revenues	166	395	352	808
Operating Expenses:
Total cost of natural gas	84	279	203	568
Fuel
Operating Expenses:
Total cost of natural gas	914	1,103	1,764	2,204
Purchased power
Operating Expenses:
Total cost of natural gas	201	236	371	503
ALABAMA POWER CO
Operating Revenues:
Total operating revenues	1,513	1,503	2,921	2,976
Operating Expenses:
Other operations and maintenance	402	402	812	788
Depreciation and amortization	200	189	399	379
Taxes other than income taxes	98	94	200	192
Total operating expenses	1,068	1,123	2,138	2,224
Operating Income	445	380	783	752
Other Income and (Expense):
Allowance for equity funds used during construction	14	14	28	27
Interest expense, net of amounts capitalized	(82)	(80)	(165)	(158)
Other income (expense), net	11	12	25	15
Total other income and (expense)	(57)	(54)	(112)	(116)
Earnings (Loss) Before Income Taxes	388	326	671	636
Income taxes (benefit)	89	64	151	145
Consolidated Net Income (Loss)	299	262	520	491
Dividends on preferred stock of subsidiaries	3	3	7	7
Net Income (Loss)	296	259	513	484
ALABAMA POWER CO | Retail electric revenues
Operating Revenues:
Total operating revenues	1,378	1,338	2,592	2,624
ALABAMA POWER CO | Wholesale electric revenues
Operating Revenues:
Total operating revenues	62	65	123	139
ALABAMA POWER CO | Other
Operating Revenues:
Total operating revenues	69	69	143	131
ALABAMA POWER CO | Fuel
Operating Expenses:
Total cost of natural gas	252	347	553	672
ALABAMA POWER CO | Purchased power
Operating Expenses:
Total cost of natural gas	47	48	84	113
ALABAMA POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Total operating revenues	4	31	63	82
ALABAMA POWER CO | Purchased power, affiliates
Operating Expenses:
Total cost of natural gas	69	43	90	80
GEORGIA POWER CO
Operating Revenues:
Total operating revenues	2,117	2,048	3,951	4,008
Operating Expenses:
Other operations and maintenance	463	457	913	863
Depreciation and amortization	244	230	483	458
Taxes other than income taxes	115	106	220	214
Estimated loss on plants under construction	0	1,060	0	1,060
Total operating expenses	1,470	2,520	2,857	3,967
Operating Income	647	(472)	1,094	41
Other Income and (Expense):
Interest expense, net of amounts capitalized	(105)	(102)	(201)	(208)
Other income (expense), net	35	35	77	73
Total other income and (expense)	(70)	(67)	(124)	(135)
Earnings (Loss) Before Income Taxes	577	(539)	970	(94)
Income taxes (benefit)	129	(143)	211	(50)
Consolidated Net Income (Loss)	448	(396)	759	(44)
Net Income (Loss)	448	(396)
GEORGIA POWER CO | Retail electric revenues
Operating Revenues:
Total operating revenues	1,946	1,889	3,614	3,688
GEORGIA POWER CO | Wholesale electric revenues
Operating Revenues:
Total operating revenues	33	36	62	80
GEORGIA POWER CO | Other
Operating Revenues:
Total operating revenues	135	120	270	227
GEORGIA POWER CO | Fuel
Operating Expenses:
Total cost of natural gas	390	378	689	790
GEORGIA POWER CO | Purchased power
Operating Expenses:
Total cost of natural gas	124	111	242	233
GEORGIA POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Total operating revenues	3	3	5	13
GEORGIA POWER CO | Purchased power, affiliates
Operating Expenses:
Total cost of natural gas	134	178	310	349
MISSISSIPPI POWER CO
Operating Revenues:
Total operating revenues	313	297	600	598
Operating Expenses:
Other operations and maintenance	68	67	127	141
Depreciation and amortization	48	44	95	84
Taxes other than income taxes	28	27	55	54
Estimated loss on plants under construction	4	0	6	45
Total operating expenses	259	243	490	537
Operating Income	54	54	110	61
Other Income and (Expense):
Interest expense, net of amounts capitalized	(17)	(21)	(35)	(39)
Other income (expense), net	5	27	11	27
Total other income and (expense)	(12)	6	(24)	(12)
Earnings (Loss) Before Income Taxes	42	60	86	49
Income taxes (benefit)	5	13	12	9
Consolidated Net Income (Loss)	37	47	74	40
Dividends on preferred stock of subsidiaries	0	1	0	1
Net Income (Loss)	37	46	74	39
MISSISSIPPI POWER CO | Retail electric revenues
Operating Revenues:
Total operating revenues	215	212	418	406
MISSISSIPPI POWER CO | Wholesale electric revenues
Operating Revenues:
Total operating revenues	57	59	114	127
MISSISSIPPI POWER CO | Other
Operating Revenues:
Total operating revenues	4	7	10	11
MISSISSIPPI POWER CO | Fuel
Operating Expenses:
Total cost of natural gas	105	98	198	197
MISSISSIPPI POWER CO | Purchased power
Operating Expenses:
Total cost of natural gas	6	7	9	16
MISSISSIPPI POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Total operating revenues	37	19	58	54
SOUTHERN POWER CO
Operating Revenues:
Total operating revenues	510	555	953	1,064
Operating Expenses:
Other operations and maintenance	79	91	166	184
Depreciation and amortization	119	125	237	240
Taxes other than income taxes	11	12	21	24
(Gain) loss on dispositions, net	(23)	0	(23)	0
Asset impairment	0	119	0	119
Total operating expenses	357	539	740	988
Operating Income	153	16	213	76
Other Income and (Expense):
Interest expense, net of amounts capitalized	(41)	(46)	(84)	(93)
Other income (expense), net	40	2	41	5
Total other income and (expense)	(1)	(44)	(43)	(88)
Earnings (Loss) Before Income Taxes	152	(28)	170	(12)
Income taxes (benefit)	(51)	(73)	(60)	(172)
Consolidated Net Income (Loss)	203	45	230	160
Net income attributable to noncontrolling interests	29	23	0	17
Net Income (Loss)	174	22	230	143
SOUTHERN POWER CO | Wholesale electric revenues
Operating Revenues:
Total operating revenues	390	443	743	867
SOUTHERN POWER CO | Other
Operating Revenues:
Total operating revenues	3	3	6	5
SOUTHERN POWER CO | Fuel
Operating Expenses:
Total cost of natural gas	139	153	284	321
SOUTHERN POWER CO | Purchased power
Operating Expenses:
Total cost of natural gas	32	39	55	100
SOUTHERN POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Total operating revenues	117	109	204	192
SOUTHERN Co GAS
Operating Revenues:
Total operating revenues	689	730	2,163	2,369
Operating Expenses:
Other operations and maintenance	199	238	433	514
Depreciation and amortization	119	126	238	255
Taxes other than income taxes	46	48	128	125
(Gain) loss on dispositions, net	0	36	0	36
Goodwill impairment	0	0	0	42
Total operating expenses	555	681	1,676	1,933
Operating Income	134	49	487	436
Other Income and (Expense):
Earnings from equity method investments	31	31	80	74
Interest expense, net of amounts capitalized	(59)	(59)	(118)	(118)
Other income (expense), net	6	3	10	15
Total other income and (expense)	(22)	(25)	(28)	(29)
Earnings (Loss) Before Income Taxes	112	24	459	407
Income taxes (benefit)	6	55	83	159
Consolidated Net Income (Loss)	106	(31)	376	248
Net Income (Loss)	106	(31)	376	248
SOUTHERN Co GAS | Natural gas
Operating Revenues:
Total operating revenues	688	710	2,163	2,341
Operating Expenses:
Total cost of natural gas	191	228	877	949
SOUTHERN Co GAS | Other
Operating Revenues:
Total operating revenues	0	24	0	55
Operating Expenses:
Total cost of natural gas	0	5	0	12
SOUTHERN Co GAS | Alternative revenue programs
Operating Revenues:
Total operating revenues	$ 1	$ (4)	$ 0	$ (27)

XML

Condensed Consolidated Statements of Income (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Alternative revenue programs
Total operating revenues	$ 1	$ (4)	$ 0	$ (27)
SOUTHERN Co GAS
Excise taxes collected	$ 23	$ 23	$ 78	$ 74

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Net income (loss)	$ 931	$ (127)	$ 2,989	$ 809
Qualifying hedges:
Changes in fair value, net of tax	(32)	(54)	(60)	(8)
Reclassification adjustment for amounts included in net income, net of tax	(3)	64	24	45
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	0	2	1	4
Total other comprehensive income (loss)	(35)	12	(35)	41
Comprehensive Income (Loss)	896	(115)	2,954	850
Dividends on preferred stock of subsidiaries	3	4	7	8
Comprehensive income attributable to noncontrolling interests	29	23	0	17
Comprehensive Income (Loss) Attributable to Parent	864	(142)	2,947	825
ALABAMA POWER CO
Net income (loss)	299	262	520	491
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	1	1	2	2
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	1	1	2	2
Comprehensive Income (Loss)	300	263	522	493
Dividends on preferred stock of subsidiaries	3	3	7	7
GEORGIA POWER CO
Net income (loss)	448	(396)	759	(44)
Qualifying hedges:
Changes in fair value, net of tax	(28)	0	(28)	0
Reclassification adjustment for amounts included in net income, net of tax	1	1	1	2
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	(27)	1	(27)	2
Comprehensive Income (Loss)	421	(395)	732	(42)
MISSISSIPPI POWER CO
Net income (loss)	37	47	74	40
Qualifying hedges:
Changes in fair value, net of tax	0	0	0	(1)
Reclassification adjustment for amounts included in net income, net of tax	0	0	1	1
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	0	0	1	0
Comprehensive Income (Loss)	37	47	75	40
Dividends on preferred stock of subsidiaries	0	1	0	1
SOUTHERN POWER CO
Net income (loss)	203	45	230	160
Qualifying hedges:
Changes in fair value, net of tax	(1)	(55)	(30)	(8)
Reclassification adjustment for amounts included in net income, net of tax	(7)	59	17	35
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	0	0	0	1
Total other comprehensive income (loss)	(8)	4	(13)	28
Comprehensive Income (Loss)	195	49	217	188
Comprehensive income attributable to noncontrolling interests	29	23	0	17
Comprehensive Income (Loss) Attributable to Parent	166	26	217	171
SOUTHERN Co GAS
Net income (loss)	106	(31)	376	248
Qualifying hedges:
Changes in fair value, net of tax	(3)	1	(3)	1
Reclassification adjustment for amounts included in net income, net of tax	0	0	0	2
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	0	0	(1)	0
Total other comprehensive income (loss)	(3)	1	(4)	3
Comprehensive Income (Loss)	$ 103	$ (30)	$ 372	$ 251

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Qualifying hedges:
Changes in fair value, tax	$ (11)	$ (18)	$ (21)	$ (3)
Reclassification adjustment for amounts included in net income, tax	(1)	21	8	15
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, tax	0	1	0	1
ALABAMA POWER CO
Qualifying hedges:
Reclassification adjustment for amounts included in net income, tax	0	0	1	1
GEORGIA POWER CO
Qualifying hedges:
Changes in fair value, tax	(9)	0	(9)	0
Reclassification adjustment for amounts included in net income, tax	0	0	0	1
MISSISSIPPI POWER CO
Qualifying hedges:
Changes in fair value, tax	0	0	0	(1)
Reclassification adjustment for amounts included in net income, tax	0	0	0	0
SOUTHERN POWER CO
Qualifying hedges:
Changes in fair value, tax	(1)	(19)	(10)	(3)
Reclassification adjustment for amounts included in net income, tax	(2)	20	6	12
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, tax	0	0	0	0
SOUTHERN Co GAS
Qualifying hedges:
Changes in fair value, tax	(1)	0	(1)	0
Reclassification adjustment for amounts included in net income, tax	0	0	0	1
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, tax	$ (1)	$ 0	$ (1)	$ 0

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Operating Activities:
Net income (loss)	$ 2,989	$ 809
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	1,623	1,750
Deferred income taxes	274	(338)
Allowance for equity funds used during construction	(63)	(63)
Mark-to-market adjustments	31	3
Pension, postretirement, and other employee benefits	(65)	(74)
Settlement of asset retirement obligations	(143)	(97)
Stock based compensation expense	75	83
Estimated loss on Kemper IGCC	11	1,088
(Gain) loss on dispositions, net	(2,512)	35
Asset impairment	32	161
Other, net	(22)	(34)
Goodwill impairment	32
Loss on disposition	(2,506)	36
Changes in certain current assets and liabilities —
-Receivables	653	94
-Prepayments	(53)	(73)
-Natural gas for sale, net of temporary LIFO liquidation	255	295
-Other current assets	(18)	(40)
-Accounts payable	(1,045)	(406)
-Accrued taxes	938	213
-Accrued compensation	(312)	(284)
-Other current liabilities	(135)	136
Net cash provided from operating activities	2,513	3,258
Investing Activities:
Property additions	(3,484)	(3,828)
Nuclear decommissioning trust fund purchases	(405)	(571)
Nuclear decommissioning trust fund sales	400	566
Proceeds from dispositions and asset sales	5,000	500
Cost of removal, net of salvage	(197)	(128)
Change in construction payables, net	(107)	49
Investment in unconsolidated subsidiaries	(134)	(63)
Payments pursuant to LTSAs	(64)	(103)
Other investing activities	(7)	(46)
Net cash provided from (used for) investing activities	1,002	(3,624)
Financing Activities:
Increase in notes payable, net	83	1,442
Proceeds —
Long-term debt	1,390	1,100
Common stock	452	222
Short-term borrowings	250	1,650
Redemptions and repurchases —
Long-term debt	(2,560)	(3,379)
Short-term borrowings	(1,850)	(550)
Distributions to noncontrolling interests	(82)	(42)
Capital contributions from noncontrolling interests	5	1,210
Payment of common stock dividends	(1,269)	(1,194)
Other financing activities	(67)	(223)
Net cash provided from (used for) financing activities	(3,648)	236
Net Change in Cash, Cash Equivalents, and Restricted Cash	(133)	(130)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	1,519	2,147
Cash, Cash Equivalents, and Restricted Cash at End of Period	1,386	2,017
Cash paid during the period for —
Interest, net of amounts capitalized	844	927
Income taxes, net	210	4
Noncash transactions — Accrued property additions at end of period	988	1,067
ALABAMA POWER CO
Operating Activities:
Net income (loss)	520	491
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	493	452
Deferred income taxes	138	48
Allowance for equity funds used during construction	(28)	(27)
Pension, postretirement, and other employee benefits	(13)	(28)
Settlement of asset retirement obligations	(43)	(19)
Other, net	(1)	(21)
Changes in certain current assets and liabilities —
-Receivables	6	(153)
-Prepayments	(59)	(57)
-Other current assets	(10)	29
-Accounts payable	(246)	(196)
-Accrued taxes	8	134
-Accrued compensation	(88)	(70)
-Other current liabilities	13	116
-Materials and supplies	5	(47)
Net cash provided from operating activities	695	652
Investing Activities:
Property additions	(833)	(997)
Nuclear decommissioning trust fund purchases	(139)	(131)
Nuclear decommissioning trust fund sales	139	131
Cost of removal, net of salvage	(48)	(34)
Change in construction payables, net	(103)	(29)
Other investing activities	(18)	(15)
Net cash provided from (used for) investing activities	(1,002)	(1,075)
Proceeds —
Senior notes	0	500
Capital contributions from parent company	1,254	488
Redemptions and repurchases —
Senior notes	(200)	0
Payment of common stock dividends	(422)	(402)
Other financing activities	(15)	(21)
Net cash provided from (used for) financing activities	617	565
Net Change in Cash, Cash Equivalents, and Restricted Cash	310	142
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	313	544
Cash, Cash Equivalents, and Restricted Cash at End of Period	623	686
Cash paid during the period for —
Interest, net of amounts capitalized	154	143
Income taxes, net	63	17
Noncash transactions — Accrued property additions at end of period	168	216
GEORGIA POWER CO
Operating Activities:
Net income (loss)	759	(44)
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	583	562
Deferred income taxes	153	(256)
Pension, postretirement, and other employee benefits	(56)	(47)
Settlement of asset retirement obligations	(76)	(49)
Estimated loss on Kemper IGCC	0	1,060
Other, net	0	29
Changes in certain current assets and liabilities —
-Receivables	(43)	(103)
-Other current assets	22	25
-Accounts payable	(94)	(87)
-Accrued taxes	(139)	(89)
-Accrued compensation	(32)	(56)
-Other current liabilities	(2)	(26)
-Fossil fuel stock	(26)	38
-Prepaid income taxes	63	115
Net cash provided from operating activities	1,112	1,072
Investing Activities:
Property additions	(1,712)	(1,501)
Nuclear decommissioning trust fund purchases	(266)	(440)
Nuclear decommissioning trust fund sales	260	435
Proceeds from dispositions and asset sales	9	134
Cost of removal, net of salvage	(107)	(50)
Payments pursuant to LTSAs	(9)	(46)
Other investing activities	(4)	(11)
Change in construction payables, net of joint owner portion	(5)	86
Net cash provided from (used for) investing activities	(1,834)	(1,393)
Financing Activities:
Increase in notes payable, net	11	480
Proceeds —
Short-term borrowings	250	0
Capital contributions from parent company	46	1,502
FFB loan	835	0
Pollution control revenue bonds	513	0
Redemptions and repurchases —
Short-term borrowings	0	(150)
Senior notes	0	(1,000)
Pollution control revenue bonds	(223)	(398)
Other long-term debt	0	(100)
Payment of common stock dividends	(788)	(691)
Other financing activities	(24)	(11)
Premiums on redemption and repurchases of senior notes	0	(152)
Net cash provided from (used for) financing activities	620	(520)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(102)	(841)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	112	852
Cash, Cash Equivalents, and Restricted Cash at End of Period	10	11
Cash paid during the period for —
Interest, net of amounts capitalized	179	211
Income taxes, net	(6)	64
Noncash transactions — Accrued property additions at end of period	650	669
MISSISSIPPI POWER CO
Operating Activities:
Net income (loss)	74	40
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	98	86
Deferred income taxes	(16)	289
Settlement of asset retirement obligations	(17)	(15)
Estimated loss on Kemper IGCC	11	28
Other, net	1	2
Changes in certain current assets and liabilities —
-Receivables	(8)	(51)
-Other current assets	(3)	(11)
-Accounts payable	(28)	(15)
-Accrued taxes	(43)	(41)
-Accrued compensation	(15)	(14)
-Other current liabilities	6	(1)
Net cash provided from operating activities	60	297
Investing Activities:
Property additions	(95)	(74)
Change in construction payables, net	(12)	(9)
Payments pursuant to LTSAs	(11)	(13)
Other investing activities	(10)	(12)
Net cash provided from (used for) investing activities	(128)	(108)
Financing Activities:
Increase in notes payable, net	0	(4)
Proceeds —
Short-term borrowings	0	300
Senior notes	0	600
Capital contributions from parent company	7	1
Pollution control revenue bonds	43	0
Redemptions and repurchases —
Short-term borrowings	0	(200)
Other long-term debt	0	(900)
Other financing activities	(1)	(6)
Return of capital	(75)	0
Net cash provided from (used for) financing activities	(26)	(209)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(94)	(20)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	293	248
Cash, Cash Equivalents, and Restricted Cash at End of Period	199	228
Cash paid during the period for —
Interest, net of amounts capitalized	36	39
Income taxes, net	23	(257)
Noncash transactions — Accrued property additions at end of period	23	23
SOUTHERN POWER CO
Operating Activities:
Net income (loss)	230	160
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	251	256
Deferred income taxes	(63)	(252)
Asset impairment	0	119
Other, net	(69)	(10)
Amortization of investment tax credits	(122)	(29)
Loss on disposition	(23)	0
Changes in certain current assets and liabilities —
-Receivables	(9)	(30)
-Other current assets	4	3
-Accounts payable	(17)	(41)
-Accrued compensation	(9)	(9)
-Other current liabilities	3	(4)
-Prepaid income taxes	520	(36)
Net cash provided from operating activities	719	127
Investing Activities:
Business acquisitions	(2)	(64)
Property additions	(123)	(198)
Proceeds from dispositions and asset sales	540	0
Change in construction payables, net	(23)	2
Investment in unconsolidated subsidiaries	(116)	0
Payments pursuant to LTSAs	(31)	(32)
Other investing activities	9	15
Net cash provided from (used for) investing activities	254	(277)
Financing Activities:
Increase in notes payable, net	0	(41)
Proceeds —
Short-term borrowings	0	200
Capital contributions from parent company	6	16
Redemptions and repurchases —
Short-term borrowings	(100)	0
Senior notes	0	(350)
Other long-term debt	0	(420)
Distributions to noncontrolling interests	(82)	(42)
Capital contributions from noncontrolling interests	5	1,210
Payment of common stock dividends	(103)	(156)
Other financing activities	(5)	(15)
Return of capital	(505)	(250)
Net cash provided from (used for) financing activities	(784)	152
Net Change in Cash, Cash Equivalents, and Restricted Cash	189	2
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	181	140
Cash, Cash Equivalents, and Restricted Cash at End of Period	370	142
Cash paid during the period for —
Interest, net of amounts capitalized	106	109
Income taxes, net	(421)	109
Noncash transactions — Accrued property additions at end of period	31	33
SOUTHERN Co GAS
Operating Activities:
Net income (loss)	376	248
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	238	255
Deferred income taxes	59	(12)
Mark-to-market adjustments	30	2
Other, net	(26)	(24)
Goodwill impairment	0	42
Loss on disposition	0	36
Changes in certain current assets and liabilities —
-Receivables	717	504
-Natural gas for sale, net of temporary LIFO liquidation	256	295
-Other current assets	29	41
-Accounts payable	(604)	(125)
-Accrued taxes	(54)	38
-Accrued compensation	(34)	(6)
-Other current liabilities	(56)	24
Net cash provided from operating activities	931	1,318
Investing Activities:
Property additions	(603)	(679)
Proceeds from dispositions and asset sales	32	364
Cost of removal, net of salvage	(33)	(18)
Change in construction payables, net	26	(6)
Investment in unconsolidated subsidiaries	(18)	(60)
Other investing activities	10	18
Net cash provided from (used for) investing activities	(586)	(381)
Financing Activities:
Increase in notes payable, net	(158)	(515)
Redemptions and repurchases —
Long-term debt	0	(200)
Payment of common stock dividends	(235)	(235)
Other financing activities	38	10
Net cash provided from (used for) financing activities	(355)	(940)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(10)	(3)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	70	78
Cash, Cash Equivalents, and Restricted Cash at End of Period	60	75
Cash paid during the period for —
Interest, net of amounts capitalized	125	129
Income taxes, net	96	106
Noncash transactions — Accrued property additions at end of period	$ 123	$ 129

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) (Parenthetical) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Interest capitalized	$ 36	$ 35
ALABAMA POWER CO
Interest capitalized	10	10
GEORGIA POWER CO
Interest capitalized	16	12
MISSISSIPPI POWER CO
Interest received	1	0
SOUTHERN POWER CO
Interest capitalized	7	10
SOUTHERN Co GAS
Interest capitalized	$ 3	$ 3

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Current Assets:
Cash and cash equivalents	$ 1,383	$ 1,396
Receivables —
Customer accounts receivable	1,654	1,726
Energy marketing receivables	361	801
Unbilled revenues	583	654
Under recovered fuel clause revenues	69	115
Other accounts and notes receivable	756	813
Accumulated provision for uncollectible accounts	(50)	(50)
Materials and supplies	1,440	1,465
Fossil fuel for generation	435	405
Natural gas for sale	268	524
Prepaid expenses	543	432
Assets from risk management activities, net of collateral	107	222
Other regulatory assets	607	525
Assets held for sale	58	393
Other current assets	138	162
Total current assets	8,352	9,583
Property, Plant, and Equipment:
In service	103,428	103,706
Less: Accumulated depreciation	30,693	31,038
Plant in service, net of depreciation	72,735	72,668
Nuclear fuel, at amortized cost	871	875
Construction work in progress	7,568	7,254
Total property, plant, and equipment	81,174	80,797
Other Property and Investments:
Goodwill	5,282	5,315
Equity investments in unconsolidated subsidiaries	1,557	1,580
Other intangible assets, net of amortization	550	613
Nuclear decommissioning trusts, at fair value	1,942	1,721
Leveraged leases	813	798
Miscellaneous property and investments	505	269
Total other property and investments	10,649	10,296
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,862
Deferred charges related to income taxes	794	794
Unamortized loss on reacquired debt	313	323
Regulatory assets – asset retirement obligations	4,062	2,933
Other regulatory assets, deferred	5,835	5,375
Assets held for sale, deferred	685	5,350
Other deferred charges and assets	1,141	1,463
Total deferred charges and other assets	14,692	16,238
Total Assets	114,867	116,914
Current Liabilities:
Securities due within one year	3,148	3,198
Notes payable	1,398	2,915
Energy marketing trade payables	393	856
Accounts payable —
Accounts payable	1,978	2,580
Customer deposits	489	522
Accrued taxes —
Accrued income taxes	171	21
Other accrued taxes	501	635
Accrued interest	455	472
Accrued compensation	676	1,030
Asset retirement obligations	429	404
Other regulatory liabilities	304	376
Liabilities held for sale	36	425
Operating lease obligations	228
Other current liabilities	793	852
Total current liabilities	10,999	14,286
Long-term Debt	39,682	40,736
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	7,728	6,558
Deferred credits related to income taxes	6,386	6,460
Accumulated deferred ITCs	2,283	2,372
Employee benefit obligations	2,058	2,147
Operating lease obligations, deferred	1,702
Asset retirement obligations, deferred	9,478	8,990
Accrued environmental remediation	247	268
Other cost of removal obligations	2,283	2,297
Other regulatory liabilities, deferred	176	169
Liabilities held for sale, deferred	39	2,836
Other deferred credits and liabilities	384	465
Total deferred credits and other liabilities	32,764	32,562
Total Liabilities	83,445	87,584
Redeemable Preferred Stock of Subsidiaries	291	291
Total stockholders' equity	31,131	29,039
Total Liabilities and Stockholders' Equity	114,867	116,914
ALABAMA POWER CO
Current Assets:
Cash and cash equivalents	623	313
Receivables —
Customer accounts receivable	432	403
Unbilled revenues	173	150
Other accounts and notes receivable	55	51
Accumulated provision for uncollectible accounts	(10)	(10)
Affiliated	38	94
Materials and supplies	530	546
Fossil fuel for generation	143	141
Prepaid expenses	170	66
Other regulatory assets	204	137
Other current assets	26	18
Total current assets	2,384	1,909
Property, Plant, and Equipment:
In service	29,070	30,402
Less: Accumulated depreciation	9,397	9,988
Plant in service, net of depreciation	19,673	20,414
Nuclear fuel, at amortized cost	322	324
Construction work in progress	1,097	1,113
Total property, plant, and equipment	21,092	21,851
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	64	65
Nuclear decommissioning trusts, at fair value	964	847
Miscellaneous property and investments	129	127
Total other property and investments	1,157	1,039
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	152
Deferred charges related to income taxes	240	240
Regulatory assets – asset retirement obligations	1,016	147
Other regulatory assets, deferred	1,824	1,240
Other deferred charges and assets	177	188
Deferred under recovered regulatory clause revenues	25	116
Total deferred charges and other assets	3,434	1,931
Total Assets	28,067	26,730
Current Liabilities:
Securities due within one year	1	201
Accounts payable —
Affiliated	321	364
Other	334	614
Customer deposits	98	96
Accrued taxes —
Other accrued taxes	102	44
Accrued interest	88	89
Accrued compensation	140	227
Asset retirement obligations	156	163
Operating lease obligations	48
Other current liabilities	155	161
Total current liabilities	1,395	1,959
Long-term Debt	7,926	7,923
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,117	2,962
Deferred credits related to income taxes	2,006	2,027
Accumulated deferred ITCs	103	106
Employee benefit obligations	309	314
Operating lease obligations, deferred	137
Asset retirement obligations, deferred	3,389	3,047
Other cost of removal obligations	464	497
Other regulatory liabilities, deferred	69	69
Other deferred credits and liabilities	32	58
Total deferred credits and other liabilities	9,626	9,080
Total Liabilities	18,947	18,962
Redeemable Preferred Stock	291	291
Total stockholders' equity	8,829	7,477
Total Liabilities and Stockholders' Equity	28,067	26,730
GEORGIA POWER CO
Current Assets:
Cash and cash equivalents	10	4
Restricted cash and cash equivalents	0	108
Receivables —
Customer accounts receivable	603	591
Unbilled revenues	267	208
Under recovered fuel clause revenues	69	115
Other accounts and notes receivable	240	80
Accumulated provision for uncollectible accounts	(2)	(2)
Affiliated	16	39
Joint owner accounts receivable	178	170
Materials and supplies	513	519
Fossil fuel for generation	257	231
Prepaid expenses	68	142
Other regulatory assets	240	199
Other current assets	58	70
Total current assets	2,517	2,474
Property, Plant, and Equipment:
In service	38,517	37,675
Less: Accumulated depreciation	12,140	12,096
Plant in service, net of depreciation	26,377	25,579
Nuclear fuel, at amortized cost	549	550
Construction work in progress	5,193	4,833
Total property, plant, and equipment	32,119	30,962
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	51	51
Nuclear decommissioning trusts, at fair value	978	873
Miscellaneous property and investments	74	72
Total other property and investments	1,103	996
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	1,492
Deferred charges related to income taxes	518	517
Regulatory assets – asset retirement obligations	2,839	2,644
Other regulatory assets, deferred	2,272	2,258
Other deferred charges and assets	379	514
Total deferred charges and other assets	7,500	5,933
Total Assets	43,239	40,365
Current Liabilities:
Securities due within one year	988	617
Notes payable	555	294
Accounts payable —
Affiliated	477	575
Other	901	890
Customer deposits	282	276
Accrued taxes —
Other accrued taxes	238	377
Accrued interest	112	105
Accrued compensation	163	221
Asset retirement obligations	240	202
Other regulatory liabilities	145	169
Operating lease obligations	140
Other current liabilities	383	183
Total current liabilities	4,484	3,909
Long-term Debt	10,150	9,364
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,212	3,062
Deferred credits related to income taxes	3,078	3,080
Accumulated deferred ITCs	257	262
Employee benefit obligations	550	599
Operating lease obligations, deferred	1,377
Asset retirement obligations, deferred	5,643	5,627
Other deferred credits and liabilities	172	139
Total deferred credits and other liabilities	14,289	12,769
Total Liabilities	28,923	26,042
Total stockholders' equity	14,316	14,323
Total Liabilities and Stockholders' Equity	43,239	40,365
MISSISSIPPI POWER CO
Current Assets:
Cash and cash equivalents	199	293
Receivables —
Customer accounts receivable	38	34
Unbilled revenues	44	41
Other accounts and notes receivable	38	31
Affiliated	17	21
Materials and supplies	52	53
Fossil fuel for generation	23	20
Other regulatory assets	107	116
Other current assets	13	19
Total current assets	531	628
Property, Plant, and Equipment:
In service	4,800	4,900
Less: Accumulated depreciation	1,427	1,429
Plant in service, net of depreciation	3,373	3,471
Construction work in progress	113	103
Total property, plant, and equipment	3,486	3,574
Other Property and Investments:
Total other property and investments	124	24
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	7
Deferred charges related to income taxes	33	33
Regulatory assets – asset retirement obligations	207	143
Other regulatory assets, deferred	328	332
Other deferred charges and assets	20	2
Accumulated deferred income taxes	145	150
Total deferred charges and other assets	733	660
Total Assets	4,874	4,886
Current Liabilities:
Securities due within one year	300	40
Accounts payable —
Affiliated	60	60
Other	49	90
Accrued taxes —
Other accrued taxes	52	95
Accrued interest	15	15
Accrued compensation	23	38
Asset retirement obligations	27	34
Other regulatory liabilities	20	12
Operating lease obligations	2
Other current liabilities	52	28
Accrued plant closure costs	24	29
Over recovered regulatory clause liabilities	12	14
Total current liabilities	634	455
Long-term Debt	1,318	1,539
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	366	378
Deferred credits related to income taxes	362	382
Employee benefit obligations	110	115
Operating lease obligations, deferred	5
Asset retirement obligations, deferred	177	126
Other cost of removal obligations	189	185
Other regulatory liabilities, deferred	79	81
Other deferred credits and liabilities	22	16
Total deferred credits and other liabilities	1,305	1,283
Total Liabilities	3,257	3,277
Total stockholders' equity	1,617	1,609
Total Liabilities and Stockholders' Equity	4,874	4,886
SOUTHERN POWER CO
Current Assets:
Cash and cash equivalents	370	181
Receivables —
Customer accounts receivable	153	111
Other accounts and notes receivable	59	116
Affiliated	49	55
Materials and supplies	185	220
Other current assets	33	37
Prepaid income taxes	489	25
Total current assets	1,338	745
Property, Plant, and Equipment:
In service	12,862	13,271
Less: Accumulated depreciation	2,255	2,171
Plant in service, net of depreciation	10,607	11,100
Construction work in progress	419	430
Total property, plant, and equipment	11,026	11,530
Other Property and Investments:
Miscellaneous property and investments	144	0
Intangible assets, net of amortization	313	345
Total other property and investments	457	345
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	370
Assets held for sale, deferred	599	576
Other deferred charges and assets	289	373
Prepaid LTSAs	107	98
Accumulated deferred income taxes	296	1,186
Income taxes receivable, non-current	36	30
Total deferred charges and other assets	1,697	2,263
Total Assets	14,518	14,883
Current Liabilities:
Securities due within one year	899	599
Notes payable	0	100
Accounts payable —
Affiliated	72	92
Other	60	77
Accrued taxes —
Accrued income taxes	23	6
Accrued interest	23	36
Liabilities held for sale	10	15
Operating lease obligations	22
Other current liabilities	116	106
Total current liabilities	1,203	1,031
Long-term Debt	4,112	4,418
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	106	105
Accumulated deferred ITCs	1,737	1,832
Operating lease obligations, deferred	373
Other deferred credits and liabilities	169	213
Total deferred credits and other liabilities	2,385	2,150
Total Liabilities	7,700	7,599
Total stockholders' equity	6,818	7,284
Total Liabilities and Stockholders' Equity	14,518	14,883
SOUTHERN Co GAS
Current Assets:
Cash and cash equivalents	56	64
Receivables —
Customer accounts receivable	281	370
Energy marketing receivables	361	801
Unbilled revenues	63	213
Other accounts and notes receivable	100	142
Accumulated provision for uncollectible accounts	(31)	(30)
Affiliated	10	11
Natural gas for sale	268	524
Prepaid expenses	120	118
Assets from risk management activities, net of collateral	101	219
Other regulatory assets	56	73
Other current assets	44	50
Total current assets	1,429	2,555
Property, Plant, and Equipment:
In service	15,680	15,177
Less: Accumulated depreciation	4,522	4,400
Plant in service, net of depreciation	11,158	10,777
Construction work in progress	628	580
Total property, plant, and equipment	11,786	11,357
Other Property and Investments:
Goodwill	5,015	5,015
Equity investments in unconsolidated subsidiaries	1,509	1,538
Other intangible assets, net of amortization	85	101
Miscellaneous property and investments	20	20
Total other property and investments	6,629	6,674
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization	95
Other regulatory assets, deferred	636	669
Other deferred charges and assets	186	193
Total deferred charges and other assets	917	862
Total Assets	20,761	21,448
Current Liabilities:
Securities due within one year	351	357
Notes payable	492	650
Energy marketing trade payables	393	856
Accounts payable —
Affiliated	38	45
Other	294	402
Customer deposits	92	133
Accrued taxes —
Accrued income taxes	17	66
Other accrued taxes	70	75
Accrued interest	57	55
Accrued compensation	64	100
Other regulatory liabilities	97	79
Operating lease obligations	15
Other current liabilities	124	130
Liabilities from risk management activities, net of collateral	22	76
Total current liabilities	2,111	3,024
Long-term Debt	5,565	5,583
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,088	1,016
Deferred credits related to income taxes	910	940
Employee benefit obligations	354	357
Operating lease obligations, deferred	79
Accrued environmental remediation	247	268
Other cost of removal obligations	1,598	1,585
Other deferred credits and liabilities	50	105
Total deferred credits and other liabilities	4,326	4,271
Total Liabilities	12,002	12,878
Total stockholders' equity	8,759	8,570
Total Liabilities and Stockholders' Equity	$ 20,761	$ 21,448

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Other intangible assets, amortization	$ 253	$ 235
SOUTHERN POWER CO
Other intangible assets, amortization	60	61
SOUTHERN Co GAS
Other intangible assets, amortization	$ 161	$ 145

XML

Consolidated Statements of Stockholders' Equity (Unaudited) - USD ($) shares in Millions, $ in Millions	Total	Common Stock	Treasury	Paid-In Capital	Retained Earnings (Accumulated Deficit)	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests	ALABAMA POWER CO	ALABAMA POWER CO Common Stock	ALABAMA POWER CO Paid-In Capital	ALABAMA POWER CO Retained Earnings (Accumulated Deficit)	ALABAMA POWER CO Accumulated Other Comprehensive Income (Loss)	GEORGIA POWER CO	GEORGIA POWER CO Common Stock	GEORGIA POWER CO Paid-In Capital	GEORGIA POWER CO Retained Earnings (Accumulated Deficit)	GEORGIA POWER CO Accumulated Other Comprehensive Income (Loss)	MISSISSIPPI POWER CO	MISSISSIPPI POWER CO Common Stock	MISSISSIPPI POWER CO Paid-In Capital	MISSISSIPPI POWER CO Retained Earnings (Accumulated Deficit)	MISSISSIPPI POWER CO Accumulated Other Comprehensive Income (Loss)	SOUTHERN POWER CO	SOUTHERN POWER CO Paid-In Capital	SOUTHERN POWER CO Retained Earnings (Accumulated Deficit)	SOUTHERN POWER CO Accumulated Other Comprehensive Income (Loss)	SOUTHERN POWER CO Total Common Stockholders' Equity	SOUTHERN POWER CO Noncontrolling Interests	SOUTHERN Co GAS	SOUTHERN Co GAS Paid-In Capital	SOUTHERN Co GAS Retained Earnings (Accumulated Deficit)	SOUTHERN Co GAS Accumulated Other Comprehensive Income (Loss)
Beginning balance (in shares) at Dec. 31, 2017		1,009	1						31					9					1
Beginning balance at Dec. 31, 2017	$ 25,528	$ 5,038	$ (36)	$ 10,469	$ 8,885	$ (189)	$ 1,361	$ 6,829	$ 1,222	$ 2,986	$ 2,647	$ (26)	$ 11,931	$ 398	$ 7,328	$ 4,215	$ (10)	$ 1,358	$ 38	$ 4,529	$ (3,205)	$ (4)	$ 6,498	$ 3,662	$ 1,478	$ (2)	$ 5,138	$ 1,360	$ 9,022	$ 9,214	$ (212)	$ 20
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	938				938			225			225		352			352		(7)			(7)		121		121		121		279		279
Other comprehensive income (loss)	30					30		1				1	1				1	(1)				(1)	24			24	24		2			2
Stock issued (in shares)		4
Stock issued	113	$ 16		97
Stock-based compensation	36			36
Cash dividends on common stock	(586)				(586)			(202)			(202)		(339)			(339)							(78)		(78)		(78)		(118)		(118)
Contributions from noncontrolling interests	9						9																9					9
Distributions to noncontrolling interests	(13)						(13)																(13)					(13)
Net income (loss) attributable to noncontrolling interests	(6)						(6)																(6)					(6)
Other	(24)		$ (2)	1	20	(41)	(2)	(6)				(6)	(1)		1		(2)	(1)			(1)		2		(2)	5	3	(1)	0		(4)	4
Capital contributions from parent company								488		488			1,476		1,476			2		2			1	1			1		14	14
Ending balance (in shares) at Mar. 31, 2018		1,013	1						31					9					1
Ending balance at Mar. 31, 2018	26,025	$ 5,054	$ (38)	10,603	9,257	(200)	1,349	7,335	$ 1,222	3,474	2,670	(31)	13,420	$ 398	8,805	4,228	(11)	1,351	$ 38	4,531	(3,213)	(5)	6,558	3,663	1,519	27	5,209	1,349	9,199	9,228	(55)	26
Beginning balance (in shares) at Dec. 31, 2017		1,009	1						31					9					1
Beginning balance at Dec. 31, 2017	25,528	$ 5,038	$ (36)	10,469	8,885	(189)	1,361	6,829	$ 1,222	2,986	2,647	(26)	11,931	$ 398	7,328	4,215	(10)	1,358	$ 38	4,529	(3,205)	(4)	6,498	3,662	1,478	(2)	5,138	1,360	9,022	9,214	(212)	20
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	784							484										39					143						248
Ending balance (in shares) at Jun. 30, 2018		1,015	1						31					9					1
Ending balance at Jun. 30, 2018	26,692	$ 5,066	$ (39)	10,303	8,494	(188)	3,056	7,401	$ 1,222	3,480	2,729	(30)	12,702	$ 398	8,834	3,480	(10)	1,398	$ 38	4,531	(3,166)	(5)	7,574	3,023	1,464	31	4,518	3,056	9,061	9,236	(202)	27
Beginning balance (in shares) at Mar. 31, 2018		1,013	1						31					9					1
Beginning balance at Mar. 31, 2018	26,025	$ 5,054	$ (38)	10,603	9,257	(200)	1,349	7,335	$ 1,222	3,474	2,670	(31)	13,420	$ 398	8,805	4,228	(11)	1,351	$ 38	4,531	(3,213)	(5)	6,558	3,663	1,519	27	5,209	1,349	9,199	9,228	(55)	26
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(154)				(154)			259			259		(396)			(396)		46			46		22		22		22		(31)		(31)
Other comprehensive income (loss)	12					12		1				1	1				1						4			4	4		1			1
Stock issued (in shares)		2
Stock issued	109	$ 12		97
Stock-based compensation	12			12
Cash dividends on common stock	(607)				(607)			(200)			(200)		(352)			(352)							(78)		(78)		(78)		(117)		(117)
Contributions from noncontrolling interests	22						22																22					22
Distributions to noncontrolling interests	(29)						(29)																(29)					(29)
Net income (loss) attributable to noncontrolling interests	23						23																23					23
Other	(4)		$ (1)	(2)	(2)		1	1		1								1			1		2		1		1	1	1		1
Sale of noncontrolling interests	1,283			(407)			1,690																1,283	(407)			(407)	1,690
Capital contributions from parent company								5		5			29		29								17	17			17		8	8
Return of capital to parent company																							(250)	(250)			(250)
Ending balance (in shares) at Jun. 30, 2018		1,015	1						31					9					1
Ending balance at Jun. 30, 2018	26,692	$ 5,066	$ (39)	10,303	8,494	(188)	3,056	7,401	$ 1,222	3,480	2,729	(30)	12,702	$ 398	8,834	3,480	(10)	1,398	$ 38	4,531	(3,166)	(5)	7,574	3,023	1,464	31	4,518	3,056	9,061	9,236	(202)	27
Beginning balance (in shares) at Dec. 31, 2018		1,035	1						31					9					1
Beginning balance at Dec. 31, 2018	29,039	$ 5,164	$ (38)	11,094	8,706	(203)	4,316	7,477	$ 1,222	3,508	2,775	(28)	14,323	$ 398	10,322	3,612	(9)	1,609	$ 38	4,546	(2,971)	(4)	7,284	1,600	1,352	16	2,968	4,316	8,570	8,856	(312)	26
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	2,084				2,084			217			217		311			311		37			37		56		56		56		270		270
Other comprehensive income (loss)								1				1	1				1						(4)			(4)	(4)		(1)			(1)
Stock issued (in shares)		6
Stock issued	224	$ 28		196
Stock-based compensation	24			24
Cash dividends on common stock	(623)				(623)			(211)			(211)		(394)			(394)							(51)		(51)		(51)		(118)		(118)
Contributions from noncontrolling interests	3						3																3					3
Distributions to noncontrolling interests	(41)						(41)																(41)					(41)
Net income (loss) attributable to noncontrolling interests	(29)						(29)																(29)					(29)
Other (in shares)			0
Other	6		$ (2)	7	0		1						(1)		(1)		0						(1)	(1)	(1)		(2)	1
Capital contributions from parent company								1,236		1,236			29		29			2		2			1	1			1		17	17
Return of capital to parent company																		(38)		(38)
Ending balance (in shares) at Mar. 31, 2019		1,041	1						31					9					1
Ending balance at Mar. 31, 2019	30,687	$ 5,192	$ (40)	11,321	10,167	(203)	4,250	8,720	$ 1,222	4,744	2,781	(27)	14,269	$ 398	10,350	3,529	(8)	1,610	$ 38	4,510	(2,934)	(4)	7,218	1,600	1,356	12	2,968	4,250	8,738	8,873	(160)	25
Beginning balance (in shares) at Dec. 31, 2018		1,035	1						31					9					1
Beginning balance at Dec. 31, 2018	29,039	$ 5,164	$ (38)	11,094	8,706	(203)	4,316	7,477	$ 1,222	3,508	2,775	(28)	14,323	$ 398	10,322	3,612	(9)	1,609	$ 38	4,546	(2,971)	(4)	7,284	1,600	1,352	16	2,968	4,316	8,570	8,856	(312)	26
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	2,982							513										74					230						376
Ending balance (in shares) at Jun. 30, 2019		1,046	1						31					9					1
Ending balance at Jun. 30, 2019	31,131	$ 5,217	$ (41)	11,540	10,420	(238)	4,233	8,829	$ 1,222	4,767	2,866	(26)	14,316	$ 398	10,371	3,582	(35)	1,617	$ 38	4,480	(2,897)	(4)	6,818	1,102	1,479	4	2,585	4,233	8,759	8,908	(171)	22
Beginning balance (in shares) at Mar. 31, 2019		1,041	1						31					9					1
Beginning balance at Mar. 31, 2019	30,687	$ 5,192	$ (40)	11,321	10,167	(203)	4,250	8,720	$ 1,222	4,744	2,781	(27)	14,269	$ 398	10,350	3,529	(8)	1,610	$ 38	4,510	(2,934)	(4)	7,218	1,600	1,356	12	2,968	4,250	8,738	8,873	(160)	25
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	899				899			296			296		448			448		37			37		174		174		174		106		106
Other comprehensive income (loss)	(35)					(35)		1				1	(27)				(27)						(8)			(8)	(8)		(3)			(3)
Stock issued (in shares)		5
Stock issued	228	$ 25		203
Stock-based compensation	11			11
Cash dividends on common stock	(646)				(646)			(211)			(211)		(394)			(394)							(52)		(52)		(52)		(117)		(117)
Contributions from noncontrolling interests	2						2																2					2
Distributions to noncontrolling interests	(47)						(47)																(47)					(47)
Net income (loss) attributable to noncontrolling interests	$ 29						29																29					29
Other (in shares)	0
Other	$ 3		$ (1)	5	0		(1)						0		1	(1)							0		1		1	(1)
Capital contributions from parent company								23		23			20		20			8		8			7	7			7		35	35
Return of capital to parent company																							(505)	(505)			(505)
Ending balance (in shares) at Jun. 30, 2019		1,046	1						31					9					1
Ending balance at Jun. 30, 2019	$ 31,131	$ 5,217	$ (41)	$ 11,540	$ 10,420	$ (238)	$ 4,233	$ 8,829	$ 1,222	$ 4,767	$ 2,866	$ (26)	$ 14,316	$ 398	$ 10,371	$ 3,582	$ (35)	$ 1,617	$ 38	$ 4,480	$ (2,897)	$ (4)	$ 6,818	$ 1,102	$ 1,479	$ 4	$ 2,585	$ 4,233	$ 8,759	$ 8,908	$ (171)	$ 22

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Consolidated Statements of Stockholders' Equity (Unaudited) (Parenthetical) - $ / shares	3 Months Ended
	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2018	Mar. 31, 2018
Statement of Stockholders' Equity [Abstract]
Cash dividends (in dollars per share)	$ 0.62	$ 0.60	$ 0.60	$ 0.58

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Introduction

6 Months Ended

Jun. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

INTRODUCTION

INTRODUCTION

The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2018 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended June 30, 2019 and 2018. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.

Recently Adopted Accounting Standards

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. The registrants adopted the new standard effective January 1, 2019. See Note (L) for additional information and related disclosures.

Goodwill and Other Intangible Assets

Goodwill at June 30, 2019 and December 31, 2018 was as follows:

	At June 30, 2019		At December 31, 2018
	(in millions)
Southern Company	$	5,282	$	5,315
Southern Company Gas:
Gas distribution operations	$	4,034	$	4,034
Gas marketing services	981		981
Southern Company Gas total	$	5,015	$	5,015

Goodwill is not amortized but is subject to an annual impairment test during the fourth quarter of each year or more frequently if impairment indicators arise. A goodwill impairment charge of $32 million was recorded in the second quarter 2019 in contemplation of the July 22, 2019 sale of one of PowerSecure's business units. See Note (K) under "Southern Company" for additional information.

Other intangible assets were as follows:

	At June 30, 2019							At December 31, 2018
	Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net
	(in millions)							(in millions)
Southern Company
Other intangible assets subject to amortization:
Customer relationships	$	211	$	(105	)	$	106	$	223	$	(94	)	$	129
Trade names	70		(23		)	47		70		(21		)	49
Storage and transportation contracts	64		(58		)	6		64		(54		)	10
PPA fair value adjustments	371		(60		)	311		405		(61		)	344
Other	12		(7		)	5		11		(5		)	6
Total other intangible assets subject to amortization	$	728	$	(253	)	$	475	$	773	$	(235	)	$	538
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—			75		75		—			75
Total other intangible assets	$	803	$	(253	)	$	550	$	848	$	(235	)	$	613
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	371	$	(60	)	$	311	$	405	$	(61	)	$	344
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156	$	(95	)	$	61	$	156	$	(84	)	$	72
Trade names	26		(8		)	18		26		(7		)	19
Wholesale gas services
Storage and transportation contracts	64		(58		)	6		64		(54		)	10
Total other intangible assets subject to amortization	$	246	$	(161	)	$	85	$	246	$	(145	)	$	101

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Six Months Ended
	June 30, 2019
	(in millions)
Southern Company	$	15	$	32
Southern Power(a)	$	4	$	10
Southern Company Gas
Gas marketing services(b)	$	6	$	12
Wholesale gas services(a)	2		4
Southern Company Gas total	$	8	$	16

(a) Recorded as a reduction to operating revenues.

(b) Included in depreciation and amortization.

Restricted Cash

At December 31, 2018, Georgia Power had restricted cash related to the redemption of pollution control revenue bonds, which were redeemed in January 2019. See Note (F) under "Financing Activities" for additional information. At both June 30, 2019 and December 31, 2018, Southern Company Gas had restricted cash held as collateral for worker's compensation, life insurance, and long-term disability insurance.

The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the registrants that had restricted cash at June 30, 2019 and/or December 31, 2018:

	Southern Company			Southern Company Gas
	(in millions)
At June 30, 2019
Cash and cash equivalents	$	1,383		$	56
Restricted cash:
Other accounts and notes receivable	4			4
Total cash, cash equivalents, and restricted cash	$	1,386	(*)	$	60

(*) Total does not add due to rounding.

	Southern Company		Georgia Power		Southern Company Gas
	(in millions)
At December 31, 2018
Cash and cash equivalents	$	1,396	$	4	$	64
Cash and cash equivalents held for sale	9		—		—
Restricted cash:
Restricted cash	—		108		—
Other accounts and notes receivable	114		—		6
Total cash, cash equivalents, and restricted cash	$	1,519	$	112	$	70

Natural Gas for Sale

Southern Company Gas, with the exception of Nicor Gas, carries natural gas inventory on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Southern Company Gas recorded adjustments of $7 million and $10 million for the three and six months ended June 30, 2019, respectively, and no material adjustments for the comparable periods in 2018.

Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. Nicor Gas had no inventory decrement at June 30, 2019.

Asset Retirement Obligations

See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding AROs.

Details of the AROs included in the condensed balance sheets of Southern Company, Alabama Power, and Mississippi Power at June 30, 2019 are shown in the following table. There were no material changes in the AROs of Georgia Power or Southern Power during the first six months of 2019.

	Southern Company			Alabama Power			Mississippi Power
	(in millions)
Balance at December 31, 2018	$	9,394		$	3,210		$	160
Liabilities incurred	6			—			—
Liabilities settled	(142		)	(43		)	(17		)
Accretion	197			70			2
Cash flow revisions	452			308			59
Balance at June 30, 2019	$	9,907		$	3,545		$	204

In June 2019, Alabama Power recorded an increase of approximately $308 million to its AROs primarily related to the CCR Rule and the related state rule based on management's completion of closure designs during the second quarter 2019 for all but two of its ash pond facilities. Mississippi Power also recorded an increase of approximately $58 million to its AROs related to the CCR Rule, primarily associated with the ash pond facility at Plant Greene County, which is jointly owned with Alabama Power. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and increases in the estimated ash volumes. The cost estimate for the remaining Alabama Power ash pond facilities will be updated within the next 12 months and the change could be material.

As further analysis is performed and additional details are developed with respect to ash pond closures, the traditional electric operating companies expect to periodically update their ARO cost estimates. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, Southern Company's and the traditional electric operating companies' results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of these matters cannot be determined at this time.

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Regulatory Matters

6 Months Ended

Jun. 30, 2019

Regulated Operations [Abstract]

REGULATORY MATTERS

REGULATORY MATTERS

See Note 2 to the financial statements in Item 8 of the Form 10-K for additional information relating to regulatory matters.

The recovery balances for certain of Alabama Power's, Georgia Power's, and Mississippi Power's regulatory clauses at June 30, 2019 and December 31, 2018 were as follows:

Regulatory Clause	Balance Sheet Line Item	June 30, 2019		December 31, 2018
		(in millions)
Alabama Power
Rate CNP Compliance	Deferred under recovered regulatory clause revenues	$	—	$	42
	Customer accounts receivable	10		—
Rate CNP PPA	Deferred under recovered regulatory clause revenues	25		25
Retail Energy Cost Recovery(*)	Deferred under recovered regulatory clause revenues	—		109
	Customer accounts receivable	8		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	19		20
Georgia Power
Fuel Cost Recovery	Receivables – under recovered fuel clause revenues	$	69	$	115
Mississippi Power
Fuel Cost Recovery	Over recovered regulatory clause liabilities	$	9	$	8

(*)

In accordance with an accounting order issued on February 5, 2019 by the Alabama PSC, Alabama Power utilized $75 million of the 2018 Rate RSE refund liability to reduce the Rate ECR under recovered balance. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information.

Alabama Power

Environmental Accounting Order

On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" and Note 6 in Item 8 of the Form 10-K for additional information.

Georgia Power

Rate Plans

On June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.

Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:

Tariff	2020		2021		2022
	(in millions)
Traditional base:
Levelized	$	209	$	—	$	—
CCR AROs	158		140		227
Environmental Compliance Cost Recovery	165		—		—
Demand-Side Management	14		2		1
Municipal Franchise Fee	17		3		5
Total(*)	$	563	$	145	$	234

(*) Totals may not add due to rounding.

Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:

• Continuation of an allowed retail ROE range of 10.00% to 12.00%.

• Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the remaining one-third are retained by Georgia Power.

• Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.

Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be determined at this time.

Integrated Resource Plan

In 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan, including 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 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. In accordance with the Georgia PSC's order, costs incurred of approximately $50 million have been recorded as a regulatory asset.

On July 16, 2019, the Georgia PSC voted to approve Georgia Power's triennial Integrated Resource Plan (2019 IRP) as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.

In the 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively, at June 30, 2019), as well as any unusable materials and supplies inventory balances, upon retirement to a regulatory asset. Recovery of each unit's net book value will continue through December 31, 2019 as provided in the 2013 ARP.

For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case as follows: (i) the net book values of Plant Mitchell Unit 3 (approximately $8 million at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book

values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The ultimate outcome of these matters cannot be determined at this time.

Also in the 2019 IRP, the Georgia PSC rejected 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. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future Integrated Resource Plan. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Georgia Power's or Southern Company's financial statements.

Additionally, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $135 million at June 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.

The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.

See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.

Nuclear Construction

See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, the joint ownership agreements and related funding agreement, VCM reports, and the NCCR tariff.

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. In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work,

certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

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 June 30, 2019(b)	(5.2		)
Remaining estimate to complete(a)	$	3.2

(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 $2.0 billion had been incurred through June 30, 2019.

In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the estimated total project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.

As construction continues and testing and system turnover activities increase, challenges with management of contractors, subcontractors, and vendors; supervision of craft labor and related craft labor productivity, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures, or components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.

The April 2019 cost and schedule validation process established target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the approved in-service dates. To support that strategy, monthly production and activity target values will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers (particularly electrical and pipefitter craft labor), as well as additional supervision and other field support resources, must be retained and deployed.

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 submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, 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 regulatory-approved 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

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

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 in conjunction with the nineteenth VCM report, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 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 at pre-established prices, 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 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.

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 June 30, 2019, Georgia Power had recovered approximately $2.0 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. In December 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.

In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the 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 in 2018 and are estimated to have negative earnings impacts of approximately $70 million in 2019 and an aggregate of approximately $630 million from 2020 to 2022.

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.

In February 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. In March 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. In December 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 August 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).

On April 30, 2019, as requested by the staff of the Georgia PSC, Georgia Power reported the results of the cost and schedule validation process to the Georgia PSC. On August 30, 2019, Georgia Power will file its twentieth VCM report concurrently with its twenty-first VCM report with the Georgia PSC, which will reflect the capital cost forecast discussed previously and request approval of $1.2 billion of construction capital costs incurred from June 30, 2018 through June 30, 2019. In addition, on June 20, 2019, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a settlement agreement related to the administrative claim filed in the Westinghouse bankruptcy proceedings. Accordingly, in the twentieth/twenty-first VCM report, Georgia Power will also request approval of the $51.6 million of associated expenditures previously deferred by the Georgia PSC.

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

DOE Financing

At June 30, 2019, Georgia Power had borrowed $3.46 billion related to Plant Vogtle Units 3 and 4 costs as provided through the Amended and Restated Loan Guarantee Agreement and related multi-advance credit facilities among Georgia Power, the DOE, and the FFB, which provide for borrowings of up to approximately $5.130 billion, subject to the satisfaction of certain conditions. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

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

Mississippi Power

Municipal and Rural Association Tariff

On May 7, 2019, the FERC accepted Mississippi Power's March 28, 2019 request for a decrease in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with its wholesale customers resolving all matters related to the Kemper County energy facility similar to the retail rate settlement agreement approved by the Mississippi PSC in February 2018 and reflecting the impacts of the Tax Reform Legislation. Pursuant to the MRA settlement agreement, base rates decreased $3.7 million annually, effective January 1, 2019.

Environmental Compliance Overview Plan

On July 9, 2019, Mississippi Power filed a request with the Mississippi PSC for a Certificate of Public Convenience and Necessity to complete certain environmental compliance projects, primarily associated with the Plant Daniel coal units co-owned 50% with Gulf Power. The total estimated cost is approximately $125 million, with Mississippi Power's share of approximately $66 million being proposed for recovery through its ECO Plan. Approximately $17 million of Mississippi Power's share is associated with ash pond closure and is reflected in Mississippi Power's ARO liabilities. See Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information on Mississippi Power's ECO Plan. See Note (A) under "Asset Retirement Obligations" for additional information on AROs and Note (C) under "Other Matters – Mississippi Power" herein for additional information on Gulf Power's ownership in Plant Daniel.

Kemper County Energy Facility

As the mining permit holder, Liberty Fuels Company, LLC 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 in Item 8 of the Form 10-K for additional information.

During the second quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $6 million ($5 million after tax), respectively, 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 dismantlement costs, net of salvage), 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 at $7 million for the remainder of 2019 and $2 million to $6 million annually in 2020 through 2023.

In addition, Mississippi Power constructed the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery and 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 and could have a material impact on Southern Company's financial statements.

In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of 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. In connection with the DOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the Kemper County energy facility. The ultimate outcome of these matters cannot be determined at this time; however, they could have a material impact on Mississippi Power's and Southern Company's financial statements.

Southern Company Gas

Rate Proceedings

Nicor Gas

In November 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% to 54% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation.

On April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with the Staff of the Illinois Commission, including a ROE of 9.86% and an equity ratio of 54%. Also on April 16, 2019, Nicor Gas filed its rebuttal testimony with the Illinois Commission incorporating the stipulation agreement and addressing the remaining items outstanding with the other two intervenors. As a result of the stipulation agreement and rebuttal testimony, the revised requested annual revenue increase is $180 million.

The Illinois Commission is expected to rule on the requested increase by early October 2019, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.

Atlanta Gas Light

On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia PSC requesting a $96 million increase in annual base rate revenues. The requested increase is based on a forward-looking test year for the 12-month period ending July 31, 2020, a ROE of 10.75% with an earnings band based on a ROE between 10.55% and 10.95%, and a continued equity ratio of 55%. The filing also requests the continuation of the Georgia rate adjustment mechanism, as previously authorized. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter on December 19, 2019 with the new rates becoming effective January 1, 2020. The ultimate outcome of this matter cannot be determined at this time.

Virginia Natural Gas

In December 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 Tax Reform Legislation. This approval also required Virginia Natural Gas to issue customer refunds, via bill credits, for $14 million related to 2018 tax benefits deferred as a regulatory liability, current, on the balance sheet at December 31, 2018. These customer refunds were completed in the first quarter 2019.

Regulatory Infrastructure Programs

Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and help ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs. 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 for timely recovery of capital expenditures for specific infrastructure replacement programs.

Virginia Natural Gas

On April 8, 2019, Virginia Natural Gas filed an application with the Virginia Commission to amend and extend its Steps to Advance Virginia's Energy program. The proposal would allow Virginia Natural Gas to continue replacing aging pipeline infrastructure and increase its authorized investment under the currently-approved plan. Virginia Natural Gas seeks to amend its currently-approved plan by increasing the authorized investment in 2019 from $35 million to $40 million and to extend the plan for an additional five years until 2024, with proposed annual investments of $50 million in 2020, $60 million in 2021, and $70 million in each year from 2022 through 2024, for a maximum total investment over the six-year term (2019 through 2024) of $370 million. The proposed investment schedule would also allow for variances of up to $6 million in 2019, $8 million in 2020, $9 million in 2021, and $10 million in each year from 2022 through 2024, with a total potential net variance of up to $10 million allowed for the program. The Virginia Commission is expected to rule on the request in the fourth quarter 2019. The ultimate outcome of this matter cannot be determined at this time.

Affiliate Asset Management Agreements

On March 15, 2019, the Virginia Commission approved an extension of Virginia Natural Gas' asset management agreement with Sequent to March 31, 2021.

FERC Matters

See Note 2 to the financial statements under "FERC Matters – Open Access Transmission Tariff" in Item 8 of the Form 10-K for additional information.

On June 28, 2019, the FERC approved a settlement agreement between Alabama Municipal Electric Authority and Cooperative Energy and SCS and the traditional electric operating companies agreeing to an OATT rate reduction based on a 10.6% ROE, with a retroactive effective date of May 10, 2018, and a five-year moratorium on these parties seeking changes to the OATT formula rate. The terms of the OATT settlement agreement will not have a material impact on the financial statements of any of the traditional electric operating companies or Southern Company.

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Contingencies

6 Months Ended

Jun. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

CONTINGENCIES

CONTINGENCIES

See Note 3 to the financial statements in Item 8 of the Form 10-K for information relating to various lawsuits and other contingencies.

General Litigation Matters

Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, 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

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 against each registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.

Southern Company

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 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 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. Also in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition. In March 2018, the court 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. In April 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. In August 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal.

In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. 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. In April 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, 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. In May 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.

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

Georgia Power

In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. In 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court. Georgia Power filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted in 2017. In June 2018, the Georgia Supreme Court affirmed the judgment of the Georgia Court of Appeals and remanded the case to the trial court for further proceedings. Following a motion by Georgia Power, on February 13, 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling to address certain terms the court previously held were ambiguous as used in the Georgia PSC's orders. The order entered by the Superior Court of Fulton County also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Georgia Power also filed a notice of appeal with the Georgia Court of Appeals regarding the Superior Court of Fulton County's February 2019 order. Georgia Power believes the plaintiffs' claims have no merit. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether conditional class certification will be upheld and the ultimate composition of any class and whether any losses would be subject to recovery from any municipalities. The ultimate outcome of this matter cannot be determined at this time.

Mississippi Power

In May 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 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, which were denied by the arbitration panel on May 10, 2019. Southern Company and Mississippi Power believe this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity. The ultimate outcome of this matter cannot be determined at this time.

In November 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 by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint on March 14, 2019. The amended complaint included four additional plaintiffs and additional claims for

gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint. Mississippi Power believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. The ultimate outcome of this matter cannot be determined at this time.

Southern Power

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 withheld payment of approximately $26 million to the construction contractor, which placed a lien on the Roserock facility for the same amount. In 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas against XL Insurance America, Inc. and North American Elite Insurance Company seeking recovery from an insurance policy for damages resulting from the hail event and McCarthy's installation practices. In June 2018, the court 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. Separate lawsuits were filed between Roserock and McCarthy, as well as other parties, and that litigation was consolidated in the U.S. District Court for the Western District of Texas. On April 18, 2019, Roserock and the parties to the state and federal lawsuits executed a settlement agreement and mutual release that resolved both lawsuits. Following execution of the agreement, the lawsuits were dismissed, Southern Power paid McCarthy the amounts previously withheld, and McCarthy released its lien. As part of the settlement, Roserock received funds that covered all related legal costs, damages, and the replacement costs of certain solar panels. Funds received by Southern Power in excess of the initial replacement costs were recognized as a gain and included in other income (expense), net in 2019. A portion of the pre-tax gain was allocated to noncontrolling interests and Southern Power recognized a $12 million after-tax gain.

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 in Illinois and Georgia have each 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.

Georgia Power's environmental remediation liability was $18 million and $23 million as of June 30, 2019 and December 31, 2018, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.

Southern Company Gas' environmental remediation liability was $283 million and $294 million as of June 30, 2019 and December 31, 2018, respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities, with the exception of one site representing $2 million of the total accrued remediation costs.

The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of Southern Company, Georgia Power, or Southern Company Gas.

Nuclear Fuel Disposal Costs

In 2014, Alabama Power and Georgia Power filed lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley, Hatch, and Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. On June 12, 2019, the Court of Federal Claims granted Alabama Power's and Georgia Power's motion for summary judgment on damages not disputed by the U.S. government, awarding those undisputed damages to Alabama Power and Georgia Power. However, those undisputed damages are not collectible and no amounts will be recognized in the financial statements until the court enters final judgment on the remaining damages. The final outcome of these matters cannot be determined at this time. However, Alabama Power and Georgia Power expect to credit any recoveries for the benefit of customers in accordance with direction from their respective PSC; therefore, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.

Other Matters

Alabama Power

On May 17, 2019, the Alabama Department of Environmental Management (ADEM) issued a proposed administrative order assessing a penalty of $250,000 to Alabama Power for unpermitted discharge of fluids and/or pollutants to groundwater and/or soils at Plant Gadsden. The proposed order also requires the submission to the ADEM of a plan with a schedule for implementation of a comprehensive groundwater investigation, an assessment of corrective measures, a report evaluating any deficiencies at the facility that may have led to the unpermitted discharge, and quarterly progress reports. Alabama Power is awaiting finalization of the order and the ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on Alabama Power's net income.

Mississippi Power

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 by the FERC and the Mississippi PSC, and cannot be determined at this time. See Note (K) under "Southern Company" for information regarding the sale of Gulf Power.

Southern Company Gas

The future performance of Southern Company Gas' natural gas storage facility consisting of two salt dome caverns in Louisiana, as well as Southern Company Gas' two other natural gas storage facilities located in California and Texas, could be impacted by ongoing changes in the U.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and may imply an impact on future rates and/or asset values. Southern Company Gas is evaluating these recent market transactions for impacts on its plans to return one of the salt dome caverns in Louisiana back to service in 2021. Sustained diminished natural gas storage values could trigger impairment of one or all of these natural gas storage facilities, which have a combined net book value of $438 million at June 30, 2019. The ultimate outcome of these matters cannot be determined at this time, but could have a material impact on Southern Company's and Southern Company Gas' financial statements.

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Revenue from Contracts with Customers

6 Months Ended

Jun. 30, 2019

Revenue from Contract with Customer [Abstract]

REVENUE FROM CONTRACTS WITH CUSTOMERS

REVENUE FROM CONTRACTS WITH CUSTOMERS

The registrants generate revenues from a variety of sources, some of which are excluded from the scope of ASC 606, Revenue from Contracts with Customers (ASC 606), such as leases, derivatives, and certain cost recovery mechanisms. See Note 1 to the financial statements under "Recently Adopted Accounting Standards – Revenue" in Item 8 of the Form 10-K for additional information on the adoption of ASC 606 for revenue from contracts with customers and Note 1 to the financial statements under "Revenues" and "Other Taxes" in Item 8 of the Form 10-K for additional information on the revenue policies of the registrants. For additional information on revenues accounted for under other accounting guidance, see Notes (J) and (L) for energy-related derivative contracts and lessor revenues, respectively, Note 1 to the financial statements under "Revenues – Southern Company Gas" in Item 8 of the Form 10-K for alternative revenue programs at the natural gas distribution utilities, and Note 2 to the financial statements in Item 8 of the Form 10-K for cost recovery mechanisms.

The following tables disaggregate revenue sources for the three and six months ended June 30, 2019 and 2018:

	For the Three Months Ended June 30, 2019		For the Three Months Ended June 30, 2018			For the Six Months Ended June 30, 2019		For the Six Months Ended June 30, 2018
	(in millions)
Southern Company
Operating revenues
Retail electric revenues(a)
Residential	$	1,488	$	1,579		$	2,776	$	3,118
Commercial	1,258		1,315			2,350		2,557
Industrial	763		814			1,440		1,569
Other	31		32			57		64
Natural gas distribution revenues(b)	562		642			1,724		1,865
Alternative revenue programs(c)	1		(4		)	—		(27		)
Total retail electric and gas distribution revenues	$	4,103	$	4,378		$	8,347	$	9,146
Wholesale energy revenues(d)(e)	410		464			777		937
Wholesale capacity revenues(e)	132		152			264		302
Other natural gas revenues(f)(g)	126		68			439		476
Other revenues(h)	327		565			683		1,138
Total operating revenues	$	5,098	$	5,627		$	10,510	$	11,999

(a) Retail electric revenues include $8 million, $18 million, $16 million, and $36 million of revenues accounted for as leases for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, and a (net reduction) or net increase of $(14) million, $68 million, $(117) million and $101 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, from certain cost recovery mechanisms that are not accounted for as revenue under ASC 606.

(b) Natural gas distribution revenues include $5 million for each of the three months ended June 30, 2019 and 2018 and $8 million for each of the six months ended June 30, 2019 and 2018 of revenues not accounted for under ASC 606.

(c) Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(d) Wholesale energy revenues include $30 million, $61 million, $82 million, and $155 million of revenues accounted for as derivatives for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, primarily related to physical energy sales in the wholesale electricity market.

(e) Wholesale energy revenues include $115 million, $118 million, $182 million, and $187 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, and wholesale capacity revenues include $22 million, $31 million, $47 million, and $61 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, related to PPAs accounted for as leases.

(f) Other natural gas revenues related to Southern Company Gas' energy and risk management activities are presented net of the related costs of those activities and include gross third-party revenues of $1.2 billion, $1.3 billion, $3.1 billion, and $3.3 billion for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of which $0.8 billion, $0.7 billion, $2.0 billion, and $1.8 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (M) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.

(g) Other natural gas revenues include $10 million and $27 million for the three and six months ended June 30, 2019, respectively, of revenues not accounted for under ASC 606, including $8 million and $16 million, respectively, of revenues accounted for as leases.

(h) Other revenues include $89 million, $89 million, $180 million, and $183 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of revenues not accounted for under ASC 606, including $28 million, $33 million, $59 million, and $66 million, respectively, accounted for as leases.

	Alabama Power		Georgia Power		Mississippi Power
	(in millions)
For the Three Months Ended June 30, 2019
Operating revenues
Retail revenues(a)(b)
Residential	$	588	$	831	$	69
Commercial	418		767		73
Industrial	366		327		70
Other	6		21		3
Total retail electric revenues	$	1,378	$	1,946	$	215
Wholesale energy revenues(c)	41		14		93
Wholesale capacity revenues	25		22		1
Other revenues(b)(d)	69		135		4
Total operating revenues	$	1,513	$	2,117	$	313
For the Three Months Ended June 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	557	$	785	$	65
Commercial	402		749		68
Industrial	372		335		76
Other	7		20		3
Total retail electric revenues	$	1,338	$	1,889	$	212
Wholesale energy revenues(c)	71		26		77
Wholesale capacity revenues	25		13		1
Other revenues(b)(d)	69		120		7
Total operating revenues	$	1,503	$	2,048	$	297

(a) Retail revenues at Alabama Power, Georgia Power, and Mississippi Power include a net increase or (net reduction) of $(11) million, $(5) million, and $2 million, respectively, for the three months ended June 30, 2019 and $78 million, $3 million, and $(1) million, respectively, for the three months ended June 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606.

(b) Retail revenues and other revenues at Georgia Power include $8 million and $11 million, respectively, for the three months ended June 30, 2019 and $18 million and $33 million, respectively, for the three months ended June 30, 2018 of revenues accounted for as leases.

(c) Wholesale energy revenues at Alabama Power, Georgia Power, and Mississippi Power include $3 million, $4 million, and $1 million, respectively, for the three months ended June 30, 2019 and $4 million, $5 million, and $1 million, respectively, for the three months ended June 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market.

(d) Other revenues at Alabama Power and Georgia Power include $31 million and $30 million, respectively, for the three months ended June 30, 2019 and $26 million and $26 million, respectively, for the three months ended June 30, 2018 of revenues not accounted for under ASC 606.

	Alabama Power		Georgia Power		Mississippi Power
	(in millions)
For the Six Months Ended June 30, 2019
Operating revenues
Retail revenues(a)(b)
Residential	$	1,128	$	1,519	$	129
Commercial	772		1,440		138
Industrial	679		616		145
Other	13		39		6
Total retail electric revenues	$	2,592	$	3,614	$	418
Wholesale energy revenues(c)	135		27		170
Wholesale capacity revenues	51		40		2
Other revenues(b)(d)	143		270		10
Total operating revenues	$	2,921	$	3,951	$	600
For the Six Months Ended June 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	1,127	$	1,529	$	125
Commercial	774		1,466		130
Industrial	710		650		146
Other	13		43		5
Total retail electric revenues	$	2,624	$	3,688	$	406
Wholesale energy revenues(c)	172		66		176
Wholesale capacity revenues	49		27		5
Other revenues(b)(d)	131		227		11
Total operating revenues	$	2,976	$	4,008	$	598

(a) Retail revenues at Alabama Power, Georgia Power, and Mississippi Power include a net increase or (net reduction) of $(68) million, $(52) million, and $3 million, respectively, for the six months ended June 30, 2019 and $125 million, $12 million, and $(8) million, respectively, for the six months ended June 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606.

(b) Retail revenues and other revenues at Georgia Power include $16 million and $23 million, respectively, for the six months ended June 30, 2019 and $36 million and $66 million, respectively, for the six months ended June 30, 2018 of revenues accounted for as leases.

(c) Wholesale energy revenues at Alabama Power, Georgia Power, and Mississippi Power include $6 million, $8 million, and $1 million, respectively, for the six months ended June 30, 2019 and $9 million, $13 million, and $2 million, respectively, for the six months ended June 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market.

(d)

Other revenues at Alabama Power and Georgia Power include $59 million and $61 million, respectively, for the six months ended June 30, 2019 and $52 million and $53 million, respectively, for the six months ended June 30, 2018 of revenues not accounted for under ASC 606.

	For the Three Months Ended June 30, 2019		For the Three Months Ended June 30, 2018		For the Six Months Ended June 30, 2019		For the Six Months Ended  June 30, 2018
	(in millions)
Southern Power
PPA capacity revenues(a)	$	125	$	144	$	252	$	282
PPA energy revenues(a)	291		302		518		556
Non-PPA revenues(b)	91		106		177		221
Other revenues	3		3		6		5
Total operating revenues	$	510	$	555	$	953	$	1,064

(a) PPA capacity revenues include $39 million, $47 million, $80 million, and $94 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, and PPA energy revenues include $125 million, $127 million, $198 million, and $203 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, related to PPAs accounted for as leases.

(b)

Non-PPA revenues include $22 million, $50 million, $67 million, and $129 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of revenues from short-term sales related to physical energy sales from uncovered capacity in the wholesale electricity market.

	For the Three Months Ended June 30, 2019		For the Three Months Ended June 30, 2018			For the Six Months Ended June 30, 2019		For the Six Months Ended  June 30, 2018
	(in millions)
Southern Company Gas
Operating revenues
Natural gas distribution revenues(a)
Residential	$	229	$	273		$	830	$	933
Commercial	65		76			235		268
Transportation	213		228			469		505
Industrial	5		7			22		24
Other	50		58			168		135
Alternative revenue programs(b)	1		(4		)	—		(27		)
Total natural gas distribution revenues	$	563	$	638		$	1,724	$	1,838
Gas pipeline investments(c)	8		8			16		16
Wholesale gas services(d)	48		(15		)	114		131
Gas marketing services(e)	58		89			287		359
Other revenues	12		10			22		25
Total operating revenues	$	689	$	730		$	2,163	$	2,369

(a) Natural gas distribution revenues include $5 million for each of the three months ended June 30, 2019 and 2018 and $8 million for each of the six months ended June 30, 2019 and 2018 of revenues not accounted for under ASC 606.

(b) Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(c) Revenues from gas pipeline investments include $8 million and $16 million for the three and six months ended June 30, 2019, respectively, accounted for as leases.

(d) Wholesale gas services revenues are presented net of the related costs associated with its energy trading and risk management activities. Operating revenues, as presented, include gross third-party revenues of $1.2 billion, $1.3 billion, $3.1 billion, and $3.3 billion for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of which $0.8 billion, $0.7 billion, $2.0 billion, and $1.8 billion, respectively, relates to contracts accounted for as derivatives. See Note (M) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.

(e)

Gas marketing services include $2 million for the three months ended June 30, 2019 and $11 million and $4 million for the six months ended June 30, 2019 and 2018, respectively, of revenues not accounted for under ASC 606.

Contract Balances

The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers as of June 30, 2019 and December 31, 2018:

	Receivables				Contract Assets				Contract Liabilities
	June 30, 2019		December 31, 2018		June 30, 2019		December 31, 2018		June 30, 2019		December 31, 2018
	(in millions)
Southern Company(*)	$	2,343	$	2,630	$	70	$	102	$	58	$	32
Alabama Power	629		520		—		—		10		12
Georgia Power	807		721		30		58		26		7
Mississippi Power	93		100		—		—		7		—
Southern Power	119		118		—		—		1		11
Southern Company Gas	550		952		—		—		1		2

(*) Includes amounts related to held for sale investments.

As of June 30, 2019 and December 31, 2018, Georgia Power had contract assets primarily related to unregulated service agreements where payment is contingent on project completion and fixed retail customer bill programs where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over the one-year contract term. Alabama Power had contract liabilities for outstanding performance obligations primarily related to extended service agreements. Contract liabilities for Georgia Power and Southern Power relate to cash collections recognized in advance of revenue for certain unregulated service agreements and certain levelized PPAs, respectively. Mississippi Power had contract liabilities for cash collections recognized in advance of revenue for operating agreements associated with a tolling arrangement accounted for as a sales-type lease. Southern Company's unregulated distributed generation business had $32 million and $39 million of contract assets and $14 million and $11 million of contract liabilities at June 30, 2019 and December 31, 2018, respectively, remaining for outstanding performance obligations.

The following table reflects revenue from contracts with customers recognized in the three and six months ended June 30, 2019 included in the contract liability at December 31, 2018:

	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
	(in millions)
Southern Company	$	11	$	27
Southern Power	1		11

Revenues recognized in the three and six months ended June 30, 2019, which were included in contract liabilities at December 31, 2018, were immaterial for Alabama Power, Georgia Power, and Southern Company Gas.

Remaining Performance Obligations

The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized when the performance obligations are satisfied during the contract term. These contracts primarily relate to PPAs whereby the traditional electric operating companies and Southern Power provide electricity and generation capacity to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain fixed price contracts. Registrants with revenues from contracts with customers related to these performance obligations remaining at June 30, 2019 expect the revenues to be recognized as follows:

	2019 (remaining)		2020		2021		2022		2023		Thereafter
	(in millions)
Southern Company	$	282	$	490	$	320	$	311	$	302	$	2,230
Alabama Power	11		23		27		23		22		140
Georgia Power	27		51		44		31		31		83
Southern Power	169		295		270		276		269		2,154

Revenues expected to be recognized for performance obligations remaining at June 30, 2019 were immaterial for Mississippi Power.

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Consolidated Entities and Equity Method Investments

6 Months Ended

Jun. 30, 2019

Regulated Operations [Abstract]

CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS

CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS

Southern Power

Consolidated Variable Interest Entities

See Note 7 to the financial statements in Item 8 of the Form 10-K for additional information on Southern Power's consolidated VIEs.

Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests. In 2018, Southern Power sold noncontrolling interests in SP Solar and SP Wind. Southern Power continues to consolidate each entity, as the primary beneficiary of each VIE, since it controls the most significant activities of each entity, including operating and maintaining their assets. Transfers and sales of the assets in the VIEs are subject to limited partner consent and the liabilities are non-recourse to the general credit of Southern Power. Liabilities consist of customary working capital items and do not include any long-term debt.

SP Solar

At June 30, 2019, SP Solar had total assets of $6.5 billion, total liabilities of $374 million, and noncontrolling interests of $1.1 billion. Cash distributions from SP Solar are allocated 67% to Southern Power and 33% to Global Atlantic in accordance with their partnership interest percentage. Under the terms of the limited partnership agreement, distributions without limited partner consent are limited to available cash and SP Solar is obligated to distribute all such available cash to its partners each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves.

SP Wind

At June 30, 2019, SP Wind had total assets of $2.5 billion, total liabilities of $136 million, and noncontrolling interests of $46 million. Under the terms of the limited liability agreement, distributions without Class A member consent are limited to available cash and SP Wind is obligated to distribute all such available cash to its members each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves. Cash distributions from SP Wind are generally allocated 60% to Southern Power and 40% to the three financial investors in accordance with the limited liability agreement.

Equity Method Investments

In June 2019, Southern Power made investments in certain legal entities that are considered VIEs but for which Southern Power is not the primary beneficiary because it does not control the most significant activities of the VIEs. These investments are accounted for as equity method investments. The total carrying amount of these investments is $144 million as of June 30, 2019, of which $116 million relates to membership interests in DSGP, an affiliate of Bloom Energy, that owns and operates fuel cell generation facilities in Delaware. Southern Power expects to consolidate DSGP, and record a noncontrolling interest, pending FERC approval of the transfer of the facilities. FERC approval is expected to occur in the third quarter 2019; however, the ultimate outcome of this matter cannot be determined at this time.

Southern Company Gas

See Note 7 to the financial statements in Item 8 of the Form 10-K for additional information on Southern Company Gas' equity method investments.

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments as of June 30, 2019 and December 31, 2018 and related income from those investments for the three- and six-month periods ended June 30, 2019 and 2018 were as follows:

Investment Balance	June 30, 2019		December 31, 2018
	(in millions)
SNG	$	1,243	$	1,261
Atlantic Coast Pipeline	101		83
PennEast Pipeline	77		71
Other(*)	88		123
Total	$	1,509	$	1,538

(*) Decrease primarily relates to the sale of Triton.

Earnings from Equity Method Investments	Three Months Ended June 30, 2019			Three Months Ended June 30, 2018		Six Months Ended June 30, 2019			Six Months Ended June 30, 2018
	(in millions)
SNG	$	32		$	27	$	74		$	66
Atlantic Coast Pipeline	3			1		6			3
PennEast Pipeline	1			1		3			2
Other(*)	(5		)	2		(3		)	3
Total	$	31		$	31	$	80		$	74

(*) Decrease primarily relates to the sale of Triton.

Triton

On May 29, 2019, Southern Company Gas sold its investment in Triton, a cargo container leasing company that was aggregated into Southern Company Gas' all other segment. This disposition resulted in a pre-tax loss of $6 million and a net after-tax gain of $7 million as a result of reversing a $13 million federal income tax valuation allowance.

SNG

Selected financial information of SNG for the three and six months ended June 30, 2019 and 2018 is as follows:

Income Statement Information	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
	(in millions)
Revenues	$	155	$	146	$	321	$	306
Operating income	86		60		192		159
Net income	64		54		148		132

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Financing

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

FINANCING

FINANCING

Bank Credit Arrangements

Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional electric operating companies' revenue bonds. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of June 30, 2019 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia

Power, and $40 million at Mississippi Power). In addition, at June 30, 2019, the traditional electric operating companies had approximately $272 million (comprised of approximately $87 million at Alabama Power and $185 million at Georgia Power) of revenue bonds outstanding that were required to be remarketed within the next 12 months. See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K and "Financing Activities" herein for additional information.

The following table outlines the committed credit arrangements by company as of June 30, 2019:

	Expires
Company	2019		2020		2022		2024		Total		Unused		Due within One Year
	(in millions)
Southern Company(a)	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—
Alabama Power	3		500		—		800		1,303		1,303		3
Georgia Power	—		—		—		1,750		1,750		1,736		—
Mississippi Power	—		—		150		—		150		150		—
Southern Power(b)	—		—		—		600		600		561		—
Southern Company Gas(c)	—		—		—		1,750		1,750		1,745		—
Other	—		30		—		—		30		30		30
Southern Company Consolidated	$	3	$	530	$	150	$	6,900	$	7,583	$	7,524	$	33

(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 $30 million was unused at June 30, 2019. 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 $1.25 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.

As reflected in the table above, in May 2019, Southern Company, Alabama Power, Georgia Power, and Southern Power each amended and restated certain of their multi-year credit arrangements, which, among other things, extended the maturity dates to 2024. Southern Power also decreased its borrowing capacity from $750 million to $600 million. In addition, Southern Company Gas Capital, along with Nicor Gas, amended and restated its multi-year credit arrangement to extend the maturity date to 2024 and decrease the aggregate borrowing capacity from $1.9 billion to $1.75 billion. In June 2019, Mississippi Power entered into a new $50 million credit arrangement that matures in 2022 and amended its existing credit arrangements, which, among other things, extended the maturity dates from 2019 to 2022.

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.

DOE Loan Guarantee Borrowings

See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding Georgia Power's 2014 loan guarantee agreement.

Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power and the DOE entered into a loan guarantee agreement in 2014 and the Amended and Restated Loan Guarantee Agreement in March 2019. Under the Amended and Restated Loan Guarantee Agreement, the DOE has agreed to guarantee the obligations of Georgia Power under note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities (FFB Credit Facilities). Under the FFB Credit Facilities, Georgia Power may make term loan borrowings through the FFB in an amount up to approximately $5.130 billion, provided that total

aggregate borrowings under the FFB Credit Facilities may not exceed 70% of (i) Eligible Project Costs minus (ii) approximately $1.492 billion (reflecting the amounts received by Georgia Power under the Guarantee Settlement Agreement less the Customer Refunds).

In March 2019, Georgia Power made borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million at an interest rate of 3.213% through the final maturity date of February 20, 2044. At June 30, 2019, Georgia Power had a total of $3.46 billion of borrowings outstanding under the FFB Credit Facilities.

All borrowings under the FFB Credit Facilities are full recourse to Georgia Power, and Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under its guarantee. Georgia Power's reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on Georgia Power's ability to grant liens on other property.

In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, 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 Eligible Project Costs.

Upon satisfaction of all conditions described above, advances may be requested on a quarterly basis through 2023. The final maturity date for each advance under the FFB Credit Facilities is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facilities will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.

Under the Amended and Restated Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default.

In the event certain mandatory prepayment events occur, the FFB's commitment to make further advances under the FFB Credit Facilities will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facilities over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle Services Agreement or rejection of the Vogtle Services Agreement in any Westinghouse bankruptcy if Georgia Power does not maintain access to intellectual property rights under the related intellectual property licenses; (ii) termination of the Bechtel Agreement, unless the Vogtle Owners enter into a replacement agreement; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC or by Georgia Power; (iv) failure of the holders of 90% of the ownership interests in Plant Vogtle Units 3 and 4 to vote to continue construction following certain schedule extensions; (v) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facilities; or (vi) loss of or failure to receive necessary regulatory approvals. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facilities. In addition, if Georgia Power discontinues construction of Plant Vogtle Units 3 and 4, Georgia Power would be obligated to immediately repay a portion of the outstanding borrowings under the FFB Credit Facilities to the extent such outstanding borrowings exceed 70% of Eligible Project Costs, net of the proceeds received by Georgia Power under the Guarantee Settlement Agreement less the Customer Refunds. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facilities. Under the FFB Credit Facilities, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.

In connection with any cancellation of Plant Vogtle Units 3 and 4, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume Georgia Power's rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of Georgia Power's ownership interest in Plant Vogtle Units 3 and 4.

Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2019:

Company	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)	$	2,100	$	—	$	—	$	—	$	—
Alabama Power	200		—		—		—		—
Georgia Power	—		513		223		835		3
Mississippi Power	—		43		—		—		—
Other	—		—		25		—		9
Southern Company Consolidated	$	2,300	$	556	$	248	$	835	$	12

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

(b) Represents the Southern Company parent entity.

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.

Southern Company

In January 2019, Southern Company repaid a $250 million short-term uncommitted bank credit arrangement and a $1.5 billion short-term floating rate bank loan.

Also in January 2019, 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, following the completion of the cash tender offers, in February 2019, Southern Company completed the redemption of all of the Series 2018A Notes, 1.85% Notes, and Series 2014B Notes remaining outstanding.

Georgia Power

In January 2019, 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 2019, Georgia Power reoffered to the public the following pollution control revenue bonds that previously had been purchased and held by Georgia Power:

• $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;

• 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; and

• $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.

In April 2019, Georgia Power purchased and held the following pollution control revenue bonds. In May 2019, Georgia Power reoffered these pollution control revenue bonds to the public.

• $55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1994;

• $30 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1995;

• $20 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Ninth Series 1994; and

• $10 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 1994.

In June 2019, Georgia Power reoffered to the public $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, which had been previously purchased and held by Georgia Power.

Also in June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR.

Mississippi Power

In March 2019, Mississippi Power reoffered to the public $43 million of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002, which previously had been purchased and held by Mississippi Power.

Southern Power

In May 2019, Southern Power repaid at maturity a $100 million aggregate principal amount short-term bank loan.

Earnings per Share

For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under stock-based compensation plans. See Note 12 to the financial statements in Item 8 of the Form 10-K for information on stock-based compensation plans. The effect of stock-based compensation plans was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:

	Three Months Ended June 30, 2019	Three Months Ended June 30, 2018	Six Months Ended June 30, 2019	Six Months Ended June 30, 2018
	(in millions)
As reported shares	1,044	1,014	1,041	1,012
Effect of stock-based compensation	8	—	8	5
Diluted shares	1,052	1,014	1,049	1,017

There were no stock-based compensation awards that were not included in the diluted earnings per share calculation because they were anti-dilutive for the three and six months ended June 30, 2019 and an immaterial amount of such awards was not included for the six months ended June 30, 2018. For the three months ended June 30, 2018, approximately 5.3 million shares of stock-based compensation awards were not included in the diluted earnings per share calculation because they were anti-dilutive.

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Income Taxes

6 Months Ended

Jun. 30, 2019

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

See Note 10 to the financial statements in Item 8 of the Form 10-K for additional tax information.

Current and Deferred Income Taxes

Tax Credit Carryforwards

Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $2.0 billion as of June 30, 2019 compared to $2.4 billion as of December 31, 2018.

The federal ITC and PTC carryforwards begin expiring in 2034 and 2032, respectively, but are expected to be fully utilized by 2023. The estimated tax credit utilization reflects the projected taxable gains on the various sale transactions describe in Note (K) and could be further delayed by numerous factors, including the acquisition of additional renewable projects, the purchase of rights to additional PTCs of Plant Vogtle Units 3 and 4 pursuant to certain joint ownership agreements, and changes in taxable income projections. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

Effective Tax Rate

Details of significant changes in the effective tax rate for the applicable registrants are provided herein.

Southern Company

Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity and flowback of excess deferred income taxes at the regulated utilities, and federal income tax benefits from ITCs and PTCs, primarily at Southern Power.

Southern Company's effective tax rate was 33.5% for the six months ended June 30, 2019 compared to an effective tax benefit rate of (3.2)% for the corresponding period in 2018. The effective tax rate increase was primarily due to the tax impact from the sale of Gulf Power in 2019 and the 2018 charge to earnings related to the construction of Plant Vogtle Units 3 and 4. See Note (K) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.

Georgia Power

Georgia Power's effective tax rate was 21.7% for the six months ended June 30, 2019 compared to a benefit rate of (53.5)% for the corresponding period in 2018. The effective tax rate increase was primarily due to the 2018 charge to earnings related to the construction of Plant Vogtle Units 3 and 4, partially offset by an increase in state ITCs. See Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.

Mississippi Power

Mississippi Power's effective tax rate was 14.0% for the six months ended June 30, 2019 compared to 18.7% for the corresponding period in 2018. The effective tax rate decrease was primarily due to an increase in the flowback of excess deferred income taxes as a result of a settlement agreement reached with wholesale customers under the MRA tariff. See Note (B) under "Mississippi Power" for additional information.

Southern Power

Southern Power's effective tax benefit rate was (35.5)% for the six months ended June 30, 2019 compared to (1,386.5)% for the corresponding period in 2018. The effective tax benefit rate decrease was primarily due to reductions of tax benefits from wind PTCs primarily as a result of the 2018 sale of the noncontrolling tax equity interest in SPC Wind and from changes in state apportionment rates following the reorganization of Southern Power's legal entities that own and operate certain solar facilities, partially offset by the net tax benefits from the sale of Plant Nacogdoches in 2019. See Note (K) and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power" for additional information.

Southern Company Gas

Southern Company Gas' effective tax rate was 18.0% for the six months ended June 30, 2019 compared to 39.1% for the corresponding period in 2018. This decrease was primarily related to an increase in the flowback of excess deferred income taxes in 2019, primarily at Atlanta Gas Light as previously authorized by the Georgia PSC, and the reversal of a federal tax valuation allowance in connection with Southern Company Gas' sale of its investment in Triton in 2019, as well as the tax impacts of the Southern Company Gas Dispositions in 2018. See Note (E) under "Southern Company Gas" and Notes 2 and 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.

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Retirement Benefits

6 Months Ended

Jun. 30, 2019

Retirement Benefits [Abstract]

RETIREMENT BENEFITS

RETIREMENT BENEFITS

The Southern Company system has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2019. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.

See Note 11 to the financial statements in Item 8 of the Form 10-K for additional information.

On each registrant's condensed statements of income, the service cost component of net periodic benefit costs is included in other operations and maintenance expenses and all other components of net periodic benefit costs are included in other income (expense), net. Components of the net periodic benefit costs for the three and six months ended June 30, 2019 and 2018 are presented in the following tables.

Three Months Ended June 30, 2019	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	73		$	17		$	18		$	3		$	1		$	6
Interest cost	123			29			39			5			2			9
Expected return on plan assets	(221		)	(52		)	(73		)	(10		)	(3		)	(15		)
Amortization:
Prior service costs	1			1			1			—			—			—
Regulatory asset	—			—			—			—			—			4
Net (gain)/loss	30			9			11			2			—			—
Net periodic pension cost (income)	$	6		$	4		$	(4	)	$	—		$	—		$	4
Postretirement Benefits
Service cost	$	4		$	1		$	1		$	—		$	—		$	—
Interest cost	17			4			6			1			—			3
Expected return on plan assets	(17		)	(7		)	(6		)	(1		)	—			(1		)
Amortization:
Prior service costs	1			1			—			—			—			—
Regulatory asset	—			—			—			—			—			1
Net (gain)/loss	—			—			—			—			—			(1		)
Net periodic postretirement benefit cost	$	5		$	(1	)	$	1		$	—		$	—		$	2

Six Months Ended June 30, 2019	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	146		$	34		$	37		$	6		$	3		$	12
Interest cost	246			57			78			11			3			18
Expected return on plan assets	(442		)	(103		)	(146		)	(20		)	(5		)	(30		)
Amortization:
Prior service costs	1			1			1			—			—			(1		)
Regulatory asset	—			—			—			—			—			7
Net (gain)/loss	60			18			22			3			—			1
Net periodic pension cost (income)	$	11		$	7		$	(8	)	$	—		$	1		$	7
Postretirement Benefits
Service cost	$	9		$	2		$	2		$	—		$	—		$	1
Interest cost	34			8			13			2			—			5
Expected return on plan assets	(33		)	(13		)	(12		)	(1		)	—			(3		)
Amortization:
Prior service costs	2			2			—			—			—			—
Regulatory asset	—			—			—			—			—			3
Net (gain)/loss	(1		)	—			—			—			—			(2		)
Net periodic postretirement benefit cost	$	11		$	(1	)	$	3		$	1		$	—		$	4

Three Months Ended June 30, 2018	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	89		$	20		$	21		$	4		$	2		$	8
Interest cost	116			25			35			5			2			9
Expected return on plan assets	(235		)	(53		)	(74		)	(10		)	(2		)	(17		)
Amortization:
Prior service costs	1			1			1			—			—			—
Regulatory asset	—			—			—			—			—			4
Net (gain)/loss	54			13			17			2			—			3
Net periodic pension cost (income)	$	25		$	6		$	—		$	1		$	2		$	7
Postretirement Benefits
Service cost	$	6		$	2		$	1		$	1		$	—		$	—
Interest cost	18			4			7			1			—			3
Expected return on plan assets	(17		)	(7		)	(7		)	(1		)	—			(2		)
Amortization:
Prior service costs	1			1			1			—			—			—
Regulatory asset	—			—			—			—			—			2
Net (gain)/loss	4			1			2			—			—			—
Net periodic postretirement benefit cost	$	12		$	1		$	4		$	1		$	—		$	3

Six Months Ended June 30, 2018	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	179		$	39		$	43		$	8		$	4		$	16
Interest cost	232			50			70			10			3			19
Expected return on plan assets	(471		)	(104		)	(148		)	(20		)	(5		)	(35		)
Amortization:
Prior service costs	2			1			1			—			—			(1		)
Regulatory asset	—			—			—			—			—			7
Net (gain)/loss	107			27			34			5			1			6
Net periodic pension cost (income)	$	49		$	13		$	—		$	3		$	3		$	12
Postretirement Benefits
Service cost	$	12		$	3		$	3		$	1		$	—		$	1
Interest cost	37			8			14			2			—			5
Expected return on plan assets	(34		)	(13		)	(13		)	(1		)	—			(4		)
Amortization:
Prior service costs	3			2			1			—			—			—
Regulatory asset	—			—			—			—			—			3
Net (gain)/loss	7			1			4			—			—			—
Net periodic postretirement benefit cost	$	25		$	1		$	9		$	2		$	—		$	5

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Fair Value Measurements

6 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

As of June 30, 2019, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using:
As of June 30, 2019:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives(a)	$	270	$	177	$	12	$	—	$	459
Foreign currency derivatives	—		60		—		—		60
Investments in trusts:(b)(c)
Domestic equity	703		124		—		—		827
Foreign equity	62		206		—		—		268
U.S. Treasury and government agency securities	—		307		—		—		307
Municipal bonds	—		72		—		—		72
Pooled funds – fixed income	—		16		—		—		16
Corporate bonds	23		299		—		—		322
Mortgage and asset backed securities	—		74		—		—		74
Private equity	—		—		—		54		54
Cash and cash equivalents	1		—		—		—		1
Other	27		2		—		—		29
Cash equivalents	841		5		—		—		846
Other investments	9		17		—		—		26
Total	$	1,936	$	1,359	$	12	$	54	$	3,361
Liabilities:
Energy-related derivatives(a)	$	405	$	189	$	22	$	—	$	616
Interest rate derivatives	—		52		—		—		52
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		21		—		21
Total	$	405	$	264	$	43	$	—	$	712

	Fair Value Measurements Using:
As of June 30, 2019:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Alabama Power
Assets:
Energy-related derivatives	$	—	$	6	$	—	$	—	$	6
Nuclear decommissioning trusts:(b)
Domestic equity	456		113		—		—		569
Foreign equity	62		60		—		—		122
U.S. Treasury and government agency securities	—		21		—		—		21
Municipal bonds	—		1		—		—		1
Corporate bonds	23		141		—		—		164
Mortgage and asset backed securities	—		25		—		—		25
Private equity	—		—		—		54		54
Other	7		—		—		—		7
Cash equivalents	430		5		—		—		435
Other investments	—		17		—		—		17
Total	$	978	$	389	$	—	$	54	$	1,421
Liabilities:
Energy-related derivatives	$	—	$	18	$	—	$	—	$	18
Georgia Power
Assets:
Energy-related derivatives	$	—	$	6	$	—	$	—	$	6
Nuclear decommissioning trusts:(b)(c)
Domestic equity	247		1		—		—		248
Foreign equity	—		143		—		—		143
U.S. Treasury and government agency securities	—		286		—		—		286
Municipal bonds	—		71		—		—		71
Corporate bonds	—		158		—		—		158
Mortgage and asset backed securities	—		50		—		—		50
Other	20		2		—		—		22
Total	$	267	$	717	$	—	$	—	$	984
Liabilities:
Energy-related derivatives	$	—	$	43	$	—	$	—	$	43
Interest rate derivatives	—		37		—		—		37
Total	$	—	$	80	$	—	$	—	$	80

	Fair Value Measurements Using:
As of June 30, 2019:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Cash equivalents	170		—		—		—		170
Total	$	170	$	3	$	—	$	—	$	173
Liabilities:
Energy-related derivatives	$	—	$	19	$	—	$	—	$	19
Southern Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	—	$	2
Foreign currency derivatives	—		60		—		—		60
Cash equivalents	177		—		—		—		177
Total	$	177	$	62	$	—	$	—	$	239
Liabilities:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		21		—		21
Total	$	—	$	27	$	21	$	—	$	48
Southern Company Gas
Assets:
Energy-related derivatives(a)	$	270	$	160	$	12	$	—	$	442
Non-qualified deferred compensation trusts:
Domestic equity	—		10		—		—		10
Foreign equity	—		4		—		—		4
Pooled funds – fixed income	—		16		—		—		16
Cash equivalents	1		—		—		—		1
Total	$	271	$	190	$	12	$	—	$	473
Liabilities:
Energy-related derivatives(a)	$	405	$	105	$	22	$	—	$	532

(a) Energy-related derivatives exclude cash collateral of $178 million.

(b) Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

(c) Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of June 30, 2019, approximately $30 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds, including reinvested interest

and dividends and excluding the funds' expenses, increased (decreased) by the amounts shown in the table below for the three and six months ended June 30, 2019 and 2018. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.

	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018			Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
	(in millions)
Southern Company	$	75	$	14		$	227	$	4
Alabama Power	38		15			125		10
Georgia Power	37		(1		)	102		(6		)

Valuation Methodologies

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

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

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. See Note 6 to the financial statements under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

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

As of June 30, 2019, the fair value measurements of private equity investments held in Alabama Power's nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient totaled $54 million and unfunded commitments related to the private equity investments totaled $45 million. Private equity funds include funds-of-funds that invest in high-quality private equity funds across several market sectors, funds that invest in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.

As of June 30, 2019, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas(*)
	(in millions)
Long-term debt, including securities due within one year:
Carrying amount	$	42,596	$	7,922	$	10,969	$	1,618	$	5,011	$	5,916
Fair value	45,394		8,717		11,749		1,657		5,261		6,420

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

The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas.

Commodity Contracts with Level 3 Valuation Inputs

As of June 30, 2019, the fair value of Southern Company Gas' Level 3 physical natural gas forward contracts was $10 million. Since commodity contracts classified as Level 3 typically include a combination of observable and unobservable components, the changes in fair value may include amounts due in part to observable market factors, or changes to assumptions on the unobservable components. The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period.

	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	(in millions)
Beginning balance	$	(19	)	$	—
Transfers to Level 3	(3		)	(33		)
Changes in fair value	12			23
Ending balance	$	(10	)	$	(10	)

Changes in fair value of Level 3 instruments represent changes in gains and losses for the periods that are reported on Southern Company Gas' statements of income in natural gas revenues.

The valuation of certain commodity contracts requires the use of certain unobservable inputs. All forward pricing used in the valuation of such contracts is directly based on third-party market data, such as broker quotes and exchange settlements, when that data is available. If third-party market data is not available, then industry standard methodologies are used to develop inputs that maximize the use of relevant observable inputs and minimize the use of unobservable inputs. Observable inputs, including some forward prices used for determining fair value, reflect the best available market information. Unobservable inputs are updated using industry standard techniques such as extrapolation, combining observable forward inputs supplemented by historical market and other relevant data. Level 3 physical natural gas forward contracts include unobservable forward price inputs (ranging from $0.09

to $1.39 per mmBtu). Forward price increases (decreases) as of June 30, 2019 would have resulted in higher (lower) values on a net basis.

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Derivatives

6 Months Ended

Jun. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES

DERIVATIVES

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. 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. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information.

Energy-Related Derivatives

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

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

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

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

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

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

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

At June 30, 2019, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:

	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)
Southern Company(*)	536	2023	2029
Alabama Power	88	2022	—
Georgia Power	200	2022	—
Mississippi Power	101	2023	—
Southern Power	8	2020	—
Southern Company Gas(*)	139	2021	2029

(*) Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 4.0 billion mmBtu and short natural gas positions of 3.9 billion mmBtu as of June 30, 2019, which is also included in Southern Company's total volume.

In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 25 million mmBtu for Southern Company, which includes 4 million mmBtu for Alabama Power, 8 million mmBtu for Georgia Power, 4 million mmBtu for Mississippi Power, and 9 million mmBtu for Southern Power.

For cash flow hedges of energy-related derivatives, the estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to earnings for the 12-month period ending June 30, 2020 are immaterial for all registrants.

Interest Rate Derivatives

Southern Company and certain subsidiaries may enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the

same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

At June 30, 2019, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date	Fair Value Gain (Loss) at June 30, 2019
	(in millions)					(in millions)
Cash Flow Hedges of Forecasted Debt
Georgia Power	$	250	3-month LIBOR	2.23%	March 2025	$	(6	)
Georgia Power	250		3-month LIBOR	2.39%	September 2029	(10		)
Georgia Power	250		3-month LIBOR	2.40%	March 2030	(9		)
Georgia Power	250		3-month LIBOR	2.48%	February 2044	(12		)
Fair Value Hedges of Existing Debt
Southern Company(*)	300		2.75%	3-month LIBOR+0.92%	June 2020	(1		)
Southern Company(*)	1,500		2.35%	1-month LIBOR+0.87%	July 2021	(14		)
Georgia Power	200		4.25%	3-month LIBOR+2.46%	December 2019	(1		)
Southern Company Consolidated	$	3,000				$	(53	)

(*) Represents the Southern Company parent entity.

The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the 12-month period ending June 30, 2020 are $(18) million for Southern Company and immaterial for all other registrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2046 for the Southern Company parent entity, 2035 for Alabama Power, 2044 for Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.

Foreign Currency Derivatives

Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

At June 30, 2019, the following foreign currency derivatives were outstanding:

	Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at June 30, 2019
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	14
Southern Power	564		3.78%	500		1.85%	June 2026	23
Total	$	1,241		€	1,100			$	37

The estimated pre-tax gains (losses) related to Southern Power's foreign currency derivatives expected to be reclassified from accumulated OCI to earnings for the 12-month period ending June 30, 2020 are $(23) million.

Derivative Financial Statement Presentation and Amounts

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

The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:

	As of June 30, 2019						As of December 31, 2018
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Southern Company
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	7		$	57		$	8		$	23
Other deferred charges and assets/Other deferred credits and liabilities	9			34			9			26
Assets held for sale, current/Liabilities held for sale, current	—			—			—			6
Total derivatives designated as hedging instruments for regulatory purposes	$	16		$	91		$	17		$	55
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	7		$	3		$	7
Other deferred charges and assets/Other deferred credits and liabilities	—			1			1			2
Interest rate derivatives:
Other current assets/Other current liabilities	—			50			—			19
Other deferred charges and assets/Other deferred credits and liabilities	—			2			—			30
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	60			—			75			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	61		$	83		$	79		$	81
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	286		$	298		$	561		$	575
Other deferred charges and assets/Other deferred credits and liabilities	156			219			180			325
Total derivatives not designated as hedging instruments	$	442		$	517		$	741		$	900
Gross amounts recognized	$	519		$	691		$	837		$	1,036
Gross amounts offset(a)	$	(328	)	$	(506	)	$	(524	)	$	(801	)
Net amounts recognized in the Balance Sheets(b)	$	191		$	185		$	313		$	235

	As of June 30, 2019						As of December 31, 2018
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Alabama Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	4		$	11		$	3		$	4
Other deferred charges and assets/Other deferred credits and liabilities	2			7			3			6
Total derivatives designated as hedging instruments for regulatory purposes	$	6		$	18		$	6		$	10
Gross amounts recognized	$	6		$	18		$	6		$	10
Gross amounts offset	$	(3	)	$	(3	)	$	(4	)	$	(4	)
Net amounts recognized in the Balance Sheets	$	3		$	15		$	2		$	6
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	26		$	2		$	8
Other deferred charges and assets/Other deferred credits and liabilities	5			17			4			13
Total derivatives designated as hedging instruments for regulatory purposes	$	6		$	43		$	6		$	21
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	37		$	—		$	2
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	37		$	—		$	2
Gross amounts recognized	$	6		$	80		$	6		$	23
Gross amounts offset	$	(6	)	$	(6	)	$	(6	)	$	(6	)
Net amounts recognized in the Balance Sheets	$	—		$	74		$	—		$	17

	As of June 30, 2019						As of December 31, 2018
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	10		$	1		$	3
Other deferred charges and assets/Other deferred credits and liabilities	2			9			2			6
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	19		$	3		$	9
Gross amounts recognized	$	3		$	19		$	3		$	9
Gross amounts offset	$	(3	)	$	(3	)	$	(2	)	$	(2	)
Net amounts recognized in the Balance Sheets	$	—		$	16		$	1		$	7
Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	3		$	3		$	6
Other deferred charges and assets/Other deferred credits and liabilities	—			1			1			2
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	60			—			75			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	61		$	27		$	79		$	31
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	—		$	—		$	—
Total derivatives not designated as hedging instruments	$	1		$	—		$	—		$	—
Gross amounts recognized	$	62		$	27		$	79		$	31
Gross amounts offset	$	(1	)	$	(1	)	$	(3	)	$	(3	)
Net amounts recognized in the Balance Sheets	$	61		$	26		$	76		$	28

	As of June 30, 2019						As of December 31, 2018
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Southern Company Gas
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	1		$	10		$	2		$	8
Other deferred charges and assets/Other deferred credits and liabilities	—			1			—			1
Total derivatives designated as hedging instruments for regulatory purposes	$	1		$	11		$	2		$	9
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	—		$	4		$	—		$	1
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	4		$	—		$	1
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	285		$	298		$	559		$	574
Other deferred charges and assets/Other deferred credits and liabilities	156			219			180			325
Total derivatives not designated as hedging instruments	$	441		$	517		$	739		$	899
Gross amounts of recognized	$	442		$	532		$	741		$	909
Gross amounts offset(a)	$	(315	)	$	(493	)	$	(508	)	$	(785	)
Net amounts recognized in the Balance Sheets(b)	$	127		$	39		$	233		$	124

(a) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $178 million and $277 million as of June 30, 2019 and December 31, 2018, respectively.

(b) Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $8 million as of December 31, 2018.

At June 30, 2019 and December 31, 2018, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at June 30, 2019
Derivative Category and Balance Sheet Location	Southern Company(*)			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas(*)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(48	)	$	(11	)	$	(25	)	$	(10	)	$	(2	)
Other regulatory assets, deferred	(23		)	(5		)	(12		)	(6		)	—
Other regulatory liabilities, current	6			3			—			—			3
Total energy-related derivative gains (losses)	$	(65	)	$	(13	)	$	(37	)	$	(16	)	$	1

(*) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $12 million at June 30, 2019.

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2018
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(19	)	$	(3	)	$	(6	)	$	(2	)	$	(8	)
Other regulatory assets, deferred	(16		)	(3		)	(9		)	(4		)	—
Assets held for sale, current	(6		)	—			—			—			—
Other regulatory liabilities, current	1			—			—			—			1
Total energy-related derivative gains (losses)	$	(40	)	$	(6	)	$	(15	)	$	(6	)	$	(7	)

For the three and six months ended June 30, 2019 and 2018, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:

Gain (Loss) Recognized in OCI on Derivative	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)						(in millions)
Southern Company
Energy-related derivatives	$	(6	)	$	—		$	(6	)	$	12
Interest rate derivatives	(37		)	—			(37		)	(2		)
Foreign currency derivatives	(1		)	(73		)	(39		)	(21		)
Total	$	(44	)	$	(73	)	$	(82	)	$	(11	)
Georgia Power
Interest rate derivatives	$	(37	)	$	—		$	(37	)	$	—
Total	$	(37	)	$	—		$	(37	)	$	—
Southern Power
Energy-related derivatives	$	(2	)	$	(1	)	$	(2	)	$	10
Foreign currency derivatives	(1		)	(73		)	(39		)	(21		)
Total	$	(3	)	$	(74	)	$	(41	)	$	(11	)

For the three and six months ended June 30, 2019 and 2018, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other registrants.

For the three and six months ended June 30, 2019 and 2018, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)						(in millions)
Southern Company
Total depreciation and amortization	$	755		$	783		$	1,506		$	1,552
Gain (loss) on energy-related cash flow hedges(a)	(1		)	1			(4		)	2
Total interest expense, net of amounts capitalized	(429		)	(470		)	(859		)	(928		)
Gain (loss) on interest rate cash flow hedges(a)	(5		)	(6		)	(9		)	(11		)
Gain (loss) on foreign currency cash flow hedges(a)	(6		)	(7		)	(12		)	(12		)
Gain (loss) on interest rate fair value hedges(b)	19			(7		)	33			(31		)
Total other income (expense), net	99			78			176			138
Gain (loss) on foreign currency cash flow hedges(a)(c)	16			(73		)	(8		)	(37		)
Southern Power
Total depreciation and amortization	$	119		$	125		$	237		$	240
Gain (loss) on energy-related cash flow hedges(a)	(1		)	1			(4		)	2
Total interest expense, net of amounts capitalized	(41		)	(46		)	(84		)	(93		)
Gain (loss) on foreign currency cash flow hedges(a)	(6		)	(7		)	(12		)	(12		)
Total other income (expense), net	40			2			41			5
Gain (loss) on foreign currency cash flow hedges(a)(c)	16			(73		)	(8		)	(37		)

(a) Reclassified from accumulated OCI into earnings.

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

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

For the three and six months ended June 30, 2019 and 2018, the pre-tax effects of cash flow and fair value hedge accounting on income for energy-related derivatives and interest rate derivatives were immaterial for the traditional electric operating companies and Southern Company Gas.

As of June 30, 2019 and December 31, 2018, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

	Carrying Amount of the Hedged Item						Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	As of June 30, 2019			As of December 31, 2018			As of June 30, 2019		As of December 31, 2018
	(in millions)						(in millions)
Southern Company
Securities due within one year	$	(499	)	$	(498	)	$	1	$	2
Long-term debt	(2,087		)	(2,052		)	7		41
Georgia Power
Securities due within one year	$	(499	)	$	(498	)	$	1	$	2

For the three and six months ended June 30, 2019 and 2018, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:

		Gain (Loss)
		Three Months Ended June 30,						Six Months Ended June 30,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2019			2018			2019		2018
		(in millions)						(in millions)
Southern Company
Energy-related derivatives:	Natural gas revenues(*)	$	50		$	(28	)	$	83	$	(43	)
	Cost of natural gas	(5		)	2			3		4
Total derivatives in non-designated hedging relationships		$	45		$	(26	)	$	86	$	(39	)
Southern Company Gas
Energy-related derivatives:	Natural gas revenues(*)	$	50		$	(28	)	$	83	$	(43	)
	Cost of natural gas	(5		)	2			3		4
Total derivatives in non-designated hedging relationships		$	45		$	(26	)	$	86	$	(39	)

(*) Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for all periods presented.

For the three and six months ended June 30, 2019 and 2018, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies and Southern Power.

Contingent Features

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At June 30, 2019, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

For the registrants with interest rate derivatives at June 30, 2019, the fair value of interest rate derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, was immaterial. At June 30, 2019, the fair value of energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial for all registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade. Following the sale of Gulf Power to NextEra Energy, Gulf Power is continuing to participate in the Southern Company power pool for a defined transition period that, subject to certain potential adjustments, is scheduled to end on January 1, 2024.

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

Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Alabama Power and Southern Power may be required to post collateral. At June 30, 2019, cash

collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At June 30, 2019, cash collateral held on deposit in broker margin accounts was $178 million.

The registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The registrants only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk. Prior to entering into a physical transaction, Southern Company Gas assigns physical wholesale counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch Ratings Inc. ratings, commercially available credit reports, and audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the 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.

Southern Company Gas also utilizes master 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 it 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. Master 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 master netting and cash collateral agreements include such provisions. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

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

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Acquisitions and Dispositions

6 Months Ended

Jun. 30, 2019

Business Combinations [Abstract]

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS

See Note 15 to the financial statements in Item 8 of the Form 10-K for additional information.

Southern Company

On January 1, 2019, Southern Company completed the sale of all of the capital stock of Gulf Power to 700 Universe, LLC, a wholly-owned subsidiary of NextEra Energy, for an aggregate cash purchase price of approximately $5.8 billion (less $1.3 billion of indebtedness assumed), subject to customary working capital adjustments. The preliminary gain associated with the sale of Gulf Power totaled $2.5 billion pre-tax ($1.3 billion after tax). The assets and liabilities of Gulf Power were classified as assets held for sale and liabilities held for sale on Southern Company's balance sheet as of December 31, 2018.

On July 22, 2019, PowerSecure completed the sale of its utility infrastructure services business unit for approximately $71 million, subject to customary working capital adjustments. The related assets and liabilities were classified as held for sale on Southern Company's balance sheet as of June 30, 2019. In contemplation of this sale, a goodwill impairment charge of $32 million was recorded in the second quarter 2019.

See "Assets Held for Sale" herein for additional information.

Southern Power

Construction Projects

During the six months ended June 30, 2019, Southern Power completed construction of and placed in service the 385-MW Plant Mankato expansion and continued construction of two other projects as described in the table below. Total aggregate construction costs, excluding acquisition costs, are expected to be between $405 million and $450 million for the Wildhorse Mountain and Reading facilities. At June 30, 2019, total costs of construction incurred for these projects were $186 million and are included in CWIP. The ultimate outcome of these matters cannot be determined at this time.

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Projects Completed During the Six Months Ended June 30, 2019
Mankato expansion(a)	Natural Gas	385	Mankato, MN	May 2019	20 years
Projects Under Construction as of June 30, 2019
Wildhorse Mountain(b)	Wind	100	Pushmataha County, OK	Fourth quarter 2019	20 years
Reading(c)	Wind	200	Osage and Lyon Counties, KS	Second quarter 2020	12 years

(a) In November 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato, including this expansion that was completed during May 2019. This transaction is subject to state commission approvals and is expected to close in fall 2019. The expansion unit started providing energy under a PPA with Northern States Power on June 1, 2019. See "Sales of Natural Gas and Biomass Plants" below.

(b) In May 2018, Southern Power purchased 100% of the Wildhorse Mountain facility. Southern Power entered into a tax equity partnership in June 2019 with funding of tax equity amounts expected to occur upon commercial operation.

(c) 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. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the class B membership interests.

Development Projects

Southern Power continues to evaluate and refine the deployment of wind turbine equipment purchased in 2016 and 2017 to potential joint development and construction projects as well as the amount of MW capacity to be

constructed. During the six months ended June 30, 2019, certain wind turbine equipment was sold, resulting in a gain on the sale of approximately $14 million.

On June 14, 2019, Southern Power entered into an agreement with Bloom Energy to acquire a majority interest in its affiliate DSGP, which owns and operates fuel cell generation facilities in Delaware, for a total amount not to exceed $173 million. In June 2019, Southern Power, through an affiliate, contributed a total of $116 million in exchange for Class B membership interests in DSGP, with the remainder expected to be contributed by the end of 2019. FERC approval of the transfer of the facilities is expected to occur in the third quarter 2019; however, the ultimate outcome of this matter cannot be determined at this time.

Sales of Natural Gas and Biomass Plants

On June 13, 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for an aggregate cash purchase price of approximately $461 million, including working capital adjustments. This sale resulted in an $88 million after-tax gain.

On May 4, 2019, Southern Power achieved commercial operation of the 385-MW natural gas expansion unit at Plant Mankato and started providing energy under a PPA with Northern States Power on June 1, 2019. The sale of Plant Mankato to Northern States Power remains subject to Minnesota and North Dakota state commission approvals and is expected to close in fall 2019. If these state commission approvals are not obtained by October 1, 2019, either party has the option to terminate the sale, which, if elected, would result in the payment of a $15 million termination fee by Northern States Power to Southern Power. The ultimate outcome of this matter cannot be determined at this time. The assets and liabilities of Plant Mankato are classified as assets held for sale and liabilities held for sale on Southern Company's and Southern Power's balance sheets as of June 30, 2019 and December 31, 2018. See "Assets Held for Sale" herein for additional information.

Assets Subject to Lien

Under the terms of the PPAs for Plant Mankato, approximately $545 million of assets, primarily related to property, plant, and equipment, are subject to lien at June 30, 2019.

Assets Held for Sale

As discussed above, Southern Company and Southern Power each have assets and liabilities held for sale on their balance sheets at June 30, 2019 and December 31, 2018. Assets and liabilities held for sale have been classified separately on each company's balance sheet at the lower of carrying value or fair value less costs to sell at the time the criteria for held-for-sale classification were met. For assets and liabilities held for sale recorded at fair value on a nonrecurring basis, the fair value of assets held for sale is based primarily on unobservable inputs (Level 3), which includes the agreed upon sales prices in executed sales agreements.

Upon classification as held for sale in November 2018 and April 2019 for Plant Mankato and Plant Nacogdoches, respectively, Southern Power ceased recognizing depreciation and amortization on the long-lived assets to be sold.

The following table provides Southern Company's and Southern Power's major classes of assets and liabilities classified as held for sale at June 30, 2019 and December 31, 2018:

	Southern Company		Southern Power
	(in millions)
At June 30, 2019
Assets Held for Sale:
Current assets	$	58	$	10
Total property, plant, and equipment	588		559
Goodwill and other intangible assets	51		40
Other non-current assets	46		—
Total Assets Held for Sale	$	743	$	609
Liabilities Held for Sale:
Current liabilities	$	36	$	10
Other non-current liabilities	39		—
Total Liabilities Held for Sale	$	75	$	10
At December 31, 2018
Assets Held for Sale:
Current assets	$	393	$	8
Total property, plant, and equipment	4,583		536
Other intangible assets	40		40
Other non-current assets	727		—
Total Assets Held for Sale	$	5,743	$	584
Liabilities Held for Sale:
Current liabilities	$	425	$	15
Long-term debt	1,286		—
Accumulated deferred income taxes	618		—
Other non-current liabilities	932		—
Total Liabilities Held for Sale	$	3,261	$	15

Southern Company and Southern Power each concluded that the sale of their assets, both individually and combined, did not represent a strategic shift in operations that has, or is expected to have, a major effect on its operations and financial results; therefore, none of the assets related to the sales have been classified as discontinued operations for any of the periods presented.

Gulf Power and Southern Power's equity interests in Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) and Plant Nacogdoches represented individually significant components of Southern Company and Southern Power, respectively; therefore, pre-tax profit for these components for the three and six months ended June 30, 2019 and 2018 is presented below:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
	(in millions)
Earnings before income taxes:
Gulf Power	$	—	$	31	$	—	$	87
Southern Power's Florida Plants	$	—	$	14	$	—	$	24
Southern Power's Plant Nacogdoches(*)	$	9	$	7	$	16	$	13

(*)

Earnings before income taxes for Plant Nacogdoches for the three and six months ended June 30, 2019 represents the beginning of the corresponding period through June 13, 2019 (the divestiture date).

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Leases

6 Months Ended

Jun. 30, 2019

Leases [Abstract]

LEASES

LEASES

On January 1, 2019, the registrants adopted the provisions of FASB ASC Topic 842 (as amended), Leases (ASC 842), which require lessees to recognize leases with a term of greater than 12 months on the balance sheet as lease obligations, representing the discounted future fixed payments due, along with right-of-use (ROU) assets that will be amortized over the term of each lease.

The registrants elected the transition methodology provided by ASC 842, whereby the applicable requirements are applied on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. The registrants also elected the package of practical expedients provided by ASC 842 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, the registrants applied the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and elected the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed.

Lessee

As lessee, the registrants lease certain electric generating units (including renewable energy facilities), real estate/land, communication towers, railcars, and other equipment and vehicles. The major categories of lease obligations are as follows:

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Electric generating units	$	1,072	$	150	$	1,580	$	—	$	—	$	—
Real estate/land	800		4		62		2		395		81
Communication towers	147		1		3		—		—		13
Railcars	54		25		27		3		—		—
Other	145		10		14		2		—		—
Total	$	2,218	$	190	$	1,686	$	7	$	395	$	94

Real estate/land leases primarily consist of commercial real estate leases at Southern Company, Georgia Power, and Southern Company Gas and various land leases primarily associated with renewable energy facilities at Southern

Power. The commercial real estate leases have remaining terms of up to 25 years while the land leases have remaining terms of up to 48 years, including renewal periods.

Communication towers are leased for the installation of equipment to provide cellular phone service to customers and to support the automated meter infrastructure programs at the traditional electric operating companies. Communication tower leases have terms of up to 10 years with options to renew for periods up to 20 years.

While renewal options exist in many of the leases, other than for land leases associated with renewable energy facilities, the expected term used in calculating the lease obligation generally reflects only the noncancelable period of the lease as it is not considered reasonably certain that the lease will be extended. The expected term of land leases associated with renewable energy facilities includes renewal periods reasonably certain of exercise resulting in an expected lease term at least equal to the expected life of the renewable energy facilities.

Contracts that Contain a Lease

While not specifically structured as a lease, some of the PPAs at Alabama Power and Georgia Power are deemed to represent a lease of the underlying electric generating units when the terms of the PPA convey the right to control the use of the underlying assets. Amounts recorded for leases of electric generating units are generally based on the amount of scheduled capacity payments due over the remaining term of the affiliate PPA, which varies between four and 18 years. Georgia Power has several PPAs with Southern Power that Georgia Power accounts for as leases with a lease obligation of approximately $660 million at June 30, 2019. The amount paid for energy under these affiliate PPAs reflects a price that would be paid in an arm's-length transaction as those amounts have been reviewed and approved by the Georgia PSC.

Short-term Leases

Leases with an initial term of 12 months or less are not recorded on the balance sheet; the registrants generally recognize lease expense for these leases on a straight-line basis over the lease term.

Residual Value Guarantees

Residual value guarantees exist primarily in railcar leases at Alabama Power and Georgia Power and the amounts probable of being paid under those guarantees are included in the lease payments. All such amounts are immaterial as of June 30, 2019.

Lease and Nonlease Components

For all asset categories, with the exception of electric generating units, gas pipelines, and real estate leases, the registrants combine lease payments and any nonlease components, such as asset maintenance, for purposes of calculating the lease obligation and the right-of-use asset.

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

	As of June 30, 2019
	Southern  Company(*)		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Operating Leases
Operating lease ROU assets, net	$	1,907	$	152	$	1,492	$	7	$	370	$	95
Operating lease obligations - current	$	241	$	48	$	140	$	2	$	22	$	15
Operating lease obligations - non current	1,733		137		1,377		5		373		79
Total operating lease obligations	$	1,974	$	185	$	1,517	$	7	$	395	$	94
Finance Leases
Finance lease ROU assets, net	$	237	$	5	$	142	$	—	$	—	$	—
Finance lease obligations - current	$	24	$	1	$	10	$	—	$	—	$	—
Finance lease obligations - noncurrent	220		4		159		—		—		—
Total finance lease obligations	$	244	$	5	$	169	$	—	$	—	$	—

(*) Includes operating lease ROU assets, net and operating lease obligations classified as held for sale.

Lease costs for the three and six months ended June 30, 2019, which includes both amounts recognized as operations and maintenance expense and amounts capitalized as part of the cost of another asset, are as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended June 30, 2019
Lease cost
Operating lease cost	$	77	$	13	$	50	$	1	$	7	$	5
Finance lease cost:
Amortization of ROU assets	7		—		4		—		—		—
Interest on lease obligations	3		—		4		—		—		—
Total finance lease cost	10		—		8		—		—		—
Short-term lease costs	13		6		6		—		—		—
Variable lease cost	29		1		25		—		1		—
Sublease income	—		—		—		—		—		—
Total lease cost	$	129	$	20	$	89	$	1	$	8	$	5
For the Six Months Ended June 30, 2019
Lease cost
Operating lease cost	$	147	$	20	$	99	$	1	$	14	$	9
Finance lease cost:
Amortization of ROU assets	14		—		7		—		—		—
Interest on lease obligations	6		—		9		—		—		—
Total finance lease cost	20		—		16		—		—		—
Short-term lease costs	30		11		12		—		—		—
Variable lease cost	48		1		41		—		3		—
Sublease income	—		—		—		—		—		—
Total lease cost	$	245	$	32	$	168	$	1	$	17	$	9

Georgia Power has variable lease payments that are based on the amount of energy produced by certain renewable generating facilities subject to PPAs.

Other information with respect to cash and noncash activities related to leases, as well as weighted-average lease terms and discount rates, is as follows:

	For the Six Months Ended June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Other information
Cash paid for amounts included in the measurements of lease obligations:
Operating cash flows from operating leases	$	129	$	20	$	75	$	1	$	12	$	9
Operating cash flows from finance leases	2		—		10		—		—		—
Financing cash flows from finance leases	16		—		3		—		—		—
ROU assets obtained in exchange for new operating lease obligations	55		5		13		—		—		13
ROU assets obtained in exchange for new finance lease obligations	33		1		28		—		—		—

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
Weighted-average remaining lease term in years:
Operating leases	14.0		3.6		10.5		7.0		33.5		9.7
Finance leases	18.3		12.8		11.0		N/A		N/A		N/A
Weighted-average discount rate:
Operating leases	4.53	%	3.33	%	4.46	%	4.06	%	5.68	%	3.73	%
Finance leases	5.05	%	3.67	%	10.69	%	N/A		N/A		N/A

Maturities of lease liabilities are as follows:

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Maturity Analysis
Operating leases:
2019 (remaining)	$	178	$	33	$	129	$	1	$	13	$	9
2020	295		53		203		2		22		17
2021	279		52		198		1		23		16
2022	268		52		196		1		23		13
2023	204		4		197		1		24		11
Thereafter	1,661		2		990		2		849		49
Total	2,885		196		1,913		8		954		115
Less: Present value discount	911		11		396		1		559		21
Operating lease obligations	$	1,974	$	185	$	1,517	$	7	$	395	$	94
Finance leases:
2019 (remaining)	$	16	$	—	$	16	$	—	$	—	$	—
2020	33		1		28		—		—		—
2021	27		1		25		—		—		—
2022	23		1		25		—		—		—
2023	18		1		25		—		—		—
Thereafter	266		1		165		—		—		—
Total	383		5		284		—		—		—
Less: Present value discount	139		—		115		—		—		—
Finance lease obligations	$	244	$	5	$	169	$	—	$	—	$	—

Payments made under PPAs at Georgia Power for energy generated from certain renewable energy facilities accounted for as operating and finance leases are considered variable lease costs and are therefore not reflected in the above maturity analysis. As of June 30, 2019, Southern Company and Southern Power have additional operating leases, primarily for land, that have not yet commenced. These operating leases are expected to commence during the remainder of 2019 through 2022, with lease terms of up to 31 years, and have estimated total obligations of $81 million.

For additional information on each registrant's operating lease obligations at December 31, 2018, see Note 9 to the financial statements in Item 8 of the Form 10-K.

Lessor

With the exception of Southern Company Gas, the registrants are each considered lessors in various arrangements that have been determined to contain a lease due to the customer's ability to control the use of the underlying asset owned by the applicable registrant. For the traditional electric operating companies, these arrangements consist of outdoor lighting contracts accounted for as operating leases with initial terms of up to five years, after which the contracts renew on a month-to-month basis at the customer's option. For Mississippi Power, these arrangements also include tolling arrangements related to electric generating units accounted for as sales-type leases with terms of up to 20 years. For Southern Power, these arrangements consist of PPAs related to electric generating units, including renewable energy facilities, accounted for as operating leases with terms of up to 28 years. For Southern Company, these arrangements also include PPAs related to fuel cells accounted for as operating leases with terms of up to 15

years. Southern Company Gas is the lessor in operating leases related to gas pipelines with remaining terms of up to 24 years.

Lease income for the three and six months ended June 30, 2019 is as follows:

	Southern Company		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended June 30, 2019
Lease income - interest income on sales-type leases	$	2	$	—	$	2	$	—	$	—
Lease income - operating leases	67		19		—		39		9
Variable lease income	115		—		—		125		—
Total lease income	$	184	$	19	$	2	$	164	$	9
For the Six Months Ended June 30, 2019
Lease income - interest income on sales-type leases	$	5	$	—	$	5	$	—	$	—
Lease income - operating leases	139		39		—		80		17
Variable lease income	182		—		—		198		—
Total lease income	$	326	$	39	$	5	$	278	$	17

No profit or loss was recognized by Mississippi Power upon commencement of a sales-type lease during the first quarter 2019.

Lease income for Southern Power is included in wholesale revenues. Lease payments received under tolling arrangements and PPAs consist of either scheduled payments or variable payments based on the amount of energy produced by the underlying electric generating units. Scheduled payments to be received under outdoor lighting contracts, tolling arrangements, and PPAs accounted for as leases are presented in the following maturity analyses.

The undiscounted cash flows to be received under tolling arrangements accounted for as sales-type leases are as follows:

	As of June 30, 2019
	Southern Company		Mississippi Power
	(in millions)
2019 (remaining)	$	7	$	7
2020	14		14
2021	14		14
2022	13		13
2023	12		12
Thereafter	135		135
Total undiscounted cash flows	$	195	$	195
Lease receivable	106		106
Difference between undiscounted cash flows and discounted cash flows	$	89	$	89

The undiscounted cash flows to be received under operating leases and contracts accounted for as operating leases (adjusted for intercompany eliminations) are as follows:

	As of June 30, 2019
	Southern Company		Georgia Power		Southern Power		Southern Company Gas
	(in millions)
2019 (remaining)	$	75	$	13	$	52	$	17
2020	125		26		65		35
2021	118		18		66		35
2022	109		8		68		34
2023	103		2		69		34
Thereafter	1,142		—		350		497
Total	$	1,672	$	67	$	670	$	652

Southern Power receives payments for renewable energy under PPAs accounted for as operating leases that are considered contingent rents and are therefore not reflected in the table above. Southern Power allocates revenue to the nonlease components of PPAs based on the stand-alone selling price of capacity and energy. The undiscounted cash flows to be received under outdoor lighting contracts accounted for as operating leases at Alabama Power and Mississippi Power are immaterial.

LEASES

LEASES

On January 1, 2019, the registrants adopted the provisions of FASB ASC Topic 842 (as amended), Leases (ASC 842), which require lessees to recognize leases with a term of greater than 12 months on the balance sheet as lease obligations, representing the discounted future fixed payments due, along with right-of-use (ROU) assets that will be amortized over the term of each lease.

The registrants elected the transition methodology provided by ASC 842, whereby the applicable requirements are applied on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. The registrants also elected the package of practical expedients provided by ASC 842 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, the registrants applied the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and elected the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed.

Lessee

As lessee, the registrants lease certain electric generating units (including renewable energy facilities), real estate/land, communication towers, railcars, and other equipment and vehicles. The major categories of lease obligations are as follows:

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Electric generating units	$	1,072	$	150	$	1,580	$	—	$	—	$	—
Real estate/land	800		4		62		2		395		81
Communication towers	147		1		3		—		—		13
Railcars	54		25		27		3		—		—
Other	145		10		14		2		—		—
Total	$	2,218	$	190	$	1,686	$	7	$	395	$	94

Real estate/land leases primarily consist of commercial real estate leases at Southern Company, Georgia Power, and Southern Company Gas and various land leases primarily associated with renewable energy facilities at Southern

Power. The commercial real estate leases have remaining terms of up to 25 years while the land leases have remaining terms of up to 48 years, including renewal periods.

Communication towers are leased for the installation of equipment to provide cellular phone service to customers and to support the automated meter infrastructure programs at the traditional electric operating companies. Communication tower leases have terms of up to 10 years with options to renew for periods up to 20 years.

While renewal options exist in many of the leases, other than for land leases associated with renewable energy facilities, the expected term used in calculating the lease obligation generally reflects only the noncancelable period of the lease as it is not considered reasonably certain that the lease will be extended. The expected term of land leases associated with renewable energy facilities includes renewal periods reasonably certain of exercise resulting in an expected lease term at least equal to the expected life of the renewable energy facilities.

Contracts that Contain a Lease

While not specifically structured as a lease, some of the PPAs at Alabama Power and Georgia Power are deemed to represent a lease of the underlying electric generating units when the terms of the PPA convey the right to control the use of the underlying assets. Amounts recorded for leases of electric generating units are generally based on the amount of scheduled capacity payments due over the remaining term of the affiliate PPA, which varies between four and 18 years. Georgia Power has several PPAs with Southern Power that Georgia Power accounts for as leases with a lease obligation of approximately $660 million at June 30, 2019. The amount paid for energy under these affiliate PPAs reflects a price that would be paid in an arm's-length transaction as those amounts have been reviewed and approved by the Georgia PSC.

Short-term Leases

Leases with an initial term of 12 months or less are not recorded on the balance sheet; the registrants generally recognize lease expense for these leases on a straight-line basis over the lease term.

Residual Value Guarantees

Residual value guarantees exist primarily in railcar leases at Alabama Power and Georgia Power and the amounts probable of being paid under those guarantees are included in the lease payments. All such amounts are immaterial as of June 30, 2019.

Lease and Nonlease Components

For all asset categories, with the exception of electric generating units, gas pipelines, and real estate leases, the registrants combine lease payments and any nonlease components, such as asset maintenance, for purposes of calculating the lease obligation and the right-of-use asset.

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

	As of June 30, 2019
	Southern  Company(*)		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Operating Leases
Operating lease ROU assets, net	$	1,907	$	152	$	1,492	$	7	$	370	$	95
Operating lease obligations - current	$	241	$	48	$	140	$	2	$	22	$	15
Operating lease obligations - non current	1,733		137		1,377		5		373		79
Total operating lease obligations	$	1,974	$	185	$	1,517	$	7	$	395	$	94
Finance Leases
Finance lease ROU assets, net	$	237	$	5	$	142	$	—	$	—	$	—
Finance lease obligations - current	$	24	$	1	$	10	$	—	$	—	$	—
Finance lease obligations - noncurrent	220		4		159		—		—		—
Total finance lease obligations	$	244	$	5	$	169	$	—	$	—	$	—

(*) Includes operating lease ROU assets, net and operating lease obligations classified as held for sale.

Lease costs for the three and six months ended June 30, 2019, which includes both amounts recognized as operations and maintenance expense and amounts capitalized as part of the cost of another asset, are as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended June 30, 2019
Lease cost
Operating lease cost	$	77	$	13	$	50	$	1	$	7	$	5
Finance lease cost:
Amortization of ROU assets	7		—		4		—		—		—
Interest on lease obligations	3		—		4		—		—		—
Total finance lease cost	10		—		8		—		—		—
Short-term lease costs	13		6		6		—		—		—
Variable lease cost	29		1		25		—		1		—
Sublease income	—		—		—		—		—		—
Total lease cost	$	129	$	20	$	89	$	1	$	8	$	5
For the Six Months Ended June 30, 2019
Lease cost
Operating lease cost	$	147	$	20	$	99	$	1	$	14	$	9
Finance lease cost:
Amortization of ROU assets	14		—		7		—		—		—
Interest on lease obligations	6		—		9		—		—		—
Total finance lease cost	20		—		16		—		—		—
Short-term lease costs	30		11		12		—		—		—
Variable lease cost	48		1		41		—		3		—
Sublease income	—		—		—		—		—		—
Total lease cost	$	245	$	32	$	168	$	1	$	17	$	9

Georgia Power has variable lease payments that are based on the amount of energy produced by certain renewable generating facilities subject to PPAs.

Other information with respect to cash and noncash activities related to leases, as well as weighted-average lease terms and discount rates, is as follows:

	For the Six Months Ended June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Other information
Cash paid for amounts included in the measurements of lease obligations:
Operating cash flows from operating leases	$	129	$	20	$	75	$	1	$	12	$	9
Operating cash flows from finance leases	2		—		10		—		—		—
Financing cash flows from finance leases	16		—		3		—		—		—
ROU assets obtained in exchange for new operating lease obligations	55		5		13		—		—		13
ROU assets obtained in exchange for new finance lease obligations	33		1		28		—		—		—

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
Weighted-average remaining lease term in years:
Operating leases	14.0		3.6		10.5		7.0		33.5		9.7
Finance leases	18.3		12.8		11.0		N/A		N/A		N/A
Weighted-average discount rate:
Operating leases	4.53	%	3.33	%	4.46	%	4.06	%	5.68	%	3.73	%
Finance leases	5.05	%	3.67	%	10.69	%	N/A		N/A		N/A

Maturities of lease liabilities are as follows:

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Maturity Analysis
Operating leases:
2019 (remaining)	$	178	$	33	$	129	$	1	$	13	$	9
2020	295		53		203		2		22		17
2021	279		52		198		1		23		16
2022	268		52		196		1		23		13
2023	204		4		197		1		24		11
Thereafter	1,661		2		990		2		849		49
Total	2,885		196		1,913		8		954		115
Less: Present value discount	911		11		396		1		559		21
Operating lease obligations	$	1,974	$	185	$	1,517	$	7	$	395	$	94
Finance leases:
2019 (remaining)	$	16	$	—	$	16	$	—	$	—	$	—
2020	33		1		28		—		—		—
2021	27		1		25		—		—		—
2022	23		1		25		—		—		—
2023	18		1		25		—		—		—
Thereafter	266		1		165		—		—		—
Total	383		5		284		—		—		—
Less: Present value discount	139		—		115		—		—		—
Finance lease obligations	$	244	$	5	$	169	$	—	$	—	$	—

Payments made under PPAs at Georgia Power for energy generated from certain renewable energy facilities accounted for as operating and finance leases are considered variable lease costs and are therefore not reflected in the above maturity analysis. As of June 30, 2019, Southern Company and Southern Power have additional operating leases, primarily for land, that have not yet commenced. These operating leases are expected to commence during the remainder of 2019 through 2022, with lease terms of up to 31 years, and have estimated total obligations of $81 million.

For additional information on each registrant's operating lease obligations at December 31, 2018, see Note 9 to the financial statements in Item 8 of the Form 10-K.

Lessor

With the exception of Southern Company Gas, the registrants are each considered lessors in various arrangements that have been determined to contain a lease due to the customer's ability to control the use of the underlying asset owned by the applicable registrant. For the traditional electric operating companies, these arrangements consist of outdoor lighting contracts accounted for as operating leases with initial terms of up to five years, after which the contracts renew on a month-to-month basis at the customer's option. For Mississippi Power, these arrangements also include tolling arrangements related to electric generating units accounted for as sales-type leases with terms of up to 20 years. For Southern Power, these arrangements consist of PPAs related to electric generating units, including renewable energy facilities, accounted for as operating leases with terms of up to 28 years. For Southern Company, these arrangements also include PPAs related to fuel cells accounted for as operating leases with terms of up to 15

years. Southern Company Gas is the lessor in operating leases related to gas pipelines with remaining terms of up to 24 years.

Lease income for the three and six months ended June 30, 2019 is as follows:

	Southern Company		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended June 30, 2019
Lease income - interest income on sales-type leases	$	2	$	—	$	2	$	—	$	—
Lease income - operating leases	67		19		—		39		9
Variable lease income	115		—		—		125		—
Total lease income	$	184	$	19	$	2	$	164	$	9
For the Six Months Ended June 30, 2019
Lease income - interest income on sales-type leases	$	5	$	—	$	5	$	—	$	—
Lease income - operating leases	139		39		—		80		17
Variable lease income	182		—		—		198		—
Total lease income	$	326	$	39	$	5	$	278	$	17

No profit or loss was recognized by Mississippi Power upon commencement of a sales-type lease during the first quarter 2019.

Lease income for Southern Power is included in wholesale revenues. Lease payments received under tolling arrangements and PPAs consist of either scheduled payments or variable payments based on the amount of energy produced by the underlying electric generating units. Scheduled payments to be received under outdoor lighting contracts, tolling arrangements, and PPAs accounted for as leases are presented in the following maturity analyses.

The undiscounted cash flows to be received under tolling arrangements accounted for as sales-type leases are as follows:

	As of June 30, 2019
	Southern Company		Mississippi Power
	(in millions)
2019 (remaining)	$	7	$	7
2020	14		14
2021	14		14
2022	13		13
2023	12		12
Thereafter	135		135
Total undiscounted cash flows	$	195	$	195
Lease receivable	106		106
Difference between undiscounted cash flows and discounted cash flows	$	89	$	89

The undiscounted cash flows to be received under operating leases and contracts accounted for as operating leases (adjusted for intercompany eliminations) are as follows:

	As of June 30, 2019
	Southern Company		Georgia Power		Southern Power		Southern Company Gas
	(in millions)
2019 (remaining)	$	75	$	13	$	52	$	17
2020	125		26		65		35
2021	118		18		66		35
2022	109		8		68		34
2023	103		2		69		34
Thereafter	1,142		—		350		497
Total	$	1,672	$	67	$	670	$	652

Southern Power receives payments for renewable energy under PPAs accounted for as operating leases that are considered contingent rents and are therefore not reflected in the table above. Southern Power allocates revenue to the nonlease components of PPAs based on the stand-alone selling price of capacity and energy. The undiscounted cash flows to be received under outdoor lighting contracts accounted for as operating leases at Alabama Power and Mississippi Power are immaterial.

LEASES

LEASES

On January 1, 2019, the registrants adopted the provisions of FASB ASC Topic 842 (as amended), Leases (ASC 842), which require lessees to recognize leases with a term of greater than 12 months on the balance sheet as lease obligations, representing the discounted future fixed payments due, along with right-of-use (ROU) assets that will be amortized over the term of each lease.

The registrants elected the transition methodology provided by ASC 842, whereby the applicable requirements are applied on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. The registrants also elected the package of practical expedients provided by ASC 842 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, the registrants applied the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and elected the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed.

Lessee

As lessee, the registrants lease certain electric generating units (including renewable energy facilities), real estate/land, communication towers, railcars, and other equipment and vehicles. The major categories of lease obligations are as follows:

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Electric generating units	$	1,072	$	150	$	1,580	$	—	$	—	$	—
Real estate/land	800		4		62		2		395		81
Communication towers	147		1		3		—		—		13
Railcars	54		25		27		3		—		—
Other	145		10		14		2		—		—
Total	$	2,218	$	190	$	1,686	$	7	$	395	$	94

Real estate/land leases primarily consist of commercial real estate leases at Southern Company, Georgia Power, and Southern Company Gas and various land leases primarily associated with renewable energy facilities at Southern

Power. The commercial real estate leases have remaining terms of up to 25 years while the land leases have remaining terms of up to 48 years, including renewal periods.

Communication towers are leased for the installation of equipment to provide cellular phone service to customers and to support the automated meter infrastructure programs at the traditional electric operating companies. Communication tower leases have terms of up to 10 years with options to renew for periods up to 20 years.

While renewal options exist in many of the leases, other than for land leases associated with renewable energy facilities, the expected term used in calculating the lease obligation generally reflects only the noncancelable period of the lease as it is not considered reasonably certain that the lease will be extended. The expected term of land leases associated with renewable energy facilities includes renewal periods reasonably certain of exercise resulting in an expected lease term at least equal to the expected life of the renewable energy facilities.

Contracts that Contain a Lease

While not specifically structured as a lease, some of the PPAs at Alabama Power and Georgia Power are deemed to represent a lease of the underlying electric generating units when the terms of the PPA convey the right to control the use of the underlying assets. Amounts recorded for leases of electric generating units are generally based on the amount of scheduled capacity payments due over the remaining term of the affiliate PPA, which varies between four and 18 years. Georgia Power has several PPAs with Southern Power that Georgia Power accounts for as leases with a lease obligation of approximately $660 million at June 30, 2019. The amount paid for energy under these affiliate PPAs reflects a price that would be paid in an arm's-length transaction as those amounts have been reviewed and approved by the Georgia PSC.

Short-term Leases

Leases with an initial term of 12 months or less are not recorded on the balance sheet; the registrants generally recognize lease expense for these leases on a straight-line basis over the lease term.

Residual Value Guarantees

Residual value guarantees exist primarily in railcar leases at Alabama Power and Georgia Power and the amounts probable of being paid under those guarantees are included in the lease payments. All such amounts are immaterial as of June 30, 2019.

Lease and Nonlease Components

For all asset categories, with the exception of electric generating units, gas pipelines, and real estate leases, the registrants combine lease payments and any nonlease components, such as asset maintenance, for purposes of calculating the lease obligation and the right-of-use asset.

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

	As of June 30, 2019
	Southern  Company(*)		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Operating Leases
Operating lease ROU assets, net	$	1,907	$	152	$	1,492	$	7	$	370	$	95
Operating lease obligations - current	$	241	$	48	$	140	$	2	$	22	$	15
Operating lease obligations - non current	1,733		137		1,377		5		373		79
Total operating lease obligations	$	1,974	$	185	$	1,517	$	7	$	395	$	94
Finance Leases
Finance lease ROU assets, net	$	237	$	5	$	142	$	—	$	—	$	—
Finance lease obligations - current	$	24	$	1	$	10	$	—	$	—	$	—
Finance lease obligations - noncurrent	220		4		159		—		—		—
Total finance lease obligations	$	244	$	5	$	169	$	—	$	—	$	—

(*) Includes operating lease ROU assets, net and operating lease obligations classified as held for sale.

Lease costs for the three and six months ended June 30, 2019, which includes both amounts recognized as operations and maintenance expense and amounts capitalized as part of the cost of another asset, are as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended June 30, 2019
Lease cost
Operating lease cost	$	77	$	13	$	50	$	1	$	7	$	5
Finance lease cost:
Amortization of ROU assets	7		—		4		—		—		—
Interest on lease obligations	3		—		4		—		—		—
Total finance lease cost	10		—		8		—		—		—
Short-term lease costs	13		6		6		—		—		—
Variable lease cost	29		1		25		—		1		—
Sublease income	—		—		—		—		—		—
Total lease cost	$	129	$	20	$	89	$	1	$	8	$	5
For the Six Months Ended June 30, 2019
Lease cost
Operating lease cost	$	147	$	20	$	99	$	1	$	14	$	9
Finance lease cost:
Amortization of ROU assets	14		—		7		—		—		—
Interest on lease obligations	6		—		9		—		—		—
Total finance lease cost	20		—		16		—		—		—
Short-term lease costs	30		11		12		—		—		—
Variable lease cost	48		1		41		—		3		—
Sublease income	—		—		—		—		—		—
Total lease cost	$	245	$	32	$	168	$	1	$	17	$	9

Georgia Power has variable lease payments that are based on the amount of energy produced by certain renewable generating facilities subject to PPAs.

Other information with respect to cash and noncash activities related to leases, as well as weighted-average lease terms and discount rates, is as follows:

	For the Six Months Ended June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Other information
Cash paid for amounts included in the measurements of lease obligations:
Operating cash flows from operating leases	$	129	$	20	$	75	$	1	$	12	$	9
Operating cash flows from finance leases	2		—		10		—		—		—
Financing cash flows from finance leases	16		—		3		—		—		—
ROU assets obtained in exchange for new operating lease obligations	55		5		13		—		—		13
ROU assets obtained in exchange for new finance lease obligations	33		1		28		—		—		—

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
Weighted-average remaining lease term in years:
Operating leases	14.0		3.6		10.5		7.0		33.5		9.7
Finance leases	18.3		12.8		11.0		N/A		N/A		N/A
Weighted-average discount rate:
Operating leases	4.53	%	3.33	%	4.46	%	4.06	%	5.68	%	3.73	%
Finance leases	5.05	%	3.67	%	10.69	%	N/A		N/A		N/A

Maturities of lease liabilities are as follows:

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Maturity Analysis
Operating leases:
2019 (remaining)	$	178	$	33	$	129	$	1	$	13	$	9
2020	295		53		203		2		22		17
2021	279		52		198		1		23		16
2022	268		52		196		1		23		13
2023	204		4		197		1		24		11
Thereafter	1,661		2		990		2		849		49
Total	2,885		196		1,913		8		954		115
Less: Present value discount	911		11		396		1		559		21
Operating lease obligations	$	1,974	$	185	$	1,517	$	7	$	395	$	94
Finance leases:
2019 (remaining)	$	16	$	—	$	16	$	—	$	—	$	—
2020	33		1		28		—		—		—
2021	27		1		25		—		—		—
2022	23		1		25		—		—		—
2023	18		1		25		—		—		—
Thereafter	266		1		165		—		—		—
Total	383		5		284		—		—		—
Less: Present value discount	139		—		115		—		—		—
Finance lease obligations	$	244	$	5	$	169	$	—	$	—	$	—

Payments made under PPAs at Georgia Power for energy generated from certain renewable energy facilities accounted for as operating and finance leases are considered variable lease costs and are therefore not reflected in the above maturity analysis. As of June 30, 2019, Southern Company and Southern Power have additional operating leases, primarily for land, that have not yet commenced. These operating leases are expected to commence during the remainder of 2019 through 2022, with lease terms of up to 31 years, and have estimated total obligations of $81 million.

For additional information on each registrant's operating lease obligations at December 31, 2018, see Note 9 to the financial statements in Item 8 of the Form 10-K.

Lessor

With the exception of Southern Company Gas, the registrants are each considered lessors in various arrangements that have been determined to contain a lease due to the customer's ability to control the use of the underlying asset owned by the applicable registrant. For the traditional electric operating companies, these arrangements consist of outdoor lighting contracts accounted for as operating leases with initial terms of up to five years, after which the contracts renew on a month-to-month basis at the customer's option. For Mississippi Power, these arrangements also include tolling arrangements related to electric generating units accounted for as sales-type leases with terms of up to 20 years. For Southern Power, these arrangements consist of PPAs related to electric generating units, including renewable energy facilities, accounted for as operating leases with terms of up to 28 years. For Southern Company, these arrangements also include PPAs related to fuel cells accounted for as operating leases with terms of up to 15

years. Southern Company Gas is the lessor in operating leases related to gas pipelines with remaining terms of up to 24 years.

Lease income for the three and six months ended June 30, 2019 is as follows:

	Southern Company		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended June 30, 2019
Lease income - interest income on sales-type leases	$	2	$	—	$	2	$	—	$	—
Lease income - operating leases	67		19		—		39		9
Variable lease income	115		—		—		125		—
Total lease income	$	184	$	19	$	2	$	164	$	9
For the Six Months Ended June 30, 2019
Lease income - interest income on sales-type leases	$	5	$	—	$	5	$	—	$	—
Lease income - operating leases	139		39		—		80		17
Variable lease income	182		—		—		198		—
Total lease income	$	326	$	39	$	5	$	278	$	17

No profit or loss was recognized by Mississippi Power upon commencement of a sales-type lease during the first quarter 2019.

Lease income for Southern Power is included in wholesale revenues. Lease payments received under tolling arrangements and PPAs consist of either scheduled payments or variable payments based on the amount of energy produced by the underlying electric generating units. Scheduled payments to be received under outdoor lighting contracts, tolling arrangements, and PPAs accounted for as leases are presented in the following maturity analyses.

The undiscounted cash flows to be received under tolling arrangements accounted for as sales-type leases are as follows:

	As of June 30, 2019
	Southern Company		Mississippi Power
	(in millions)
2019 (remaining)	$	7	$	7
2020	14		14
2021	14		14
2022	13		13
2023	12		12
Thereafter	135		135
Total undiscounted cash flows	$	195	$	195
Lease receivable	106		106
Difference between undiscounted cash flows and discounted cash flows	$	89	$	89

The undiscounted cash flows to be received under operating leases and contracts accounted for as operating leases (adjusted for intercompany eliminations) are as follows:

	As of June 30, 2019
	Southern Company		Georgia Power		Southern Power		Southern Company Gas
	(in millions)
2019 (remaining)	$	75	$	13	$	52	$	17
2020	125		26		65		35
2021	118		18		66		35
2022	109		8		68		34
2023	103		2		69		34
Thereafter	1,142		—		350		497
Total	$	1,672	$	67	$	670	$	652

Southern Power receives payments for renewable energy under PPAs accounted for as operating leases that are considered contingent rents and are therefore not reflected in the table above. Southern Power allocates revenue to the nonlease components of PPAs based on the stand-alone selling price of capacity and energy. The undiscounted cash flows to be received under outdoor lighting contracts accounted for as operating leases at Alabama Power and Mississippi Power are immaterial.

LEASES

LEASES

On January 1, 2019, the registrants adopted the provisions of FASB ASC Topic 842 (as amended), Leases (ASC 842), which require lessees to recognize leases with a term of greater than 12 months on the balance sheet as lease obligations, representing the discounted future fixed payments due, along with right-of-use (ROU) assets that will be amortized over the term of each lease.

The registrants elected the transition methodology provided by ASC 842, whereby the applicable requirements are applied on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. The registrants also elected the package of practical expedients provided by ASC 842 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, the registrants applied the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and elected the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed.

Lessee

As lessee, the registrants lease certain electric generating units (including renewable energy facilities), real estate/land, communication towers, railcars, and other equipment and vehicles. The major categories of lease obligations are as follows:

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Electric generating units	$	1,072	$	150	$	1,580	$	—	$	—	$	—
Real estate/land	800		4		62		2		395		81
Communication towers	147		1		3		—		—		13
Railcars	54		25		27		3		—		—
Other	145		10		14		2		—		—
Total	$	2,218	$	190	$	1,686	$	7	$	395	$	94

Real estate/land leases primarily consist of commercial real estate leases at Southern Company, Georgia Power, and Southern Company Gas and various land leases primarily associated with renewable energy facilities at Southern

Power. The commercial real estate leases have remaining terms of up to 25 years while the land leases have remaining terms of up to 48 years, including renewal periods.

Communication towers are leased for the installation of equipment to provide cellular phone service to customers and to support the automated meter infrastructure programs at the traditional electric operating companies. Communication tower leases have terms of up to 10 years with options to renew for periods up to 20 years.

While renewal options exist in many of the leases, other than for land leases associated with renewable energy facilities, the expected term used in calculating the lease obligation generally reflects only the noncancelable period of the lease as it is not considered reasonably certain that the lease will be extended. The expected term of land leases associated with renewable energy facilities includes renewal periods reasonably certain of exercise resulting in an expected lease term at least equal to the expected life of the renewable energy facilities.

Contracts that Contain a Lease

While not specifically structured as a lease, some of the PPAs at Alabama Power and Georgia Power are deemed to represent a lease of the underlying electric generating units when the terms of the PPA convey the right to control the use of the underlying assets. Amounts recorded for leases of electric generating units are generally based on the amount of scheduled capacity payments due over the remaining term of the affiliate PPA, which varies between four and 18 years. Georgia Power has several PPAs with Southern Power that Georgia Power accounts for as leases with a lease obligation of approximately $660 million at June 30, 2019. The amount paid for energy under these affiliate PPAs reflects a price that would be paid in an arm's-length transaction as those amounts have been reviewed and approved by the Georgia PSC.

Short-term Leases

Leases with an initial term of 12 months or less are not recorded on the balance sheet; the registrants generally recognize lease expense for these leases on a straight-line basis over the lease term.

Residual Value Guarantees

Residual value guarantees exist primarily in railcar leases at Alabama Power and Georgia Power and the amounts probable of being paid under those guarantees are included in the lease payments. All such amounts are immaterial as of June 30, 2019.

Lease and Nonlease Components

For all asset categories, with the exception of electric generating units, gas pipelines, and real estate leases, the registrants combine lease payments and any nonlease components, such as asset maintenance, for purposes of calculating the lease obligation and the right-of-use asset.

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

	As of June 30, 2019
	Southern  Company(*)		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Operating Leases
Operating lease ROU assets, net	$	1,907	$	152	$	1,492	$	7	$	370	$	95
Operating lease obligations - current	$	241	$	48	$	140	$	2	$	22	$	15
Operating lease obligations - non current	1,733		137		1,377		5		373		79
Total operating lease obligations	$	1,974	$	185	$	1,517	$	7	$	395	$	94
Finance Leases
Finance lease ROU assets, net	$	237	$	5	$	142	$	—	$	—	$	—
Finance lease obligations - current	$	24	$	1	$	10	$	—	$	—	$	—
Finance lease obligations - noncurrent	220		4		159		—		—		—
Total finance lease obligations	$	244	$	5	$	169	$	—	$	—	$	—

(*) Includes operating lease ROU assets, net and operating lease obligations classified as held for sale.

Lease costs for the three and six months ended June 30, 2019, which includes both amounts recognized as operations and maintenance expense and amounts capitalized as part of the cost of another asset, are as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended June 30, 2019
Lease cost
Operating lease cost	$	77	$	13	$	50	$	1	$	7	$	5
Finance lease cost:
Amortization of ROU assets	7		—		4		—		—		—
Interest on lease obligations	3		—		4		—		—		—
Total finance lease cost	10		—		8		—		—		—
Short-term lease costs	13		6		6		—		—		—
Variable lease cost	29		1		25		—		1		—
Sublease income	—		—		—		—		—		—
Total lease cost	$	129	$	20	$	89	$	1	$	8	$	5
For the Six Months Ended June 30, 2019
Lease cost
Operating lease cost	$	147	$	20	$	99	$	1	$	14	$	9
Finance lease cost:
Amortization of ROU assets	14		—		7		—		—		—
Interest on lease obligations	6		—		9		—		—		—
Total finance lease cost	20		—		16		—		—		—
Short-term lease costs	30		11		12		—		—		—
Variable lease cost	48		1		41		—		3		—
Sublease income	—		—		—		—		—		—
Total lease cost	$	245	$	32	$	168	$	1	$	17	$	9

Georgia Power has variable lease payments that are based on the amount of energy produced by certain renewable generating facilities subject to PPAs.

Other information with respect to cash and noncash activities related to leases, as well as weighted-average lease terms and discount rates, is as follows:

	For the Six Months Ended June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Other information
Cash paid for amounts included in the measurements of lease obligations:
Operating cash flows from operating leases	$	129	$	20	$	75	$	1	$	12	$	9
Operating cash flows from finance leases	2		—		10		—		—		—
Financing cash flows from finance leases	16		—		3		—		—		—
ROU assets obtained in exchange for new operating lease obligations	55		5		13		—		—		13
ROU assets obtained in exchange for new finance lease obligations	33		1		28		—		—		—

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
Weighted-average remaining lease term in years:
Operating leases	14.0		3.6		10.5		7.0		33.5		9.7
Finance leases	18.3		12.8		11.0		N/A		N/A		N/A
Weighted-average discount rate:
Operating leases	4.53	%	3.33	%	4.46	%	4.06	%	5.68	%	3.73	%
Finance leases	5.05	%	3.67	%	10.69	%	N/A		N/A		N/A

Maturities of lease liabilities are as follows:

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Maturity Analysis
Operating leases:
2019 (remaining)	$	178	$	33	$	129	$	1	$	13	$	9
2020	295		53		203		2		22		17
2021	279		52		198		1		23		16
2022	268		52		196		1		23		13
2023	204		4		197		1		24		11
Thereafter	1,661		2		990		2		849		49
Total	2,885		196		1,913		8		954		115
Less: Present value discount	911		11		396		1		559		21
Operating lease obligations	$	1,974	$	185	$	1,517	$	7	$	395	$	94
Finance leases:
2019 (remaining)	$	16	$	—	$	16	$	—	$	—	$	—
2020	33		1		28		—		—		—
2021	27		1		25		—		—		—
2022	23		1		25		—		—		—
2023	18		1		25		—		—		—
Thereafter	266		1		165		—		—		—
Total	383		5		284		—		—		—
Less: Present value discount	139		—		115		—		—		—
Finance lease obligations	$	244	$	5	$	169	$	—	$	—	$	—

Payments made under PPAs at Georgia Power for energy generated from certain renewable energy facilities accounted for as operating and finance leases are considered variable lease costs and are therefore not reflected in the above maturity analysis. As of June 30, 2019, Southern Company and Southern Power have additional operating leases, primarily for land, that have not yet commenced. These operating leases are expected to commence during the remainder of 2019 through 2022, with lease terms of up to 31 years, and have estimated total obligations of $81 million.

For additional information on each registrant's operating lease obligations at December 31, 2018, see Note 9 to the financial statements in Item 8 of the Form 10-K.

Lessor

With the exception of Southern Company Gas, the registrants are each considered lessors in various arrangements that have been determined to contain a lease due to the customer's ability to control the use of the underlying asset owned by the applicable registrant. For the traditional electric operating companies, these arrangements consist of outdoor lighting contracts accounted for as operating leases with initial terms of up to five years, after which the contracts renew on a month-to-month basis at the customer's option. For Mississippi Power, these arrangements also include tolling arrangements related to electric generating units accounted for as sales-type leases with terms of up to 20 years. For Southern Power, these arrangements consist of PPAs related to electric generating units, including renewable energy facilities, accounted for as operating leases with terms of up to 28 years. For Southern Company, these arrangements also include PPAs related to fuel cells accounted for as operating leases with terms of up to 15

years. Southern Company Gas is the lessor in operating leases related to gas pipelines with remaining terms of up to 24 years.

Lease income for the three and six months ended June 30, 2019 is as follows:

	Southern Company		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended June 30, 2019
Lease income - interest income on sales-type leases	$	2	$	—	$	2	$	—	$	—
Lease income - operating leases	67		19		—		39		9
Variable lease income	115		—		—		125		—
Total lease income	$	184	$	19	$	2	$	164	$	9
For the Six Months Ended June 30, 2019
Lease income - interest income on sales-type leases	$	5	$	—	$	5	$	—	$	—
Lease income - operating leases	139		39		—		80		17
Variable lease income	182		—		—		198		—
Total lease income	$	326	$	39	$	5	$	278	$	17

No profit or loss was recognized by Mississippi Power upon commencement of a sales-type lease during the first quarter 2019.

Lease income for Southern Power is included in wholesale revenues. Lease payments received under tolling arrangements and PPAs consist of either scheduled payments or variable payments based on the amount of energy produced by the underlying electric generating units. Scheduled payments to be received under outdoor lighting contracts, tolling arrangements, and PPAs accounted for as leases are presented in the following maturity analyses.

The undiscounted cash flows to be received under tolling arrangements accounted for as sales-type leases are as follows:

	As of June 30, 2019
	Southern Company		Mississippi Power
	(in millions)
2019 (remaining)	$	7	$	7
2020	14		14
2021	14		14
2022	13		13
2023	12		12
Thereafter	135		135
Total undiscounted cash flows	$	195	$	195
Lease receivable	106		106
Difference between undiscounted cash flows and discounted cash flows	$	89	$	89

The undiscounted cash flows to be received under operating leases and contracts accounted for as operating leases (adjusted for intercompany eliminations) are as follows:

	As of June 30, 2019
	Southern Company		Georgia Power		Southern Power		Southern Company Gas
	(in millions)
2019 (remaining)	$	75	$	13	$	52	$	17
2020	125		26		65		35
2021	118		18		66		35
2022	109		8		68		34
2023	103		2		69		34
Thereafter	1,142		—		350		497
Total	$	1,672	$	67	$	670	$	652

Southern Power receives payments for renewable energy under PPAs accounted for as operating leases that are considered contingent rents and are therefore not reflected in the table above. Southern Power allocates revenue to the nonlease components of PPAs based on the stand-alone selling price of capacity and energy. The undiscounted cash flows to be received under outdoor lighting contracts accounted for as operating leases at Alabama Power and Mississippi Power are immaterial.

XML

Segment and Related Information

6 Months Ended

Jun. 30, 2019

Segment Reporting [Abstract]

SEGMENT AND RELATED INFORMATION

SEGMENT AND RELATED INFORMATION

Southern Company

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 – Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in three Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas pipeline investments, wholesale gas services, and gas marketing services.

Southern Company's reportable business segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $117 million and $204 million for the three and six months ended June 30, 2019, respectively, and $109 million and $192 million for the three and six months ended June 30, 2018, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were immaterial for both the three and six months ended June 30, 2019 and 2018. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $16 million and $33 million for the three and six months ended June 30, 2019, respectively, and $22 million and $58 million for the three and six months ended June 30, 2018, respectively. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy solutions, such as distributed energy infrastructure and energy efficiency products and services, to customers, as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.

Financial data for business segments and products and services for the three and six months ended June 30, 2019 and 2018 was as follows:

	Electric Utilities
	Traditional Electric Operating Companies			Southern Power		Eliminations			Total			Southern Company Gas			All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2019
Operating revenues	$	3,899		$	510	$	(119	)	$	4,290		$	689		$	186		$	(67	)	$	5,098
Segment net income (loss)(a)(b)(c)(d)	782			174		—			956			106			(154		)	(9		)	899
Six Months Ended June 30, 2019
Operating revenues	$	7,343		$	953	$	(211	)	$	8,085		$	2,163		$	368		$	(106	)	$	10,510
Segment net income (loss)(a)(b)(c)(d)	1,346			230		—			1,576			376			1,041			(11		)	2,982
At June 30, 2019
Goodwill	$	—		$	2	$	—		$	2		$	5,015		$	265		$	—		$	5,282
Total assets	78,314			14,518		(783		)	92,049			20,761			3,343			(1,286		)	114,867
Three Months Ended June 30, 2018
Operating revenues	$	4,124		$	555	$	(114	)	$	4,565		$	730		$	381		$	(49	)	$	5,627
Segment net income (loss)(a)(b)(d)	(48		)	22		—			(26		)	(31		)	(100		)	3			(154		)
Six Months Ended June 30, 2018
Operating revenues	$	8,104		$	1,064	$	(220	)	$	8,948		$	2,369		$	782		$	(100	)	$	11,999
Segment net income (loss)(a)(b)(d)(e)	563			143		—			706			248			(174		)	4			784
At December 31, 2018
Goodwill	$	—		$	2	$	—		$	2		$	5,015		$	298		$	—		$	5,315
Total assets	79,382			14,883		(306		)	93,959			21,448			3,285			(1,778		)	116,914

(a) Attributable to Southern Company.

(b) Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated losses on plants under construction of $4 million ($3 million after tax) and $1.1 billion ($0.8 billion after tax) for the three months ended June 30, 2019 and 2018, respectively, and $6 million ($5 million after tax) and $1.1 billion ($0.8 billion after tax) for the six months ended June 30, 2019 and 2018, respectively. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) under "Georgia Power – Nuclear Construction" and "Mississippi Power – Kemper County Energy Facility" for additional information.

(c) Segment net income (loss) for the "All Other" column includes the preliminary pre-tax gain associated with the sale of Gulf Power of $2.5 billion ($1.3 billion after tax) for the six months ended June 30, 2019, of which $(15) million ($(11) million after tax) was recorded in the three months ended June 30, 2019, as well as a goodwill impairment charge of $32 million for the three and six months ended June 30, 2019 in contemplation of the sale of one of PowerSecure's business units. See Note (K) under "Southern Company" for additional information.

(d) Segment net income (loss) for Southern Power includes a $23 million pre-tax gain ($88 million gain after tax) on the sale of Plant Nacogdoches for the three and six months ended June 30, 2019 and a pre-tax impairment charge of $119 million ($89 million after tax) for the three and six months ended June 30, 2018 related to the sale of Southern Power's Florida Plants. See Note (K) under "Southern Power" and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Sale of Natural Gas Plants" for additional information.

(e) Segment net income (loss) for Southern Company Gas includes a goodwill impairment charge of $42 million for the six months ended June 30, 2018 related to the sale of Pivotal Home Solutions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

Products and Services

	Electric Utilities' Revenues
	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended June 30, 2019	$	3,540	$	542	$	208	$	4,290
Three Months Ended June 30, 2018	3,740		616		209		4,565
Six Months Ended June 30, 2019	$	6,623	$	1,041	$	421	$	8,085
Six Months Ended June 30, 2018	7,308		1,239		401		8,948

	Southern Company Gas' Revenues
	Gas Distribution Operations(a)		Gas Marketing Services(b)		Other		Total
	(in millions)
Three Months Ended June 30, 2019	$	563	$	58	$	68	$	689
Three Months Ended June 30, 2018	638		89		3		730
Six Months Ended June 30, 2019	$	1,724	$	287	$	152	$	2,163
Six Months Ended June 30, 2018	1,838		359		172		2,369

(a) Operating revenues for the three gas distribution operations dispositions were $70 million and $237 million for the three and six months ended June 30, 2018, respectively.

(b)

Operating revenues for Pivotal Home Solutions were $24 million and $55 million for the three and six months ended June 30, 2018, respectively.

Southern Company Gas

Southern Company Gas manages its business through four reportable segments – gas distribution operations, gas pipeline investments, wholesale gas services, and gas marketing services. The non-reportable segments are combined and presented as all other.

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

Gas pipeline investments consists of joint ventures in natural gas pipeline investments including a 50% interest in SNG, two significant pipeline construction projects, and a 50% joint ownership interest in the Dalton Pipeline. These natural gas pipelines enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas.

Wholesale gas services provides natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services engages in natural gas storage and gas pipeline arbitrage and related activities.

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

The all other column includes segments below the quantitative threshold for separate disclosure. This includes Southern Company Gas' storage and fuels operations, its investment in Triton through the completion of its sale on May 29, 2019, and other subsidiaries that fall below the quantitative threshold for separate disclosure. See Note (E) under "Southern Company Gas" for additional information and related disclosures.

Business segment financial data for the three and six months ended June 30, 2019 and 2018 was as follows:

	Gas Distribution Operations(a)		Gas Pipeline Investments		Wholesale Gas Services(b)			Gas Marketing Services(c)(d)			Total			All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2019
Operating revenues	$	568	$	8	$	48		$	58		$	682		$	13		$	(6	)	$	689
Segment net income (loss)	58		25		23			(3		)	103			3			—			106
Six Months Ended June 30, 2019
Operating revenues	$	1,740	$	16	$	134		$	287		$	2,177		$	24		$	(38	)	$	2,163
Segment net income (loss)	191		57		70			58			376			—			—			376
Total assets at June 30, 2019	17,397		1,768		668			1,527			21,360			10,934			(11,533		)	20,761
Three Months Ended June 30, 2018
Operating revenues	$	643	$	8	$	(16	)	$	89		$	724		$	11		$	(5	)	$	730
Segment net income (loss)	68		21		(21		)	(76		)	(8		)	(23		)	—			(31		)
Six Months Ended June 30, 2018
Operating revenues	$	1,856	$	16	$	150		$	359		$	2,381		$	26		$	(38	)	$	2,369
Segment net income (loss)	216		48		83			(63		)	284			(36		)	—			248
Total assets at December 31, 2018	17,266		1,763		1,302			1,587			21,918			11,112			(11,582		)	21,448

(a) Operating revenues for the three gas distribution operations dispositions were $70 million and $237 million for the three and six months ended June 30, 2018, respectively. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

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

	Third Party Gross Revenues		Intercompany Revenues		Total Gross Revenues		Less Gross Gas Costs		Operating Revenues
	(in millions)
Three Months Ended June 30, 2019	$	1,223	$	63	$	1,286	$	1,238	$	48
Three Months Ended June 30, 2018	1,336		102		1,438		1,454		(16		)
Six Months Ended June 30, 2019	$	3,148	$	151	$	3,299	$	3,165	$	134
Six Months Ended June 30, 2018	3,274		269		3,543		3,393		150

(c) Operating revenues for Pivotal Home Solutions were $24 million and $55 million for the three and six months ended June 30, 2018, respectively. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information on the sale of Pivotal Home Solutions.

(d)

Segment net income (loss) for gas marketing services includes a loss on disposition of $36 million for the three and six months ended June 30, 2018 and a goodwill impairment charge of $42 million for the six months ended June 30, 2018 related to the sale of Pivotal Home Solutions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

XML

Introduction (Policies)

6 Months Ended

Jun. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Accounting

The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2018 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended June 30, 2019 and 2018. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

Reclassifications

Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.

Recently Adopted Accounting Standards

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. The registrants adopted the new standard effective January 1, 2019. See Note (L) for additional information and related disclosures.

Goodwill and Other Intangible Assets

Goodwill is not amortized but is subject to an annual impairment test during the fourth quarter of each year or more frequently if impairment indicators arise.

Restricted Cash

At December 31, 2018, Georgia Power had restricted cash related to the redemption of pollution control revenue bonds, which were redeemed in January 2019. See Note (F) under "Financing Activities" for additional information. At both June 30, 2019 and December 31, 2018, Southern Company Gas had restricted cash held as collateral for worker's compensation, life insurance, and long-term disability insurance.

Natural Gas For Sale

Southern Company Gas, with the exception of Nicor Gas, carries natural gas inventory on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Southern Company Gas recorded adjustments of $7 million and $10 million for the three and six months ended June 30, 2019, respectively, and no material adjustments for the comparable periods in 2018.

Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. Nicor Gas had no inventory decrement at June 30, 2019.

Valuation Methodologies

Valuation Methodologies

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

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

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. See Note 6 to the financial statements under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

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

Derivatives

Interest Rate Derivatives

Southern Company and certain subsidiaries may enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the

same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. 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. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information.

Energy-Related Derivatives

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

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

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

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

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

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

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

Foreign Currency Derivatives

Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

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Introduction (Tables)

6 Months Ended

Jun. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Goodwill

Goodwill at June 30, 2019 and December 31, 2018 was as follows:

	At June 30, 2019		At December 31, 2018
	(in millions)
Southern Company	$	5,282	$	5,315
Southern Company Gas:
Gas distribution operations	$	4,034	$	4,034
Gas marketing services	981		981
Southern Company Gas total	$	5,015	$	5,015

Schedule of Other Intangible Assets, Indefinite-Lived

Other intangible assets were as follows:

	At June 30, 2019							At December 31, 2018
	Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net
	(in millions)							(in millions)
Southern Company
Other intangible assets subject to amortization:
Customer relationships	$	211	$	(105	)	$	106	$	223	$	(94	)	$	129
Trade names	70		(23		)	47		70		(21		)	49
Storage and transportation contracts	64		(58		)	6		64		(54		)	10
PPA fair value adjustments	371		(60		)	311		405		(61		)	344
Other	12		(7		)	5		11		(5		)	6
Total other intangible assets subject to amortization	$	728	$	(253	)	$	475	$	773	$	(235	)	$	538
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—			75		75		—			75
Total other intangible assets	$	803	$	(253	)	$	550	$	848	$	(235	)	$	613
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	371	$	(60	)	$	311	$	405	$	(61	)	$	344
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156	$	(95	)	$	61	$	156	$	(84	)	$	72
Trade names	26		(8		)	18		26		(7		)	19
Wholesale gas services
Storage and transportation contracts	64		(58		)	6		64		(54		)	10
Total other intangible assets subject to amortization	$	246	$	(161	)	$	85	$	246	$	(145	)	$	101

Schedule of Other Intangible Assets, Finite-Lived

Other intangible assets were as follows:

	At June 30, 2019							At December 31, 2018
	Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net
	(in millions)							(in millions)
Southern Company
Other intangible assets subject to amortization:
Customer relationships	$	211	$	(105	)	$	106	$	223	$	(94	)	$	129
Trade names	70		(23		)	47		70		(21		)	49
Storage and transportation contracts	64		(58		)	6		64		(54		)	10
PPA fair value adjustments	371		(60		)	311		405		(61		)	344
Other	12		(7		)	5		11		(5		)	6
Total other intangible assets subject to amortization	$	728	$	(253	)	$	475	$	773	$	(235	)	$	538
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—			75		75		—			75
Total other intangible assets	$	803	$	(253	)	$	550	$	848	$	(235	)	$	613
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	371	$	(60	)	$	311	$	405	$	(61	)	$	344
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156	$	(95	)	$	61	$	156	$	(84	)	$	72
Trade names	26		(8		)	18		26		(7		)	19
Wholesale gas services
Storage and transportation contracts	64		(58		)	6		64		(54		)	10
Total other intangible assets subject to amortization	$	246	$	(161	)	$	85	$	246	$	(145	)	$	101

Finite-lived Intangible Assets Amortization Expense

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Six Months Ended
	June 30, 2019
	(in millions)
Southern Company	$	15	$	32
Southern Power(a)	$	4	$	10
Southern Company Gas
Gas marketing services(b)	$	6	$	12
Wholesale gas services(a)	2		4
Southern Company Gas total	$	8	$	16

(a) Recorded as a reduction to operating revenues.

(b)

Included in depreciation and amortization.

Restrictions on Cash and Cash Equivalents

The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the registrants that had restricted cash at June 30, 2019 and/or December 31, 2018:

	Southern Company			Southern Company Gas
	(in millions)
At June 30, 2019
Cash and cash equivalents	$	1,383		$	56
Restricted cash:
Other accounts and notes receivable	4			4
Total cash, cash equivalents, and restricted cash	$	1,386	(*)	$	60

(*) Total does not add due to rounding.

	Southern Company		Georgia Power		Southern Company Gas
	(in millions)
At December 31, 2018
Cash and cash equivalents	$	1,396	$	4	$	64
Cash and cash equivalents held for sale	9		—		—
Restricted cash:
Restricted cash	—		108		—
Other accounts and notes receivable	114		—		6
Total cash, cash equivalents, and restricted cash	$	1,519	$	112	$	70

Schedule of Cash and Cash Equivalents

The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the registrants that had restricted cash at June 30, 2019 and/or December 31, 2018:

	Southern Company			Southern Company Gas
	(in millions)
At June 30, 2019
Cash and cash equivalents	$	1,383		$	56
Restricted cash:
Other accounts and notes receivable	4			4
Total cash, cash equivalents, and restricted cash	$	1,386	(*)	$	60

(*) Total does not add due to rounding.

	Southern Company		Georgia Power		Southern Company Gas
	(in millions)
At December 31, 2018
Cash and cash equivalents	$	1,396	$	4	$	64
Cash and cash equivalents held for sale	9		—		—
Restricted cash:
Restricted cash	—		108		—
Other accounts and notes receivable	114		—		6
Total cash, cash equivalents, and restricted cash	$	1,519	$	112	$	70

Details of AROs included in the balance sheets

Details of the AROs included in the condensed balance sheets of Southern Company, Alabama Power, and Mississippi Power at June 30, 2019 are shown in the following table. There were no material changes in the AROs of Georgia Power or Southern Power during the first six months of 2019.

	Southern Company			Alabama Power			Mississippi Power
	(in millions)
Balance at December 31, 2018	$	9,394		$	3,210		$	160
Liabilities incurred	6			—			—
Liabilities settled	(142		)	(43		)	(17		)
Accretion	197			70			2
Cash flow revisions	452			308			59
Balance at June 30, 2019	$	9,907		$	3,545		$	204

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Regulatory Matters (Tables)

6 Months Ended

Jun. 30, 2019

Regulated Operations [Abstract]

Cost Recovery Clauses

The recovery balances for certain of Alabama Power's, Georgia Power's, and Mississippi Power's regulatory clauses at June 30, 2019 and December 31, 2018 were as follows:

Regulatory Clause	Balance Sheet Line Item	June 30, 2019		December 31, 2018
		(in millions)
Alabama Power
Rate CNP Compliance	Deferred under recovered regulatory clause revenues	$	—	$	42
	Customer accounts receivable	10		—
Rate CNP PPA	Deferred under recovered regulatory clause revenues	25		25
Retail Energy Cost Recovery(*)	Deferred under recovered regulatory clause revenues	—		109
	Customer accounts receivable	8		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	19		20
Georgia Power
Fuel Cost Recovery	Receivables – under recovered fuel clause revenues	$	69	$	115
Mississippi Power
Fuel Cost Recovery	Over recovered regulatory clause liabilities	$	9	$	8

(*)

In accordance with an accounting order issued on February 5, 2019 by the Alabama PSC, Alabama Power utilized $75 million of the 2018 Rate RSE refund liability to reduce the Rate ECR under recovered balance. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information.

Requested Recovery of Proposed Increases

Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:

Tariff	2020		2021		2022
	(in millions)
Traditional base:
Levelized	$	209	$	—	$	—
CCR AROs	158		140		227
Environmental Compliance Cost Recovery	165		—		—
Demand-Side Management	14		2		1
Municipal Franchise Fee	17		3		5
Total(*)	$	563	$	145	$	234

(*)

Totals may not add due to rounding.

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 June 30, 2019(b)	(5.2		)
Remaining estimate to complete(a)	$	3.2

(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.

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Revenue from Contracts with Customers (Tables)

6 Months Ended

Jun. 30, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following tables disaggregate revenue sources for the three and six months ended June 30, 2019 and 2018:

	For the Three Months Ended June 30, 2019		For the Three Months Ended June 30, 2018			For the Six Months Ended June 30, 2019		For the Six Months Ended June 30, 2018
	(in millions)
Southern Company
Operating revenues
Retail electric revenues(a)
Residential	$	1,488	$	1,579		$	2,776	$	3,118
Commercial	1,258		1,315			2,350		2,557
Industrial	763		814			1,440		1,569
Other	31		32			57		64
Natural gas distribution revenues(b)	562		642			1,724		1,865
Alternative revenue programs(c)	1		(4		)	—		(27		)
Total retail electric and gas distribution revenues	$	4,103	$	4,378		$	8,347	$	9,146
Wholesale energy revenues(d)(e)	410		464			777		937
Wholesale capacity revenues(e)	132		152			264		302
Other natural gas revenues(f)(g)	126		68			439		476
Other revenues(h)	327		565			683		1,138
Total operating revenues	$	5,098	$	5,627		$	10,510	$	11,999

(a) Retail electric revenues include $8 million, $18 million, $16 million, and $36 million of revenues accounted for as leases for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, and a (net reduction) or net increase of $(14) million, $68 million, $(117) million and $101 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, from certain cost recovery mechanisms that are not accounted for as revenue under ASC 606.

(b) Natural gas distribution revenues include $5 million for each of the three months ended June 30, 2019 and 2018 and $8 million for each of the six months ended June 30, 2019 and 2018 of revenues not accounted for under ASC 606.

(c) Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(d) Wholesale energy revenues include $30 million, $61 million, $82 million, and $155 million of revenues accounted for as derivatives for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, primarily related to physical energy sales in the wholesale electricity market.

(e) Wholesale energy revenues include $115 million, $118 million, $182 million, and $187 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, and wholesale capacity revenues include $22 million, $31 million, $47 million, and $61 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, related to PPAs accounted for as leases.

(f) Other natural gas revenues related to Southern Company Gas' energy and risk management activities are presented net of the related costs of those activities and include gross third-party revenues of $1.2 billion, $1.3 billion, $3.1 billion, and $3.3 billion for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of which $0.8 billion, $0.7 billion, $2.0 billion, and $1.8 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (M) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.

(g) Other natural gas revenues include $10 million and $27 million for the three and six months ended June 30, 2019, respectively, of revenues not accounted for under ASC 606, including $8 million and $16 million, respectively, of revenues accounted for as leases.

(h) Other revenues include $89 million, $89 million, $180 million, and $183 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of revenues not accounted for under ASC 606, including $28 million, $33 million, $59 million, and $66 million, respectively, accounted for as leases.

	Alabama Power		Georgia Power		Mississippi Power
	(in millions)
For the Three Months Ended June 30, 2019
Operating revenues
Retail revenues(a)(b)
Residential	$	588	$	831	$	69
Commercial	418		767		73
Industrial	366		327		70
Other	6		21		3
Total retail electric revenues	$	1,378	$	1,946	$	215
Wholesale energy revenues(c)	41		14		93
Wholesale capacity revenues	25		22		1
Other revenues(b)(d)	69		135		4
Total operating revenues	$	1,513	$	2,117	$	313
For the Three Months Ended June 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	557	$	785	$	65
Commercial	402		749		68
Industrial	372		335		76
Other	7		20		3
Total retail electric revenues	$	1,338	$	1,889	$	212
Wholesale energy revenues(c)	71		26		77
Wholesale capacity revenues	25		13		1
Other revenues(b)(d)	69		120		7
Total operating revenues	$	1,503	$	2,048	$	297

(a) Retail revenues at Alabama Power, Georgia Power, and Mississippi Power include a net increase or (net reduction) of $(11) million, $(5) million, and $2 million, respectively, for the three months ended June 30, 2019 and $78 million, $3 million, and $(1) million, respectively, for the three months ended June 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606.

(b) Retail revenues and other revenues at Georgia Power include $8 million and $11 million, respectively, for the three months ended June 30, 2019 and $18 million and $33 million, respectively, for the three months ended June 30, 2018 of revenues accounted for as leases.

(c) Wholesale energy revenues at Alabama Power, Georgia Power, and Mississippi Power include $3 million, $4 million, and $1 million, respectively, for the three months ended June 30, 2019 and $4 million, $5 million, and $1 million, respectively, for the three months ended June 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market.

(d) Other revenues at Alabama Power and Georgia Power include $31 million and $30 million, respectively, for the three months ended June 30, 2019 and $26 million and $26 million, respectively, for the three months ended June 30, 2018 of revenues not accounted for under ASC 606.

	Alabama Power		Georgia Power		Mississippi Power
	(in millions)
For the Six Months Ended June 30, 2019
Operating revenues
Retail revenues(a)(b)
Residential	$	1,128	$	1,519	$	129
Commercial	772		1,440		138
Industrial	679		616		145
Other	13		39		6
Total retail electric revenues	$	2,592	$	3,614	$	418
Wholesale energy revenues(c)	135		27		170
Wholesale capacity revenues	51		40		2
Other revenues(b)(d)	143		270		10
Total operating revenues	$	2,921	$	3,951	$	600
For the Six Months Ended June 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	1,127	$	1,529	$	125
Commercial	774		1,466		130
Industrial	710		650		146
Other	13		43		5
Total retail electric revenues	$	2,624	$	3,688	$	406
Wholesale energy revenues(c)	172		66		176
Wholesale capacity revenues	49		27		5
Other revenues(b)(d)	131		227		11
Total operating revenues	$	2,976	$	4,008	$	598

(a) Retail revenues at Alabama Power, Georgia Power, and Mississippi Power include a net increase or (net reduction) of $(68) million, $(52) million, and $3 million, respectively, for the six months ended June 30, 2019 and $125 million, $12 million, and $(8) million, respectively, for the six months ended June 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606.

(b) Retail revenues and other revenues at Georgia Power include $16 million and $23 million, respectively, for the six months ended June 30, 2019 and $36 million and $66 million, respectively, for the six months ended June 30, 2018 of revenues accounted for as leases.

(c) Wholesale energy revenues at Alabama Power, Georgia Power, and Mississippi Power include $6 million, $8 million, and $1 million, respectively, for the six months ended June 30, 2019 and $9 million, $13 million, and $2 million, respectively, for the six months ended June 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market.

(d)

Other revenues at Alabama Power and Georgia Power include $59 million and $61 million, respectively, for the six months ended June 30, 2019 and $52 million and $53 million, respectively, for the six months ended June 30, 2018 of revenues not accounted for under ASC 606.

	For the Three Months Ended June 30, 2019		For the Three Months Ended June 30, 2018		For the Six Months Ended June 30, 2019		For the Six Months Ended  June 30, 2018
	(in millions)
Southern Power
PPA capacity revenues(a)	$	125	$	144	$	252	$	282
PPA energy revenues(a)	291		302		518		556
Non-PPA revenues(b)	91		106		177		221
Other revenues	3		3		6		5
Total operating revenues	$	510	$	555	$	953	$	1,064

(a) PPA capacity revenues include $39 million, $47 million, $80 million, and $94 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, and PPA energy revenues include $125 million, $127 million, $198 million, and $203 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, related to PPAs accounted for as leases.

(b)

Non-PPA revenues include $22 million, $50 million, $67 million, and $129 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of revenues from short-term sales related to physical energy sales from uncovered capacity in the wholesale electricity market.

	For the Three Months Ended June 30, 2019		For the Three Months Ended June 30, 2018			For the Six Months Ended June 30, 2019		For the Six Months Ended  June 30, 2018
	(in millions)
Southern Company Gas
Operating revenues
Natural gas distribution revenues(a)
Residential	$	229	$	273		$	830	$	933
Commercial	65		76			235		268
Transportation	213		228			469		505
Industrial	5		7			22		24
Other	50		58			168		135
Alternative revenue programs(b)	1		(4		)	—		(27		)
Total natural gas distribution revenues	$	563	$	638		$	1,724	$	1,838
Gas pipeline investments(c)	8		8			16		16
Wholesale gas services(d)	48		(15		)	114		131
Gas marketing services(e)	58		89			287		359
Other revenues	12		10			22		25
Total operating revenues	$	689	$	730		$	2,163	$	2,369

(a) Natural gas distribution revenues include $5 million for each of the three months ended June 30, 2019 and 2018 and $8 million for each of the six months ended June 30, 2019 and 2018 of revenues not accounted for under ASC 606.

(b) Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(c) Revenues from gas pipeline investments include $8 million and $16 million for the three and six months ended June 30, 2019, respectively, accounted for as leases.

(d) Wholesale gas services revenues are presented net of the related costs associated with its energy trading and risk management activities. Operating revenues, as presented, include gross third-party revenues of $1.2 billion, $1.3 billion, $3.1 billion, and $3.3 billion for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of which $0.8 billion, $0.7 billion, $2.0 billion, and $1.8 billion, respectively, relates to contracts accounted for as derivatives. See Note (M) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.

(e)

Gas marketing services include $2 million for the three months ended June 30, 2019 and $11 million and $4 million for the six months ended June 30, 2019 and 2018, respectively, of revenues not accounted for under ASC 606.

Contract with Customer, Asset and Liability and Revenue Recognized

The following table reflects revenue from contracts with customers recognized in the three and six months ended June 30, 2019 included in the contract liability at December 31, 2018:

	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
	(in millions)
Southern Company	$	11	$	27
Southern Power	1		11

The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers as of June 30, 2019 and December 31, 2018:

	Receivables				Contract Assets				Contract Liabilities
	June 30, 2019		December 31, 2018		June 30, 2019		December 31, 2018		June 30, 2019		December 31, 2018
	(in millions)
Southern Company(*)	$	2,343	$	2,630	$	70	$	102	$	58	$	32
Alabama Power	629		520		—		—		10		12
Georgia Power	807		721		30		58		26		7
Mississippi Power	93		100		—		—		7		—
Southern Power	119		118		—		—		1		11
Southern Company Gas	550		952		—		—		1		2

(*)

Includes amounts related to held for sale investments.

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

Registrants with revenues from contracts with customers related to these performance obligations remaining at June 30, 2019 expect the revenues to be recognized as follows:

	2019 (remaining)		2020		2021		2022		2023		Thereafter
	(in millions)
Southern Company	$	282	$	490	$	320	$	311	$	302	$	2,230
Alabama Power	11		23		27		23		22		140
Georgia Power	27		51		44		31		31		83
Southern Power	169		295		270		276		269		2,154

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Consolidated Entities and Equity Method Investments (Tables)

6 Months Ended

Jun. 30, 2019

Regulated Operations [Abstract]

Equity Method Investments

Selected financial information of SNG for the three and six months ended June 30, 2019 and 2018 is as follows:

Income Statement Information	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
	(in millions)
Revenues	$	155	$	146	$	321	$	306
Operating income	86		60		192		159
Net income	64		54		148		132

The carrying amounts of Southern Company Gas' equity method investments as of June 30, 2019 and December 31, 2018 and related income from those investments for the three- and six-month periods ended June 30, 2019 and 2018 were as follows:

Investment Balance	June 30, 2019		December 31, 2018
	(in millions)
SNG	$	1,243	$	1,261
Atlantic Coast Pipeline	101		83
PennEast Pipeline	77		71
Other(*)	88		123
Total	$	1,509	$	1,538

(*)

Decrease primarily relates to the sale of Triton.

Schedule of Other Nonoperating Income, by Component

Earnings from Equity Method Investments	Three Months Ended June 30, 2019			Three Months Ended June 30, 2018		Six Months Ended June 30, 2019			Six Months Ended June 30, 2018
	(in millions)
SNG	$	32		$	27	$	74		$	66
Atlantic Coast Pipeline	3			1		6			3
PennEast Pipeline	1			1		3			2
Other(*)	(5		)	2		(3		)	3
Total	$	31		$	31	$	80		$	74

(*)

Decrease primarily relates to the sale of Triton.

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Financing (Tables)

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

Credit Arrangements by Company

The following table outlines the committed credit arrangements by company as of June 30, 2019:

	Expires
Company	2019		2020		2022		2024		Total		Unused		Due within One Year
	(in millions)
Southern Company(a)	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—
Alabama Power	3		500		—		800		1,303		1,303		3
Georgia Power	—		—		—		1,750		1,750		1,736		—
Mississippi Power	—		—		150		—		150		150		—
Southern Power(b)	—		—		—		600		600		561		—
Southern Company Gas(c)	—		—		—		1,750		1,750		1,745		—
Other	—		30		—		—		30		30		30
Southern Company Consolidated	$	3	$	530	$	150	$	6,900	$	7,583	$	7,524	$	33

(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 $30 million was unused at June 30, 2019. 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 $1.25 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.

Schedule of Long-term Debt Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2019:

Company	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)	$	2,100	$	—	$	—	$	—	$	—
Alabama Power	200		—		—		—		—
Georgia Power	—		513		223		835		3
Mississippi Power	—		43		—		—		—
Other	—		—		25		—		9
Southern Company Consolidated	$	2,300	$	556	$	248	$	835	$	12

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

(b)

Represents the Southern Company parent entity.

Shares Used to Compute Diluted Earnings Per Share

Shares used to compute diluted earnings per share were as follows:

	Three Months Ended June 30, 2019	Three Months Ended June 30, 2018	Six Months Ended June 30, 2019	Six Months Ended June 30, 2018
	(in millions)
As reported shares	1,044	1,014	1,041	1,012
Effect of stock-based compensation	8	—	8	5
Diluted shares	1,052	1,014	1,049	1,017

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Retirement Benefits (Tables)

6 Months Ended

Jun. 30, 2019

Retirement Benefits [Abstract]

Pension Plans and Postretirement Plans

Components of the net periodic benefit costs for the three and six months ended June 30, 2019 and 2018 are presented in the following tables.

Three Months Ended June 30, 2019	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	73		$	17		$	18		$	3		$	1		$	6
Interest cost	123			29			39			5			2			9
Expected return on plan assets	(221		)	(52		)	(73		)	(10		)	(3		)	(15		)
Amortization:
Prior service costs	1			1			1			—			—			—
Regulatory asset	—			—			—			—			—			4
Net (gain)/loss	30			9			11			2			—			—
Net periodic pension cost (income)	$	6		$	4		$	(4	)	$	—		$	—		$	4
Postretirement Benefits
Service cost	$	4		$	1		$	1		$	—		$	—		$	—
Interest cost	17			4			6			1			—			3
Expected return on plan assets	(17		)	(7		)	(6		)	(1		)	—			(1		)
Amortization:
Prior service costs	1			1			—			—			—			—
Regulatory asset	—			—			—			—			—			1
Net (gain)/loss	—			—			—			—			—			(1		)
Net periodic postretirement benefit cost	$	5		$	(1	)	$	1		$	—		$	—		$	2

Six Months Ended June 30, 2019	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	146		$	34		$	37		$	6		$	3		$	12
Interest cost	246			57			78			11			3			18
Expected return on plan assets	(442		)	(103		)	(146		)	(20		)	(5		)	(30		)
Amortization:
Prior service costs	1			1			1			—			—			(1		)
Regulatory asset	—			—			—			—			—			7
Net (gain)/loss	60			18			22			3			—			1
Net periodic pension cost (income)	$	11		$	7		$	(8	)	$	—		$	1		$	7
Postretirement Benefits
Service cost	$	9		$	2		$	2		$	—		$	—		$	1
Interest cost	34			8			13			2			—			5
Expected return on plan assets	(33		)	(13		)	(12		)	(1		)	—			(3		)
Amortization:
Prior service costs	2			2			—			—			—			—
Regulatory asset	—			—			—			—			—			3
Net (gain)/loss	(1		)	—			—			—			—			(2		)
Net periodic postretirement benefit cost	$	11		$	(1	)	$	3		$	1		$	—		$	4

Three Months Ended June 30, 2018	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	89		$	20		$	21		$	4		$	2		$	8
Interest cost	116			25			35			5			2			9
Expected return on plan assets	(235		)	(53		)	(74		)	(10		)	(2		)	(17		)
Amortization:
Prior service costs	1			1			1			—			—			—
Regulatory asset	—			—			—			—			—			4
Net (gain)/loss	54			13			17			2			—			3
Net periodic pension cost (income)	$	25		$	6		$	—		$	1		$	2		$	7
Postretirement Benefits
Service cost	$	6		$	2		$	1		$	1		$	—		$	—
Interest cost	18			4			7			1			—			3
Expected return on plan assets	(17		)	(7		)	(7		)	(1		)	—			(2		)
Amortization:
Prior service costs	1			1			1			—			—			—
Regulatory asset	—			—			—			—			—			2
Net (gain)/loss	4			1			2			—			—			—
Net periodic postretirement benefit cost	$	12		$	1		$	4		$	1		$	—		$	3

Six Months Ended June 30, 2018	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	179		$	39		$	43		$	8		$	4		$	16
Interest cost	232			50			70			10			3			19
Expected return on plan assets	(471		)	(104		)	(148		)	(20		)	(5		)	(35		)
Amortization:
Prior service costs	2			1			1			—			—			(1		)
Regulatory asset	—			—			—			—			—			7
Net (gain)/loss	107			27			34			5			1			6
Net periodic pension cost (income)	$	49		$	13		$	—		$	3		$	3		$	12
Postretirement Benefits
Service cost	$	12		$	3		$	3		$	1		$	—		$	1
Interest cost	37			8			14			2			—			5
Expected return on plan assets	(34		)	(13		)	(13		)	(1		)	—			(4		)
Amortization:
Prior service costs	3			2			1			—			—			—
Regulatory asset	—			—			—			—			—			3
Net (gain)/loss	7			1			4			—			—			—
Net periodic postretirement benefit cost	$	25		$	1		$	9		$	2		$	—		$	5

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

Assets and Liabilities Measured at Fair Value on a Recurring Basis

As of June 30, 2019, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using:
As of June 30, 2019:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives(a)	$	270	$	177	$	12	$	—	$	459
Foreign currency derivatives	—		60		—		—		60
Investments in trusts:(b)(c)
Domestic equity	703		124		—		—		827
Foreign equity	62		206		—		—		268
U.S. Treasury and government agency securities	—		307		—		—		307
Municipal bonds	—		72		—		—		72
Pooled funds – fixed income	—		16		—		—		16
Corporate bonds	23		299		—		—		322
Mortgage and asset backed securities	—		74		—		—		74
Private equity	—		—		—		54		54
Cash and cash equivalents	1		—		—		—		1
Other	27		2		—		—		29
Cash equivalents	841		5		—		—		846
Other investments	9		17		—		—		26
Total	$	1,936	$	1,359	$	12	$	54	$	3,361
Liabilities:
Energy-related derivatives(a)	$	405	$	189	$	22	$	—	$	616
Interest rate derivatives	—		52		—		—		52
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		21		—		21
Total	$	405	$	264	$	43	$	—	$	712

	Fair Value Measurements Using:
As of June 30, 2019:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Alabama Power
Assets:
Energy-related derivatives	$	—	$	6	$	—	$	—	$	6
Nuclear decommissioning trusts:(b)
Domestic equity	456		113		—		—		569
Foreign equity	62		60		—		—		122
U.S. Treasury and government agency securities	—		21		—		—		21
Municipal bonds	—		1		—		—		1
Corporate bonds	23		141		—		—		164
Mortgage and asset backed securities	—		25		—		—		25
Private equity	—		—		—		54		54
Other	7		—		—		—		7
Cash equivalents	430		5		—		—		435
Other investments	—		17		—		—		17
Total	$	978	$	389	$	—	$	54	$	1,421
Liabilities:
Energy-related derivatives	$	—	$	18	$	—	$	—	$	18
Georgia Power
Assets:
Energy-related derivatives	$	—	$	6	$	—	$	—	$	6
Nuclear decommissioning trusts:(b)(c)
Domestic equity	247		1		—		—		248
Foreign equity	—		143		—		—		143
U.S. Treasury and government agency securities	—		286		—		—		286
Municipal bonds	—		71		—		—		71
Corporate bonds	—		158		—		—		158
Mortgage and asset backed securities	—		50		—		—		50
Other	20		2		—		—		22
Total	$	267	$	717	$	—	$	—	$	984
Liabilities:
Energy-related derivatives	$	—	$	43	$	—	$	—	$	43
Interest rate derivatives	—		37		—		—		37
Total	$	—	$	80	$	—	$	—	$	80

	Fair Value Measurements Using:
As of June 30, 2019:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Cash equivalents	170		—		—		—		170
Total	$	170	$	3	$	—	$	—	$	173
Liabilities:
Energy-related derivatives	$	—	$	19	$	—	$	—	$	19
Southern Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	—	$	2
Foreign currency derivatives	—		60		—		—		60
Cash equivalents	177		—		—		—		177
Total	$	177	$	62	$	—	$	—	$	239
Liabilities:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		21		—		21
Total	$	—	$	27	$	21	$	—	$	48
Southern Company Gas
Assets:
Energy-related derivatives(a)	$	270	$	160	$	12	$	—	$	442
Non-qualified deferred compensation trusts:
Domestic equity	—		10		—		—		10
Foreign equity	—		4		—		—		4
Pooled funds – fixed income	—		16		—		—		16
Cash equivalents	1		—		—		—		1
Total	$	271	$	190	$	12	$	—	$	473
Liabilities:
Energy-related derivatives(a)	$	405	$	105	$	22	$	—	$	532

(a) Energy-related derivatives exclude cash collateral of $178 million.

(b) Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

(c) Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of June 30, 2019, approximately $30 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

Schedule of Increase (Decrease) In Fair Value Of Funds

The fair value of the funds, including reinvested interest

and dividends and excluding the funds' expenses, increased (decreased) by the amounts shown in the table below for the three and six months ended June 30, 2019 and 2018. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.

	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018			Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
	(in millions)
Southern Company	$	75	$	14		$	227	$	4
Alabama Power	38		15			125		10
Georgia Power	37		(1		)	102		(6		)

Financial Instruments for Which Carrying Amount Did Not Equal Fair Value

As of June 30, 2019, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas(*)
	(in millions)
Long-term debt, including securities due within one year:
Carrying amount	$	42,596	$	7,922	$	10,969	$	1,618	$	5,011	$	5,916
Fair value	45,394		8,717		11,749		1,657		5,261		6,420

(*)

The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the lives of the respective bonds.

Fair Value of Commodity Derivative Contracts that Include a Significant Unobservable Component

The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period.

	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	(in millions)
Beginning balance	$	(19	)	$	—
Transfers to Level 3	(3		)	(33		)
Changes in fair value	12			23
Ending balance	$	(10	)	$	(10	)

XML

Derivatives (Tables)

6 Months Ended

Jun. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Energy-Related Derivatives

At June 30, 2019, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:

	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)
Southern Company(*)	536	2023	2029
Alabama Power	88	2022	—
Georgia Power	200	2022	—
Mississippi Power	101	2023	—
Southern Power	8	2020	—
Southern Company Gas(*)	139	2021	2029

(*)

Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 4.0 billion mmBtu and short natural gas positions of 3.9 billion mmBtu as of June 30, 2019, which is also included in Southern Company's total volume.

Schedule of Interest Rate Derivatives

At June 30, 2019, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date	Fair Value Gain (Loss) at June 30, 2019
	(in millions)					(in millions)
Cash Flow Hedges of Forecasted Debt
Georgia Power	$	250	3-month LIBOR	2.23%	March 2025	$	(6	)
Georgia Power	250		3-month LIBOR	2.39%	September 2029	(10		)
Georgia Power	250		3-month LIBOR	2.40%	March 2030	(9		)
Georgia Power	250		3-month LIBOR	2.48%	February 2044	(12		)
Fair Value Hedges of Existing Debt
Southern Company(*)	300		2.75%	3-month LIBOR+0.92%	June 2020	(1		)
Southern Company(*)	1,500		2.35%	1-month LIBOR+0.87%	July 2021	(14		)
Georgia Power	200		4.25%	3-month LIBOR+2.46%	December 2019	(1		)
Southern Company Consolidated	$	3,000				$	(53	)

(*)

Represents the Southern Company parent entity.

Schedule of Foreign Currency Derivatives

At June 30, 2019, the following foreign currency derivatives were outstanding:

	Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at June 30, 2019
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	14
Southern Power	564		3.78%	500		1.85%	June 2026	23
Total	$	1,241		€	1,100			$	37

Fair Value of Energy-Related Derivatives and Interest Rate Derivatives

The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:

	As of June 30, 2019						As of December 31, 2018
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Southern Company
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	7		$	57		$	8		$	23
Other deferred charges and assets/Other deferred credits and liabilities	9			34			9			26
Assets held for sale, current/Liabilities held for sale, current	—			—			—			6
Total derivatives designated as hedging instruments for regulatory purposes	$	16		$	91		$	17		$	55
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	7		$	3		$	7
Other deferred charges and assets/Other deferred credits and liabilities	—			1			1			2
Interest rate derivatives:
Other current assets/Other current liabilities	—			50			—			19
Other deferred charges and assets/Other deferred credits and liabilities	—			2			—			30
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	60			—			75			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	61		$	83		$	79		$	81
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	286		$	298		$	561		$	575
Other deferred charges and assets/Other deferred credits and liabilities	156			219			180			325
Total derivatives not designated as hedging instruments	$	442		$	517		$	741		$	900
Gross amounts recognized	$	519		$	691		$	837		$	1,036
Gross amounts offset(a)	$	(328	)	$	(506	)	$	(524	)	$	(801	)
Net amounts recognized in the Balance Sheets(b)	$	191		$	185		$	313		$	235

	As of June 30, 2019						As of December 31, 2018
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Alabama Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	4		$	11		$	3		$	4
Other deferred charges and assets/Other deferred credits and liabilities	2			7			3			6
Total derivatives designated as hedging instruments for regulatory purposes	$	6		$	18		$	6		$	10
Gross amounts recognized	$	6		$	18		$	6		$	10
Gross amounts offset	$	(3	)	$	(3	)	$	(4	)	$	(4	)
Net amounts recognized in the Balance Sheets	$	3		$	15		$	2		$	6
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	26		$	2		$	8
Other deferred charges and assets/Other deferred credits and liabilities	5			17			4			13
Total derivatives designated as hedging instruments for regulatory purposes	$	6		$	43		$	6		$	21
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	37		$	—		$	2
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	37		$	—		$	2
Gross amounts recognized	$	6		$	80		$	6		$	23
Gross amounts offset	$	(6	)	$	(6	)	$	(6	)	$	(6	)
Net amounts recognized in the Balance Sheets	$	—		$	74		$	—		$	17

	As of June 30, 2019						As of December 31, 2018
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	10		$	1		$	3
Other deferred charges and assets/Other deferred credits and liabilities	2			9			2			6
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	19		$	3		$	9
Gross amounts recognized	$	3		$	19		$	3		$	9
Gross amounts offset	$	(3	)	$	(3	)	$	(2	)	$	(2	)
Net amounts recognized in the Balance Sheets	$	—		$	16		$	1		$	7
Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	3		$	3		$	6
Other deferred charges and assets/Other deferred credits and liabilities	—			1			1			2
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	60			—			75			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	61		$	27		$	79		$	31
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	—		$	—		$	—
Total derivatives not designated as hedging instruments	$	1		$	—		$	—		$	—
Gross amounts recognized	$	62		$	27		$	79		$	31
Gross amounts offset	$	(1	)	$	(1	)	$	(3	)	$	(3	)
Net amounts recognized in the Balance Sheets	$	61		$	26		$	76		$	28

	As of June 30, 2019						As of December 31, 2018
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Southern Company Gas
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	1		$	10		$	2		$	8
Other deferred charges and assets/Other deferred credits and liabilities	—			1			—			1
Total derivatives designated as hedging instruments for regulatory purposes	$	1		$	11		$	2		$	9
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	—		$	4		$	—		$	1
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	4		$	—		$	1
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	285		$	298		$	559		$	574
Other deferred charges and assets/Other deferred credits and liabilities	156			219			180			325
Total derivatives not designated as hedging instruments	$	441		$	517		$	739		$	899
Gross amounts of recognized	$	442		$	532		$	741		$	909
Gross amounts offset(a)	$	(315	)	$	(493	)	$	(508	)	$	(785	)
Net amounts recognized in the Balance Sheets(b)	$	127		$	39		$	233		$	124

(a) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $178 million and $277 million as of June 30, 2019 and December 31, 2018, respectively.

(b)

Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $8 million as of December 31, 2018.

Pre-tax Effects of Unrealized Derivative Gains (Losses) Arising from Energy-Related Derivative Instruments

At June 30, 2019 and December 31, 2018, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at June 30, 2019
Derivative Category and Balance Sheet Location	Southern Company(*)			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas(*)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(48	)	$	(11	)	$	(25	)	$	(10	)	$	(2	)
Other regulatory assets, deferred	(23		)	(5		)	(12		)	(6		)	—
Other regulatory liabilities, current	6			3			—			—			3
Total energy-related derivative gains (losses)	$	(65	)	$	(13	)	$	(37	)	$	(16	)	$	1

(*) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $12 million at June 30, 2019.

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2018
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(19	)	$	(3	)	$	(6	)	$	(2	)	$	(8	)
Other regulatory assets, deferred	(16		)	(3		)	(9		)	(4		)	—
Assets held for sale, current	(6		)	—			—			—			—
Other regulatory liabilities, current	1			—			—			—			1
Total energy-related derivative gains (losses)	$	(40	)	$	(6	)	$	(15	)	$	(6	)	$	(7	)

Pre-tax Effects of Interest Rate Derivatives, Designated as Cash Flow Hedging Instruments

For the three and six months ended June 30, 2019 and 2018, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:

Gain (Loss) Recognized in OCI on Derivative	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)						(in millions)
Southern Company
Energy-related derivatives	$	(6	)	$	—		$	(6	)	$	12
Interest rate derivatives	(37		)	—			(37		)	(2		)
Foreign currency derivatives	(1		)	(73		)	(39		)	(21		)
Total	$	(44	)	$	(73	)	$	(82	)	$	(11	)
Georgia Power
Interest rate derivatives	$	(37	)	$	—		$	(37	)	$	—
Total	$	(37	)	$	—		$	(37	)	$	—
Southern Power
Energy-related derivatives	$	(2	)	$	(1	)	$	(2	)	$	10
Foreign currency derivatives	(1		)	(73		)	(39		)	(21		)
Total	$	(3	)	$	(74	)	$	(41	)	$	(11	)

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location

For the three and six months ended June 30, 2019 and 2018, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)						(in millions)
Southern Company
Total depreciation and amortization	$	755		$	783		$	1,506		$	1,552
Gain (loss) on energy-related cash flow hedges(a)	(1		)	1			(4		)	2
Total interest expense, net of amounts capitalized	(429		)	(470		)	(859		)	(928		)
Gain (loss) on interest rate cash flow hedges(a)	(5		)	(6		)	(9		)	(11		)
Gain (loss) on foreign currency cash flow hedges(a)	(6		)	(7		)	(12		)	(12		)
Gain (loss) on interest rate fair value hedges(b)	19			(7		)	33			(31		)
Total other income (expense), net	99			78			176			138
Gain (loss) on foreign currency cash flow hedges(a)(c)	16			(73		)	(8		)	(37		)
Southern Power
Total depreciation and amortization	$	119		$	125		$	237		$	240
Gain (loss) on energy-related cash flow hedges(a)	(1		)	1			(4		)	2
Total interest expense, net of amounts capitalized	(41		)	(46		)	(84		)	(93		)
Gain (loss) on foreign currency cash flow hedges(a)	(6		)	(7		)	(12		)	(12		)
Total other income (expense), net	40			2			41			5
Gain (loss) on foreign currency cash flow hedges(a)(c)	16			(73		)	(8		)	(37		)

(a) Reclassified from accumulated OCI into earnings.

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

(c)

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

Schedule of Fair Value Hedging Instruments, Statements of Financial Performance and Financial Position, Location

As of June 30, 2019 and December 31, 2018, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

	Carrying Amount of the Hedged Item						Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	As of June 30, 2019			As of December 31, 2018			As of June 30, 2019		As of December 31, 2018
	(in millions)						(in millions)
Southern Company
Securities due within one year	$	(499	)	$	(498	)	$	1	$	2
Long-term debt	(2,087		)	(2,052		)	7		41
Georgia Power
Securities due within one year	$	(499	)	$	(498	)	$	1	$	2

Pre-tax Effect of Interest Rate and Energy Related Derivatives

For the three and six months ended June 30, 2019 and 2018, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:

		Gain (Loss)
		Three Months Ended June 30,						Six Months Ended June 30,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2019			2018			2019		2018
		(in millions)						(in millions)
Southern Company
Energy-related derivatives:	Natural gas revenues(*)	$	50		$	(28	)	$	83	$	(43	)
	Cost of natural gas	(5		)	2			3		4
Total derivatives in non-designated hedging relationships		$	45		$	(26	)	$	86	$	(39	)
Southern Company Gas
Energy-related derivatives:	Natural gas revenues(*)	$	50		$	(28	)	$	83	$	(43	)
	Cost of natural gas	(5		)	2			3		4
Total derivatives in non-designated hedging relationships		$	45		$	(26	)	$	86	$	(39	)

(*)

Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for all periods presented.

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Acquisitions and Dispositions (Tables)

6 Months Ended

Jun. 30, 2019

Business Combinations [Abstract]

Schedule of Construction Projects

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Projects Completed During the Six Months Ended June 30, 2019
Mankato expansion(a)	Natural Gas	385	Mankato, MN	May 2019	20 years
Projects Under Construction as of June 30, 2019
Wildhorse Mountain(b)	Wind	100	Pushmataha County, OK	Fourth quarter 2019	20 years
Reading(c)	Wind	200	Osage and Lyon Counties, KS	Second quarter 2020	12 years

(a) In November 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato, including this expansion that was completed during May 2019. This transaction is subject to state commission approvals and is expected to close in fall 2019. The expansion unit started providing energy under a PPA with Northern States Power on June 1, 2019. See "Sales of Natural Gas and Biomass Plants" below.

(b) In May 2018, Southern Power purchased 100% of the Wildhorse Mountain facility. Southern Power entered into a tax equity partnership in June 2019 with funding of tax equity amounts expected to occur upon commercial operation.

(c)

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. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the class B membership interests.

Disposal Groups, Including Discontinued Operations

Gulf Power and Southern Power's equity interests in Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) and Plant Nacogdoches represented individually significant components of Southern Company and Southern Power, respectively; therefore, pre-tax profit for these components for the three and six months ended June 30, 2019 and 2018 is presented below:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
	(in millions)
Earnings before income taxes:
Gulf Power	$	—	$	31	$	—	$	87
Southern Power's Florida Plants	$	—	$	14	$	—	$	24
Southern Power's Plant Nacogdoches(*)	$	9	$	7	$	16	$	13

(*)

Earnings before income taxes for Plant Nacogdoches for the three and six months ended June 30, 2019 represents the beginning of the corresponding period through June 13, 2019 (the divestiture date).

The following table provides Southern Company's and Southern Power's major classes of assets and liabilities classified as held for sale at June 30, 2019 and December 31, 2018:

	Southern Company		Southern Power
	(in millions)
At June 30, 2019
Assets Held for Sale:
Current assets	$	58	$	10
Total property, plant, and equipment	588		559
Goodwill and other intangible assets	51		40
Other non-current assets	46		—
Total Assets Held for Sale	$	743	$	609
Liabilities Held for Sale:
Current liabilities	$	36	$	10
Other non-current liabilities	39		—
Total Liabilities Held for Sale	$	75	$	10
At December 31, 2018
Assets Held for Sale:
Current assets	$	393	$	8
Total property, plant, and equipment	4,583		536
Other intangible assets	40		40
Other non-current assets	727		—
Total Assets Held for Sale	$	5,743	$	584
Liabilities Held for Sale:
Current liabilities	$	425	$	15
Long-term debt	1,286		—
Accumulated deferred income taxes	618		—
Other non-current liabilities	932		—
Total Liabilities Held for Sale	$	3,261	$	15

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Leases (Tables)

6 Months Ended

Jun. 30, 2019

Leases [Abstract]

Major Categories of Lease Obligations

The major categories of lease obligations are as follows:

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Electric generating units	$	1,072	$	150	$	1,580	$	—	$	—	$	—
Real estate/land	800		4		62		2		395		81
Communication towers	147		1		3		—		—		13
Railcars	54		25		27		3		—		—
Other	145		10		14		2		—		—
Total	$	2,218	$	190	$	1,686	$	7	$	395	$	94

Balance Sheet Amounts Recorded for Operating and Financing Leases

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

	As of June 30, 2019
	Southern  Company(*)		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Operating Leases
Operating lease ROU assets, net	$	1,907	$	152	$	1,492	$	7	$	370	$	95
Operating lease obligations - current	$	241	$	48	$	140	$	2	$	22	$	15
Operating lease obligations - non current	1,733		137		1,377		5		373		79
Total operating lease obligations	$	1,974	$	185	$	1,517	$	7	$	395	$	94
Finance Leases
Finance lease ROU assets, net	$	237	$	5	$	142	$	—	$	—	$	—
Finance lease obligations - current	$	24	$	1	$	10	$	—	$	—	$	—
Finance lease obligations - noncurrent	220		4		159		—		—		—
Total finance lease obligations	$	244	$	5	$	169	$	—	$	—	$	—

(*)

Includes operating lease ROU assets, net and operating lease obligations classified as held for sale.

Lease Costs and Other Information

Lease costs for the three and six months ended June 30, 2019, which includes both amounts recognized as operations and maintenance expense and amounts capitalized as part of the cost of another asset, are as follows:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended June 30, 2019
Lease cost
Operating lease cost	$	77	$	13	$	50	$	1	$	7	$	5
Finance lease cost:
Amortization of ROU assets	7		—		4		—		—		—
Interest on lease obligations	3		—		4		—		—		—
Total finance lease cost	10		—		8		—		—		—
Short-term lease costs	13		6		6		—		—		—
Variable lease cost	29		1		25		—		1		—
Sublease income	—		—		—		—		—		—
Total lease cost	$	129	$	20	$	89	$	1	$	8	$	5
For the Six Months Ended June 30, 2019
Lease cost
Operating lease cost	$	147	$	20	$	99	$	1	$	14	$	9
Finance lease cost:
Amortization of ROU assets	14		—		7		—		—		—
Interest on lease obligations	6		—		9		—		—		—
Total finance lease cost	20		—		16		—		—		—
Short-term lease costs	30		11		12		—		—		—
Variable lease cost	48		1		41		—		3		—
Sublease income	—		—		—		—		—		—
Total lease cost	$	245	$	32	$	168	$	1	$	17	$	9

Georgia Power has variable lease payments that are based on the amount of energy produced by certain renewable generating facilities subject to PPAs.

Other information with respect to cash and noncash activities related to leases, as well as weighted-average lease terms and discount rates, is as follows:

	For the Six Months Ended June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Other information
Cash paid for amounts included in the measurements of lease obligations:
Operating cash flows from operating leases	$	129	$	20	$	75	$	1	$	12	$	9
Operating cash flows from finance leases	2		—		10		—		—		—
Financing cash flows from finance leases	16		—		3		—		—		—
ROU assets obtained in exchange for new operating lease obligations	55		5		13		—		—		13
ROU assets obtained in exchange for new finance lease obligations	33		1		28		—		—		—

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
Weighted-average remaining lease term in years:
Operating leases	14.0		3.6		10.5		7.0		33.5		9.7
Finance leases	18.3		12.8		11.0		N/A		N/A		N/A
Weighted-average discount rate:
Operating leases	4.53	%	3.33	%	4.46	%	4.06	%	5.68	%	3.73	%
Finance leases	5.05	%	3.67	%	10.69	%	N/A		N/A		N/A

Maturities of Operating Lease Liabilities

Maturities of lease liabilities are as follows:

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Maturity Analysis
Operating leases:
2019 (remaining)	$	178	$	33	$	129	$	1	$	13	$	9
2020	295		53		203		2		22		17
2021	279		52		198		1		23		16
2022	268		52		196		1		23		13
2023	204		4		197		1		24		11
Thereafter	1,661		2		990		2		849		49
Total	2,885		196		1,913		8		954		115
Less: Present value discount	911		11		396		1		559		21
Operating lease obligations	$	1,974	$	185	$	1,517	$	7	$	395	$	94
Finance leases:
2019 (remaining)	$	16	$	—	$	16	$	—	$	—	$	—
2020	33		1		28		—		—		—
2021	27		1		25		—		—		—
2022	23		1		25		—		—		—
2023	18		1		25		—		—		—
Thereafter	266		1		165		—		—		—
Total	383		5		284		—		—		—
Less: Present value discount	139		—		115		—		—		—
Finance lease obligations	$	244	$	5	$	169	$	—	$	—	$	—

Maturities of Finance Lease Liabilities

Maturities of lease liabilities are as follows:

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
Maturity Analysis
Operating leases:
2019 (remaining)	$	178	$	33	$	129	$	1	$	13	$	9
2020	295		53		203		2		22		17
2021	279		52		198		1		23		16
2022	268		52		196		1		23		13
2023	204		4		197		1		24		11
Thereafter	1,661		2		990		2		849		49
Total	2,885		196		1,913		8		954		115
Less: Present value discount	911		11		396		1		559		21
Operating lease obligations	$	1,974	$	185	$	1,517	$	7	$	395	$	94
Finance leases:
2019 (remaining)	$	16	$	—	$	16	$	—	$	—	$	—
2020	33		1		28		—		—		—
2021	27		1		25		—		—		—
2022	23		1		25		—		—		—
2023	18		1		25		—		—		—
Thereafter	266		1		165		—		—		—
Total	383		5		284		—		—		—
Less: Present value discount	139		—		115		—		—		—
Finance lease obligations	$	244	$	5	$	169	$	—	$	—	$	—

Lease Income, Sales-type Leases

Lease income for the three and six months ended June 30, 2019 is as follows:

	Southern Company		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended June 30, 2019
Lease income - interest income on sales-type leases	$	2	$	—	$	2	$	—	$	—
Lease income - operating leases	67		19		—		39		9
Variable lease income	115		—		—		125		—
Total lease income	$	184	$	19	$	2	$	164	$	9
For the Six Months Ended June 30, 2019
Lease income - interest income on sales-type leases	$	5	$	—	$	5	$	—	$	—
Lease income - operating leases	139		39		—		80		17
Variable lease income	182		—		—		198		—
Total lease income	$	326	$	39	$	5	$	278	$	17

Lease Income, Operating Leases

Lease income for the three and six months ended June 30, 2019 is as follows:

	Southern Company		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
	(in millions)
For the Three Months Ended June 30, 2019
Lease income - interest income on sales-type leases	$	2	$	—	$	2	$	—	$	—
Lease income - operating leases	67		19		—		39		9
Variable lease income	115		—		—		125		—
Total lease income	$	184	$	19	$	2	$	164	$	9
For the Six Months Ended June 30, 2019
Lease income - interest income on sales-type leases	$	5	$	—	$	5	$	—	$	—
Lease income - operating leases	139		39		—		80		17
Variable lease income	182		—		—		198		—
Total lease income	$	326	$	39	$	5	$	278	$	17

Undiscounted Cash Flows to be Received Under Tolling Arrangements Accounted for as Sales-type Leases

The undiscounted cash flows to be received under tolling arrangements accounted for as sales-type leases are as follows:

	As of June 30, 2019
	Southern Company		Mississippi Power
	(in millions)
2019 (remaining)	$	7	$	7
2020	14		14
2021	14		14
2022	13		13
2023	12		12
Thereafter	135		135
Total undiscounted cash flows	$	195	$	195
Lease receivable	106		106
Difference between undiscounted cash flows and discounted cash flows	$	89	$	89

Undiscounted Cash Flows to be Received Under PPAs Accounted for as Operating Leases

The undiscounted cash flows to be received under operating leases and contracts accounted for as operating leases (adjusted for intercompany eliminations) are as follows:

	As of June 30, 2019
	Southern Company		Georgia Power		Southern Power		Southern Company Gas
	(in millions)
2019 (remaining)	$	75	$	13	$	52	$	17
2020	125		26		65		35
2021	118		18		66		35
2022	109		8		68		34
2023	103		2		69		34
Thereafter	1,142		—		350		497
Total	$	1,672	$	67	$	670	$	652

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Segment and Related Information (Tables)

6 Months Ended

Jun. 30, 2019

Segment Reporting [Abstract]

Financial Data for Business Segments

Financial data for business segments and products and services for the three and six months ended June 30, 2019 and 2018 was as follows:

	Electric Utilities
	Traditional Electric Operating Companies			Southern Power		Eliminations			Total			Southern Company Gas			All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2019
Operating revenues	$	3,899		$	510	$	(119	)	$	4,290		$	689		$	186		$	(67	)	$	5,098
Segment net income (loss)(a)(b)(c)(d)	782			174		—			956			106			(154		)	(9		)	899
Six Months Ended June 30, 2019
Operating revenues	$	7,343		$	953	$	(211	)	$	8,085		$	2,163		$	368		$	(106	)	$	10,510
Segment net income (loss)(a)(b)(c)(d)	1,346			230		—			1,576			376			1,041			(11		)	2,982
At June 30, 2019
Goodwill	$	—		$	2	$	—		$	2		$	5,015		$	265		$	—		$	5,282
Total assets	78,314			14,518		(783		)	92,049			20,761			3,343			(1,286		)	114,867
Three Months Ended June 30, 2018
Operating revenues	$	4,124		$	555	$	(114	)	$	4,565		$	730		$	381		$	(49	)	$	5,627
Segment net income (loss)(a)(b)(d)	(48		)	22		—			(26		)	(31		)	(100		)	3			(154		)
Six Months Ended June 30, 2018
Operating revenues	$	8,104		$	1,064	$	(220	)	$	8,948		$	2,369		$	782		$	(100	)	$	11,999
Segment net income (loss)(a)(b)(d)(e)	563			143		—			706			248			(174		)	4			784
At December 31, 2018
Goodwill	$	—		$	2	$	—		$	2		$	5,015		$	298		$	—		$	5,315
Total assets	79,382			14,883		(306		)	93,959			21,448			3,285			(1,778		)	116,914

(a) Attributable to Southern Company.

(b) Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated losses on plants under construction of $4 million ($3 million after tax) and $1.1 billion ($0.8 billion after tax) for the three months ended June 30, 2019 and 2018, respectively, and $6 million ($5 million after tax) and $1.1 billion ($0.8 billion after tax) for the six months ended June 30, 2019 and 2018, respectively. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) under "Georgia Power – Nuclear Construction" and "Mississippi Power – Kemper County Energy Facility" for additional information.

(c) Segment net income (loss) for the "All Other" column includes the preliminary pre-tax gain associated with the sale of Gulf Power of $2.5 billion ($1.3 billion after tax) for the six months ended June 30, 2019, of which $(15) million ($(11) million after tax) was recorded in the three months ended June 30, 2019, as well as a goodwill impairment charge of $32 million for the three and six months ended June 30, 2019 in contemplation of the sale of one of PowerSecure's business units. See Note (K) under "Southern Company" for additional information.

(d) Segment net income (loss) for Southern Power includes a $23 million pre-tax gain ($88 million gain after tax) on the sale of Plant Nacogdoches for the three and six months ended June 30, 2019 and a pre-tax impairment charge of $119 million ($89 million after tax) for the three and six months ended June 30, 2018 related to the sale of Southern Power's Florida Plants. See Note (K) under "Southern Power" and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Sale of Natural Gas Plants" for additional information.

(e)

Segment net income (loss) for Southern Company Gas includes a goodwill impairment charge of $42 million for the six months ended June 30, 2018 related to the sale of Pivotal Home Solutions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

Business segment financial data for the three and six months ended June 30, 2019 and 2018 was as follows:

	Gas Distribution Operations(a)		Gas Pipeline Investments		Wholesale Gas Services(b)			Gas Marketing Services(c)(d)			Total			All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2019
Operating revenues	$	568	$	8	$	48		$	58		$	682		$	13		$	(6	)	$	689
Segment net income (loss)	58		25		23			(3		)	103			3			—			106
Six Months Ended June 30, 2019
Operating revenues	$	1,740	$	16	$	134		$	287		$	2,177		$	24		$	(38	)	$	2,163
Segment net income (loss)	191		57		70			58			376			—			—			376
Total assets at June 30, 2019	17,397		1,768		668			1,527			21,360			10,934			(11,533		)	20,761
Three Months Ended June 30, 2018
Operating revenues	$	643	$	8	$	(16	)	$	89		$	724		$	11		$	(5	)	$	730
Segment net income (loss)	68		21		(21		)	(76		)	(8		)	(23		)	—			(31		)
Six Months Ended June 30, 2018
Operating revenues	$	1,856	$	16	$	150		$	359		$	2,381		$	26		$	(38	)	$	2,369
Segment net income (loss)	216		48		83			(63		)	284			(36		)	—			248
Total assets at December 31, 2018	17,266		1,763		1,302			1,587			21,918			11,112			(11,582		)	21,448

(a) Operating revenues for the three gas distribution operations dispositions were $70 million and $237 million for the three and six months ended June 30, 2018, respectively. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

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

	Third Party Gross Revenues		Intercompany Revenues		Total Gross Revenues		Less Gross Gas Costs		Operating Revenues
	(in millions)
Three Months Ended June 30, 2019	$	1,223	$	63	$	1,286	$	1,238	$	48
Three Months Ended June 30, 2018	1,336		102		1,438		1,454		(16		)
Six Months Ended June 30, 2019	$	3,148	$	151	$	3,299	$	3,165	$	134
Six Months Ended June 30, 2018	3,274		269		3,543		3,393		150

(c) Operating revenues for Pivotal Home Solutions were $24 million and $55 million for the three and six months ended June 30, 2018, respectively. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information on the sale of Pivotal Home Solutions.

(d)

Segment net income (loss) for gas marketing services includes a loss on disposition of $36 million for the three and six months ended June 30, 2018 and a goodwill impairment charge of $42 million for the six months ended June 30, 2018 related to the sale of Pivotal Home Solutions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

Financial Data for Products and Services

Products and Services

	Electric Utilities' Revenues
	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended June 30, 2019	$	3,540	$	542	$	208	$	4,290
Three Months Ended June 30, 2018	3,740		616		209		4,565
Six Months Ended June 30, 2019	$	6,623	$	1,041	$	421	$	8,085
Six Months Ended June 30, 2018	7,308		1,239		401		8,948

	Southern Company Gas' Revenues
	Gas Distribution Operations(a)		Gas Marketing Services(b)		Other		Total
	(in millions)
Three Months Ended June 30, 2019	$	563	$	58	$	68	$	689
Three Months Ended June 30, 2018	638		89		3		730
Six Months Ended June 30, 2019	$	1,724	$	287	$	152	$	2,163
Six Months Ended June 30, 2018	1,838		359		172		2,369

(a) Operating revenues for the three gas distribution operations dispositions were $70 million and $237 million for the three and six months ended June 30, 2018, respectively.

(b)

Operating revenues for Pivotal Home Solutions were $24 million and $55 million for the three and six months ended June 30, 2018, respectively.

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Introduction - Narrative (Details)	1 Months Ended	3 Months Ended		6 Months Ended
	Jun. 30, 2019 USD ($)	Jun. 30, 2019 USD ($) business_unit	Jun. 30, 2018 USD ($)	Jun. 30, 2019 USD ($)	Jun. 30, 2018 USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Goodwill impairment		$ 32,000,000		$ 32,000,000
SOUTHERN Co GAS
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Goodwill impairment		0	$ 0	0	$ 42,000,000
Inventory decrement		7,000,000	$ 0	$ 10,000,000	$ 0
ALABAMA POWER CO
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Increase in ARO	$ 308,000,000
MISSISSIPPI POWER CO
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Increase in ARO	$ 58,000,000
Disposal Group, Held-for-sale, Not Discontinued Operations | PowerSecure International, Inc.
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Goodwill impairment		$ 32,000,000
Number Of Business Units | business_unit		1

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Introduction - Goodwill (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Goodwill [Line Items]
Goodwill	$ 5,282	$ 5,315
SOUTHERN Co GAS
Goodwill [Line Items]
Goodwill	5,015	5,015
SOUTHERN Co GAS | Gas Distribution Operations
Goodwill [Line Items]
Goodwill	4,034	4,034
SOUTHERN Co GAS | Gas Marketing Services
Goodwill [Line Items]
Goodwill	$ 981	$ 981

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Introduction - Other Intangible Assets (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Other intangible assets subject to amortization:
Gross Carrying Amount	$ 728	$ 773
Accumulated Amortization	(253)	(235)
Other Intangible Assets, Net	475	538
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75	75
Total other intangible assets
Gross Carrying Amount	803	848
Other Intangible Assets, Net	550	613
Customer relationships
Other intangible assets subject to amortization:
Gross Carrying Amount	211	223
Accumulated Amortization	(105)	(94)
Other Intangible Assets, Net	106	129
Trade names
Other intangible assets subject to amortization:
Gross Carrying Amount	70	70
Accumulated Amortization	(23)	(21)
Other Intangible Assets, Net	47	49
Other
Other intangible assets subject to amortization:
Gross Carrying Amount	12	11
Accumulated Amortization	(7)	(5)
Other Intangible Assets, Net	5	6
SOUTHERN POWER CO
Other intangible assets subject to amortization:
Accumulated Amortization	(60)	(61)
SOUTHERN POWER CO | PPA fair value adjustments
Other intangible assets subject to amortization:
Gross Carrying Amount	371	405
Accumulated Amortization	(60)	(61)
Other Intangible Assets, Net	311	344
SOUTHERN Co GAS
Other intangible assets subject to amortization:
Gross Carrying Amount	246	246
Accumulated Amortization	(161)	(145)
Other Intangible Assets, Net	85	101
Total other intangible assets
Other Intangible Assets, Net	85	101
SOUTHERN Co GAS | Customer relationships
Other intangible assets subject to amortization:
Gross Carrying Amount	156	156
Accumulated Amortization	(95)	(84)
Other Intangible Assets, Net	61	72
SOUTHERN Co GAS | Trade names
Other intangible assets subject to amortization:
Gross Carrying Amount	26	26
Accumulated Amortization	(8)	(7)
Other Intangible Assets, Net	18	19
SOUTHERN Co GAS | Storage and transportation contracts
Other intangible assets subject to amortization:
Gross Carrying Amount	64	64
Accumulated Amortization	(58)	(54)
Other Intangible Assets, Net	$ 6	$ 10

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Introduction - Intangibles, Amortization (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 15	$ 32
SOUTHERN POWER CO
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	4	10
SOUTHERN Co GAS
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	8	16
Gas Marketing Services | SOUTHERN Co GAS
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	6	12
Wholesale Gas Services | SOUTHERN Co GAS
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 2	$ 4

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Introduction - Restricted Cash (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018	Jun. 30, 2018	Dec. 31, 2017
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	$ 1,383	$ 1,396
Cash and cash equivalents held for sale		9
Restricted cash:
Total cash, cash equivalents, and restricted cash	1,386	1,519	$ 2,017	$ 2,147
Restricted cash
Restricted cash:
Restricted cash		0
Other accounts and notes receivable
Restricted cash:
Restricted cash	4	114
GEORGIA POWER CO
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	10	4
Cash and cash equivalents held for sale		0
Restricted cash:
Total cash, cash equivalents, and restricted cash	10	112	11	852
GEORGIA POWER CO | Restricted cash
Restricted cash:
Restricted cash		108
GEORGIA POWER CO | Other accounts and notes receivable
Restricted cash:
Restricted cash		0
SOUTHERN Co GAS
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	56	64
Cash and cash equivalents held for sale		0
Restricted cash:
Total cash, cash equivalents, and restricted cash	60	70	$ 75	$ 78
SOUTHERN Co GAS | Restricted cash
Restricted cash:
Restricted cash		0
SOUTHERN Co GAS | Other accounts and notes receivable
Restricted cash:
Restricted cash	$ 4	$ 6

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Introduction - Asset Retirement Obligations (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($)
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at December 31, 2018	$ 9,394
Liabilities incurred	6
Liabilities settled	(142)
Accretion	197
Cash flow revisions	452
Balance at June 30, 2019	9,907
ALABAMA POWER CO
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at December 31, 2018	3,210
Liabilities incurred	0
Liabilities settled	(43)
Accretion	70
Cash flow revisions	308
Balance at June 30, 2019	3,545
MISSISSIPPI POWER CO
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at December 31, 2018	160
Liabilities incurred	0
Liabilities settled	(17)
Accretion	2
Cash flow revisions	59
Balance at June 30, 2019	$ 204

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Regulatory Matters - Cost Recovery Clauses (Details) - USD ($) $ in Millions	Jun. 30, 2019	Feb. 05, 2019	Dec. 31, 2018
ALABAMA POWER CO
Loss Contingencies [Line Items]
Rate RSE Refund Liability		$ 75
ALABAMA POWER CO | Deferred under recovered regulatory clause revenues
Loss Contingencies [Line Items]
Rate CNP Compliance	$ 0		$ 42
Rate CNP PPA	25		25
Retail Energy Cost Recovery	0		109
ALABAMA POWER CO | Customer accounts receivable
Loss Contingencies [Line Items]
Rate CNP Compliance	10		0
Retail Energy Cost Recovery	8		0
ALABAMA POWER CO | Other regulatory liabilities, deferred
Loss Contingencies [Line Items]
Natural Disaster Reserve	19		20
GEORGIA POWER CO | Receivables – under recovered fuel clause revenues
Loss Contingencies [Line Items]
Fuel Cost Recovery	69		115
MISSISSIPPI POWER CO | Over recovered regulatory clause liabilities
Loss Contingencies [Line Items]
Fuel Cost Recovery	$ 9		$ 8

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Regulatory Matters - Alabama Power (Details) - ALABAMA POWER CO - Restatement Adjustment $ in Millions	Apr. 15, 2019 USD ($)
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Capitalized asset retirement costs, net	$ 700
Remaining amounts of regulatory assets for which no return on investment during recovery period is provided	700
Plant Gorgas Units 8, 9, and 10
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net investment costs	654
Remaining amounts of regulatory assets for which no return on investment during recovery period is provided	$ 654

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Regulatory Matters - Georgia Power (Details) - GEORGIA POWER CO $ in Millions				6 Months Ended
	Jul. 29, 2019 MW	Jul. 16, 2019 MW	Jun. 28, 2019	Jun. 30, 2019 USD ($) MW	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Public Utilities, General Disclosures [Line Items]
Alternate Rate Plan period			3 years
Requested increases effective January 1, 2020				$ 563
Requested increases effective January 1, 2021				145
Requested increases effective January 1, 2022				234
Proposed retail ROE			10.90%
Proposed equity ratio			56.00%
Percentage of earnings above the top of allowed ROE range shared with customers			66.67%
Percentage of earnings above the top of allowed ROE range not shared with customers			33.33%
Cost recovery, new nuclear				99
Cost recovery, estimate, nuclear fuel				50
Under recovered CCR compliance cost				$ 135
Requested recovery of under recovered CCR compliance costs, period				3 years
Approved capacity of units for solar generation resources (mw) | MW				2,210
Approved capacity of units for investment portfolio (mw) | MW				80
Minimum
Public Utilities, General Disclosures [Line Items]
Allowed retail ROE			10.00%
Maximum
Public Utilities, General Disclosures [Line Items]
Allowed retail ROE			12.00%
Plant Hammond Units 1 Through 4
Public Utilities, General Disclosures [Line Items]
Net book value of planned units retirements				$ 500
Plant McIntosh Unit 1
Public Utilities, General Disclosures [Line Items]
Net book value of planned units retirements				40
Plant Mitchell Unit 3
Public Utilities, General Disclosures [Line Items]
Net book value of planned units retirements				$ 8
Subsequent Event
Public Utilities, General Disclosures [Line Items]
Rejected proposed capacity of units for certification | MW		25
Subsequent Event | Plant Hammond Units 1 Through 4
Public Utilities, General Disclosures [Line Items]
Capacity of units included in request for decertification of units (mw) | MW	840
Subsequent Event | Plant McIntosh Unit 1
Public Utilities, General Disclosures [Line Items]
Capacity of units included in request for decertification of units (mw) | MW	142.5
Remaining Net Book Value Of Retired Assets | Maximum
Public Utilities, General Disclosures [Line Items]
Regulatory asset, amortization period				3 years
Scenario, Forecast
Public Utilities, General Disclosures [Line Items]
Recovery of estimated under recovered CCR rule costs					$ 655	$ 395	$ 277

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Regulatory Matters - Requested Recovery of Proposed Increases (Details) - GEORGIA POWER CO $ in Millions	Jun. 30, 2019 USD ($)
Public Utilities, General Disclosures [Line Items]
2020	$ 563
2021	145
2022	234
Levelized
Public Utilities, General Disclosures [Line Items]
2020	209
2021	0
2022	0
CCR ARO
Public Utilities, General Disclosures [Line Items]
2020	158
2021	140
2022	227
Environmental Compliance Cost Recovery
Public Utilities, General Disclosures [Line Items]
2020	165
2021	0
2022	0
Demand-Side Management
Public Utilities, General Disclosures [Line Items]
2020	14
2021	2
2022	1
Municipal Franchise Fee
Public Utilities, General Disclosures [Line Items]
2020	17
2021	3
2022	$ 5

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Regulatory Matters - Nuclear Construction (Details) - GEORGIA POWER CO $ in Millions							1 Months Ended		6 Months Ended	12 Months Ended				36 Months Ended
	Jan. 01, 2021	Jan. 01, 2020	Aug. 30, 2019 USD ($)	Feb. 19, 2019 USD ($)	Jan. 11, 2018 USD ($)	Jan. 01, 2016	Dec. 31, 2018 USD ($) appeal	Aug. 31, 2018 USD ($)	Jun. 30, 2019 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2012 utility MW	Dec. 31, 2009 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2014	Dec. 31, 2013
Loss Contingencies [Line Items]
Number of construction units approved | utility												2
Electric generating capacity in mega watts under consortium agreement | MW												1,100
Additional construction capital costs					$ 3,300.0
Estimated in-service capital cost													$ 4,418.0
Financing costs collected, net of tax									$ 2,000.0
Increase in NCCR tariff							$ 88.0
Amendment to estimated in-service capital cost					$ 5,680.0
Retail rate of return on common equity																10.95%
Number of appeals | appeal							2
Requested capital construction costs				$ 5,400.0
Deferred approval of expenditures related to administrative claim				$ 51.6
Scenario, Forecast
Loss Contingencies [Line Items]
Requested capital construction costs			$ 1,200.0
FFB Loan
Loss Contingencies [Line Items]
Long-term line of credit									3,460.0
Eligible project costs to be reimbursed									$ 5,130.0
Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Proportionate ownership share									45.70%
Construction financing costs									$ 2,000.0
Base project capital cost forecast, monthly									50.0
Monthly AFUDC									12.0
Percentage of ownership interest required for voting for continuing construction								90.00%							90.00%
Cost settlement agreement revised forecast, net of payments									$ 7,300.0
Public utilities, approved return on equity percentage						10.00%
Public utilities, approved return on equity, monthly percentage decrease									0.10%
Return on equity reduction, negative impact on earnings											$ 100.0
Requested capital construction costs								$ 578.0
Guarantor obligations									$ 1,700.0
Customer refund									$ 188.0
Plant Vogtle Units 3 And 4 | Scenario, Forecast
Loss Contingencies [Line Items]
Construction financing costs										$ 3,100.0
Public utilities, approved return on equity percentage	5.30%	8.30%
Return on equity reduction, negative impact on earnings										$ 70.0				$ 630.0
Plant Vogtle Units 3 And 4 | Vogtle Owners
Loss Contingencies [Line Items]
Period of notice required in the event letters of credit are not renewed									30 days

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Regulatory Matters - Nuclear Construction Cost and Schedule (Details) - GEORGIA POWER CO - Plant Vogtle Units 3 And 4 $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($)
Loss Contingencies [Line Items]
Base project capital cost forecast	$ 8,000
Construction contingency estimate	400
Total project capital cost forecast	8,400
Net investment as of June 30, 2019	(5,200)
Remaining estimate to complete	3,200
Expected capitalized costs	315
Guarantor obligations	1,700
Customer refund	$ 188

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Regulatory Matters - Mississippi Power (Details) - USD ($) $ in Millions	Jan. 01, 2019	Jul. 09, 2019
MISSISSIPPI POWER CO | Subsequent Event
Loss Contingencies [Line Items]
Proportionate ownership share		50.00%
Total estimated cost		$ 66.0
MISSISSIPPI POWER CO | Subsequent Event | Ash Pond Closure
Loss Contingencies [Line Items]
Total estimated cost		17.0
MISSISSIPPI POWER CO | MRA Revenue
Loss Contingencies [Line Items]
Decrease in base rate under cost based electric tariff	$ 3.7
Mississippi Power And Gulf Power | Subsequent Event
Loss Contingencies [Line Items]
Total estimated cost		$ 125.0

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Regulatory Matters - Kemper County Energy Facility (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	6 Months Ended		48 Months Ended
	Dec. 31, 2018	Jun. 30, 2019	Dec. 31, 2019	Jun. 30, 2019	Dec. 31, 2023
Loss Contingencies [Line Items]
Liabilities incurred				$ 6
MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Liabilities incurred				0
MISSISSIPPI POWER CO | Kemper IGCC
Loss Contingencies [Line Items]
Pre-tax charge to income		$ 4		6
Asset retirement obligation, liabilities incurred, net of tax		3		5
Asset retirement obligation, expected cost		$ 10		$ 10
Government grants received	$ 387
MISSISSIPPI POWER CO | Kemper IGCC | Scenario, Forecast
Loss Contingencies [Line Items]
Liabilities incurred			$ 7
MISSISSIPPI POWER CO | Kemper IGCC | Minimum | Scenario, Forecast
Loss Contingencies [Line Items]
Liabilities incurred					$ 2
MISSISSIPPI POWER CO | Kemper IGCC | Maximum | Scenario, Forecast
Loss Contingencies [Line Items]
Liabilities incurred					$ 6

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Regulatory Matters - Southern Company Gas (Details) $ in Millions					1 Months Ended		12 Months Ended
	Jun. 03, 2019 USD ($)	Apr. 16, 2019 USD ($) intervenor	Apr. 08, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2018 USD ($)	Nov. 30, 2018 USD ($)	Dec. 31, 2017
Nicor Gas
Loss Contingencies [Line Items]
Approved increase (decrease) in fuel rates amount						$ 230
Public utilities, approved return on equity percentage		9.86%				10.60%
Regulatory equity ratio		54.00%				54.00%	52.00%
Number of intervenors | intervenor		2
Requested increase in rate amounts		$ 180
Atlanta Gas Light
Loss Contingencies [Line Items]
Public utilities, approved return on equity percentage	10.75%
Regulatory equity ratio	55.00%
Requested increase in rate amounts	$ 96
Virginia Natural Gas
Loss Contingencies [Line Items]
Approved increase (decrease) in fuel rates amount					$ (14)
Bill credits				$ 14
Virginia Natural Gas | SAVE
Loss Contingencies [Line Items]
Infrastructure replacement program, proposed investment amount			$ 370
Infrastructure replacement program, petitioned investment renewal term			5 years
Infrastructure replacement program, petitioned investment term			6 years
Infrastructure replacement program, proposed investment variance amount			$ 10
Virginia Natural Gas | SAVE | 2018
Loss Contingencies [Line Items]
Approved investment amount			35
Virginia Natural Gas | SAVE | 2019
Loss Contingencies [Line Items]
Infrastructure replacement program, proposed investment amount			40
Infrastructure replacement program, proposed investment variance amount			6
Virginia Natural Gas | SAVE | 2020
Loss Contingencies [Line Items]
Infrastructure replacement program, proposed investment amount			50
Infrastructure replacement program, proposed investment variance amount			8
Virginia Natural Gas | SAVE | 2021
Loss Contingencies [Line Items]
Infrastructure replacement program, proposed investment amount			60
Infrastructure replacement program, proposed investment variance amount			9
Virginia Natural Gas | SAVE | 2022
Loss Contingencies [Line Items]
Infrastructure replacement program, proposed investment amount			70
Infrastructure replacement program, proposed investment variance amount			10
Virginia Natural Gas | SAVE | 2023
Loss Contingencies [Line Items]
Infrastructure replacement program, proposed investment amount			70
Infrastructure replacement program, proposed investment variance amount			10
Virginia Natural Gas | SAVE | 2024
Loss Contingencies [Line Items]
Infrastructure replacement program, proposed investment amount			70
Infrastructure replacement program, proposed investment variance amount			$ 10
Minimum | Atlanta Gas Light
Loss Contingencies [Line Items]
Public utilities, approved return on equity percentage	10.55%
Maximum | Atlanta Gas Light
Loss Contingencies [Line Items]
Public utilities, approved return on equity percentage	10.95%

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Regulatory Matters - FERC Matters (Details) - Open Access Transmission Tariff - SCS	May 10, 2018
Loss Contingencies [Line Items]
Public utilities, approved return on equity percentage	10.60%
Moratorium period	5 years

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Contingencies - General Litigation Matters (Details) $ in Millions		1 Months Ended			3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 14, 2019 plaintiff	Nov. 30, 2018 USD ($) defendant plaintiff	May 31, 2018 USD ($) agreement	Apr. 30, 2018	Jun. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)	Dec. 31, 2017 claim
Loss Contingencies [Line Items]
Number of plaintiffs | plaintiff		10
Pending Litigation | Putative Securities Class Action
Loss Contingencies [Line Items]
Increase in the purported class period							1 day
Pending Litigation | Shareholder Derivative Lawsuits
Loss Contingencies [Line Items]
Pending number of claims | claim							2
Stay period			30 days	30 days
MISSISSIPPI POWER CO | Pending Litigation | Martin Product Sales, LLC Litigation
Loss Contingencies [Line Items]
Number of agreements | agreement			2
MISSISSIPPI POWER CO | Pending Litigation | Purported Violations Of Mississippi Consumer Protection Act
Loss Contingencies [Line Items]
Number of plaintiffs | plaintiff	4
Number of defendants | defendant		3
Underpayment of refunds		$ 23.5
Martin Product Sales, LLC Litigation | Martin Product Sales, LLC Litigation
Loss Contingencies [Line Items]
Damages sought by litigation			$ 143.0
SOUTHERN POWER CO
Loss Contingencies [Line Items]
Withholding of construction contract payments						$ 26.0
Gain on funds received in excess of initial replacement costs, after tax					$ 12.0
SOUTHERN POWER CO | RE Roserock, LLC | RE Roserock, LLC
Loss Contingencies [Line Items]
Ownership percentage by parent					51.00%	51.00%

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Contingencies - Environmental Remediation (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
GEORGIA POWER CO
Loss Contingencies [Line Items]
Environmental remediation liability, current and former sites	$ 18	$ 23
SOUTHERN Co GAS
Loss Contingencies [Line Items]
Environmental remediation liability, current and former sites	283	$ 294
SOUTHERN Co GAS | Location One
Loss Contingencies [Line Items]
Environmental remediation liability, current and former sites	$ 2

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Contingencies - Other Matters (Details)	60 Months Ended
	Jan. 15, 2024 USD ($)	Jun. 30, 2019 USD ($) Facility	May 17, 2019 USD ($)
ALABAMA POWER CO | Damage from Unpermitted Discharge of Fluids and/or Pollutants | Plant Gadsden
Loss Contingencies [Line Items]
Possible environmental penalty | $			$ 250,000
GULF POWER CO | Scenario, Forecast | Plant Daniel Units 1 And 2
Loss Contingencies [Line Items]
Undivided ownership interest to be sold	50.00%
Undivided ownership interest, ownership interest in individual unit	100.00%
MISSISSIPPI POWER CO | Scenario, Forecast | Plant Daniel Units 1 And 2
Loss Contingencies [Line Items]
Payments to acquire business | $	$ 1
Option to purchase, period	120 days
SOUTHERN Co GAS | Natural Gas Storage Facility
Loss Contingencies [Line Items]
Combined net book value | $		$ 438,000,000
SOUTHERN Co GAS | Natural Gas Storage Facility | Louisiana
Loss Contingencies [Line Items]
Number of facilities | Facility		2
Number of facilities to be restored | Facility		1
SOUTHERN Co GAS | Natural Gas Storage Facility | California
Loss Contingencies [Line Items]
Number of facilities | Facility		2

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Revenue from Contracts with Customers - Disaggregate Revenue Sources (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Disaggregation of Revenue [Line Items]
Total operating revenues	$ 5,098	$ 5,627	$ 10,510	$ 11,999
Revenue from leases	184		326
Total retail electric and gas distribution revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	4,103	4,378	8,347	9,146
Total retail electric revenues
Disaggregation of Revenue [Line Items]
Revenue from leases	8	18	16	36
Increase (decrease) in revenue from cost recovery mechanisms	(14)	68	(117)	101
Residential
Disaggregation of Revenue [Line Items]
Total operating revenues	1,488	1,579	2,776	3,118
Commercial
Disaggregation of Revenue [Line Items]
Total operating revenues	1,258	1,315	2,350	2,557
Industrial
Disaggregation of Revenue [Line Items]
Total operating revenues	763	814	1,440	1,569
Other
Disaggregation of Revenue [Line Items]
Total operating revenues	31	32	57	64
Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	562	642	1,724	1,865
Revenues not accounted for under ASC 606	5	5	8	8
Alternative revenue programs
Disaggregation of Revenue [Line Items]
Total operating revenues	1	(4)	0	(27)
Wholesale energy revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	410	464	777	937
Revenue from leases	115	118	182	187
Revenue from transactions accounted for as derivatives	30	61	82	155
Wholesale capacity revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	132	152	264	302
Revenue from leases	22	31	47	61
Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	126	68	439	476
Revenue from leases	8		16
Revenues not accounted for under ASC 606	10		27
Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	327	565	683	1,138
Revenue from leases	28	33	59	66
Revenues not accounted for under ASC 606	89	89	180	183
ALABAMA POWER CO
Disaggregation of Revenue [Line Items]
Total operating revenues	1,513	1,503	2,921	2,976
ALABAMA POWER CO | Total retail electric revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	1,378	1,338	2,592	2,624
Increase (decrease) in revenue from cost recovery mechanisms	(11)	78	(68)	125
ALABAMA POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total operating revenues	588	557	1,128	1,127
ALABAMA POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total operating revenues	418	402	772	774
ALABAMA POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total operating revenues	366	372	679	710
ALABAMA POWER CO | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	6	7	13	13
ALABAMA POWER CO | Wholesale energy revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	41	71	135	172
Revenue from transactions accounted for as derivatives	3	4	6	9
ALABAMA POWER CO | Wholesale capacity revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	25	25	51	49
ALABAMA POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	69	69	143	131
Revenues not accounted for under ASC 606	31	26	59	52
GEORGIA POWER CO
Disaggregation of Revenue [Line Items]
Total operating revenues	2,117	2,048	3,951	4,008
Revenue from leases	19		39
GEORGIA POWER CO | Total retail electric revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	1,946	1,889	3,614	3,688
Revenue from leases	8	18	16	36
Increase (decrease) in revenue from cost recovery mechanisms	(5)	3	(52)	12
GEORGIA POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total operating revenues	831	785	1,519	1,529
GEORGIA POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total operating revenues	767	749	1,440	1,466
GEORGIA POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total operating revenues	327	335	616	650
GEORGIA POWER CO | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	21	20	39	43
GEORGIA POWER CO | Wholesale energy revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	14	26	27	66
Revenue from transactions accounted for as derivatives	4	5	8	13
GEORGIA POWER CO | Wholesale capacity revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	22	13	40	27
GEORGIA POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	135	120	270	227
Revenue from leases	11	33	23	66
Revenues not accounted for under ASC 606	30	26	61	53
MISSISSIPPI POWER CO
Disaggregation of Revenue [Line Items]
Total operating revenues	313	297	600	598
Revenue from leases	2		5
MISSISSIPPI POWER CO | Total retail electric revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	215	212	418	406
Increase (decrease) in revenue from cost recovery mechanisms	2	(1)	3	(8)
MISSISSIPPI POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total operating revenues	69	65	129	125
MISSISSIPPI POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total operating revenues	73	68	138	130
MISSISSIPPI POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total operating revenues	70	76	145	146
MISSISSIPPI POWER CO | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	3	3	6	5
MISSISSIPPI POWER CO | Wholesale energy revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	93	77	170	176
Revenue from transactions accounted for as derivatives	1	1	1	2
MISSISSIPPI POWER CO | Wholesale capacity revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	1	1	2	5
MISSISSIPPI POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	4	7	10	11
SOUTHERN POWER CO
Disaggregation of Revenue [Line Items]
Total operating revenues	510	555	953	1,064
Revenue from leases	164		278
SOUTHERN POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	3	3	6	5
SOUTHERN POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	125	144	252	282
Revenue from leases	39	47	80	94
SOUTHERN POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	291	302	518	556
Revenue from leases	125	127	198	203
SOUTHERN POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	91	106	177	221
Revenue from transactions accounted for as derivatives	22	50	67	129
SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Total operating revenues	689	730	2,163	2,369
Revenue from leases	9		17
SOUTHERN Co GAS | Wholesale Gas Services | Third Party Gross Revenues
Disaggregation of Revenue [Line Items]
Revenue from transactions accounted for as derivatives	800	700	2,000	1,800
SOUTHERN Co GAS | Operating Segments
Disaggregation of Revenue [Line Items]
Total operating revenues	682	724	2,177	2,381
SOUTHERN Co GAS | Operating Segments | Wholesale Gas Services
Disaggregation of Revenue [Line Items]
Total operating revenues	48	(16)	134	150
SOUTHERN Co GAS | Operating Segments | Wholesale Gas Services | Third Party Gross Revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	1,223	1,336	3,148	3,274
SOUTHERN Co GAS | Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	563	638	1,724	1,838
Revenues not accounted for under ASC 606	5	5	8	8
SOUTHERN Co GAS | Residential
Disaggregation of Revenue [Line Items]
Total operating revenues	229	273	830	933
SOUTHERN Co GAS | Commercial
Disaggregation of Revenue [Line Items]
Total operating revenues	65	76	235	268
SOUTHERN Co GAS | Transportation
Disaggregation of Revenue [Line Items]
Total operating revenues	213	228	469	505
SOUTHERN Co GAS | Industrial
Disaggregation of Revenue [Line Items]
Total operating revenues	5	7	22	24
SOUTHERN Co GAS | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	50	58	168	135
SOUTHERN Co GAS | Alternative revenue programs
Disaggregation of Revenue [Line Items]
Total operating revenues	1	(4)	0	(27)
SOUTHERN Co GAS | Other natural gas revenues | Wholesale Gas Services | Third Party Gross Revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	1,200	1,300	3,100	3,300
SOUTHERN Co GAS | Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	12	10	22	25
SOUTHERN Co GAS | Wholesale Gas Services
Disaggregation of Revenue [Line Items]
Total operating revenues	48	(15)	114	131
SOUTHERN Co GAS | Gas pipeline investments
Disaggregation of Revenue [Line Items]
Total operating revenues	8	8	16	16
Revenue from leases	8		16
SOUTHERN Co GAS | Gas marketing services
Disaggregation of Revenue [Line Items]
Total operating revenues	58	$ 89	287	359
Revenues not accounted for under ASC 606	$ 2		$ 11	$ 4

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Revenue from Contracts with Customers - Contract Balances (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Receivables	$ 2,343	$ 2,630
Contract Assets	70	102
Contract Liabilities	58	32
ALABAMA POWER CO
Disaggregation of Revenue [Line Items]
Receivables	629	520
Contract Assets	0	0
Contract Liabilities	10	12
GEORGIA POWER CO
Disaggregation of Revenue [Line Items]
Receivables	807	721
Contract Assets	30	58
Contract Liabilities	26	7
MISSISSIPPI POWER CO
Disaggregation of Revenue [Line Items]
Receivables	93	100
Contract Assets	0	0
Contract Liabilities	7	0
SOUTHERN POWER CO
Disaggregation of Revenue [Line Items]
Receivables	119	118
Contract Assets	0	0
Contract Liabilities	1	11
SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Receivables	550	952
Contract Assets	0	0
Contract Liabilities	$ 1	$ 2

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Revenue from Contracts with Customers - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Contract assets	$ 70	$ 70	$ 102
Contract liabilities	58	58	32
Revenue from contracts with customers recognized	11	27
Unregulated Distributed Generation
Disaggregation of Revenue [Line Items]
Contract assets	32	32	39
Contract liabilities	14	14	11
ALABAMA POWER CO
Disaggregation of Revenue [Line Items]
Contract assets	0	0	0
Contract liabilities	10	10	12
Revenue from contracts with customers recognized	0	0
GEORGIA POWER CO
Disaggregation of Revenue [Line Items]
Contract assets	30	30	58
Contract liabilities	26	26	7
Revenue from contracts with customers recognized	0	0
SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Contract assets	0	0	0
Contract liabilities	1	1	2
Revenue from contracts with customers recognized	0	0
MISSISSIPPI POWER CO
Disaggregation of Revenue [Line Items]
Contract assets	0	0	0
Contract liabilities	7	7	$ 0
Revenue, remaining performance obligation	$ 0	$ 0

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Revenue from Contracts with Customers - Revenue from Contracts with Customers (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers recognized	$ 11	$ 27
SOUTHERN POWER CO
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers recognized	$ 1	$ 11

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Revenue from Contracts with Customers - Performance Obligations (Details) $ in Millions	Jun. 30, 2019 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 282
Performance obligation, expected timing of satisfaction	6 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 490
Performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 320
Performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 311
Performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 302
Performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 2,230
Performance obligation, expected timing of satisfaction
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 11
Performance obligation, expected timing of satisfaction	6 months
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 23
Performance obligation, expected timing of satisfaction	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 27
Performance obligation, expected timing of satisfaction	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 23
Performance obligation, expected timing of satisfaction	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 22
Performance obligation, expected timing of satisfaction	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 140
Performance obligation, expected timing of satisfaction
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 27
Performance obligation, expected timing of satisfaction	6 months
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 51
Performance obligation, expected timing of satisfaction	1 year
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 44
Performance obligation, expected timing of satisfaction	1 year
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 31
Performance obligation, expected timing of satisfaction	1 year
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 31
Performance obligation, expected timing of satisfaction	1 year
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 83
Performance obligation, expected timing of satisfaction
MISSISSIPPI POWER CO
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 0
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-07-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 169
Performance obligation, expected timing of satisfaction	6 months
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 295
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 270
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 276
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 269
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 2,154
Performance obligation, expected timing of satisfaction

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Consolidated Entities and Equity Method Investments - Narrative (Details) $ in Millions		6 Months Ended
	May 29, 2019 USD ($)	Jun. 30, 2019 USD ($) investor
SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Distribution made to limited partner, cash distributions paid, percentage		67.00%
Global Atlantic
Schedule of Equity Method Investments [Line Items]
Distribution made to limited partner, cash distributions paid, percentage		33.00%
Variable Interest Entity, Not Primary Beneficiary | SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Carrying amount of investments		$ 144
SP Solar Holdings I, LP | Variable Interest Entity, Primary Beneficiary | SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Assets		6,500
Liabilities		374
Noncontrolling interests related to other partners' interests		$ 1,100
SP Wind | SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Distribution made to limited partner, cash distributions paid, percentage		60.00%
Number of financial investors | investor		3
SP Wind | Financial Investors
Schedule of Equity Method Investments [Line Items]
Distribution made to limited partner, cash distributions paid, percentage		40.00%
SP Wind | Variable Interest Entity, Primary Beneficiary | SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Assets		$ 2,500
Liabilities		136
Noncontrolling interests related to other partners' interests		46
DSGP | Variable Interest Entity, Not Primary Beneficiary | SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Carrying amount of investments		$ 116
Triton | SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Pre tax loss on disposition of investment	$ 6
Income tax benefit on disposition of investment	13
After-tax gain on disposition of investment	$ 7

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Consolidated Entities and Equity Method Investments - Balance Sheet Equity Method Investment Carrying Amount (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Investment Balance	$ 1,557	$ 1,580
SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Investment Balance	1,509	1,538
SOUTHERN Co GAS | SNG
Schedule of Equity Method Investments [Line Items]
Investment Balance	1,243	1,261
SOUTHERN Co GAS | Atlantic Coast Pipeline
Schedule of Equity Method Investments [Line Items]
Investment Balance	101	83
SOUTHERN Co GAS | PennEast Pipeline
Schedule of Equity Method Investments [Line Items]
Investment Balance	77	71
SOUTHERN Co GAS | Other
Schedule of Equity Method Investments [Line Items]
Investment Balance	$ 88	$ 123

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Consolidated Entities and Equity Method Investments - Income Statement Equity Method Investment Carrying Amount (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	$ 33	$ 31	$ 81	$ 72
SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	31	31	80	74
SOUTHERN Co GAS | SNG
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	32	27	74	66
SOUTHERN Co GAS | Atlantic Coast Pipeline
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	3	1	6	3
SOUTHERN Co GAS | PennEast Pipeline
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	1	1	3	2
SOUTHERN Co GAS | Other
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	$ (5)	$ 2	$ (3)	$ 3

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Consolidated Entities and Equity Method Investments - Investment in SNG (Details) - SNG - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Income Statement Information
Revenues	$ 155	$ 146	$ 321	$ 306
Operating income	86	60	192	159
Net income	$ 64	$ 54	$ 148	$ 132

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Financing - Narrative (Details)	1 Months Ended				3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2019 USD ($) loan	May 31, 2019 USD ($)	Mar. 31, 2019 USD ($)	Jan. 31, 2019 USD ($)	Jun. 30, 2019 USD ($) shares	Jun. 30, 2018 shares	Jun. 30, 2019 USD ($) loan shares	Jun. 30, 2018 USD ($) shares	Dec. 31, 2014	Apr. 30, 2019 USD ($)	Aug. 31, 2018
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding	$ 1,400,000,000				$ 1,400,000,000		$ 1,400,000,000
Fixed rate pollution control revenue bonds outstanding	272,000,000				272,000,000		272,000,000
Borrowing capacity	7,583,000,000				$ 7,583,000,000		7,583,000,000
Repayments of short-term debt							$ 1,850,000,000	$ 550,000,000
Stock-based compensation awards not included in the diluted earnings per share calculation because they were anti-dilutive (in shares) | shares					0	5,300,000	0	0
Senior Notes
Debt Instrument [Line Items]
Repayments of debt				$ 1,200,000,000
Senior Notes | 1.85% Notes
Debt Instrument [Line Items]
Interest rate				1.85%
Repurchase amount				$ 522,000,000
Debt face amount				$ 1,000,000,000.0
Senior Notes | Series 2014B Notes
Debt Instrument [Line Items]
Interest rate				2.15%
Repurchase amount				$ 180,000,000
Debt face amount				350,000,000
Senior Notes | Series 2018A Notes
Debt Instrument [Line Items]
Repurchase amount				504,000,000
Debt face amount				750,000,000
Notes Payable to Banks | Uncommitted Bank Credit Arrangement
Debt Instrument [Line Items]
Repayments of short-term debt				250,000,000
Notes Payable to Banks | Floating Rate Bank Term Loan Agreement
Debt Instrument [Line Items]
Repayments of short-term debt				1,500,000,000
ALABAMA POWER CO
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding	854,000,000				$ 854,000,000		$ 854,000,000
Fixed rate pollution control revenue bonds outstanding	87,000,000				87,000,000		87,000,000
Borrowing capacity	1,303,000,000				1,303,000,000		1,303,000,000
GEORGIA POWER CO
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding	550,000,000				550,000,000		550,000,000
Fixed rate pollution control revenue bonds outstanding	185,000,000				185,000,000		185,000,000
Borrowing capacity	1,750,000,000				1,750,000,000		1,750,000,000
Repayments of short-term debt							0	$ 150,000,000
GEORGIA POWER CO | Municipal bonds | Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project) First Series 1992
Debt Instrument [Line Items]
Redeemed aggregate principal amount				13,000,000
GEORGIA POWER CO | Municipal bonds | Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Eighth Series 1994
Debt Instrument [Line Items]
Redeemed aggregate principal amount				20,000,000
GEORGIA POWER CO | Municipal bonds | Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 1995
Debt Instrument [Line Items]
Redeemed aggregate principal amount				$ 75,000,000
GEORGIA POWER CO | Municipal bonds | Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009
Debt Instrument [Line Items]
Debt face amount			$ 173,000,000
GEORGIA POWER CO | Municipal bonds | Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013
Debt Instrument [Line Items]
Debt face amount			105,000,000
GEORGIA POWER CO | Municipal bonds | Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008
Debt Instrument [Line Items]
Debt face amount			65,000,000
GEORGIA POWER CO | Municipal bonds | Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1994
Debt Instrument [Line Items]
Debt face amount										$ 55,000,000
GEORGIA POWER CO | Municipal bonds | Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1995
Debt Instrument [Line Items]
Debt face amount										30,000,000
GEORGIA POWER CO | Municipal bonds | Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Ninth Series 1994
Debt Instrument [Line Items]
Debt face amount										20,000,000
GEORGIA POWER CO | Municipal bonds | Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 1994
Debt Instrument [Line Items]
Debt face amount										10,000,000
GEORGIA POWER CO | Municipal bonds | Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1994
Debt Instrument [Line Items]
Debt face amount	$ 55,000,000				55,000,000		55,000,000
GEORGIA POWER CO | Plant Vogtle Units 3 And 4
Debt Instrument [Line Items]
Undivided ownership interest									45.70%
GEORGIA POWER CO | Notes Payable to Banks
Debt Instrument [Line Items]
Number of short-term loans | loan	2
GEORGIA POWER CO | Notes Payable to Banks | First Short-Term Floating Rate Bank Loan
Debt Instrument [Line Items]
Debt face amount	$ 125,000,000				125,000,000		125,000,000
GEORGIA POWER CO | Notes Payable to Banks | Second Short-Term Floating Rate Bank Loan
Debt Instrument [Line Items]
Debt face amount	125,000,000				125,000,000		$ 125,000,000
GEORGIA POWER CO | Term Loan
Debt Instrument [Line Items]
Number of term loan facilities | loan							2
GEORGIA POWER CO | 2014 FFB Credit Facility
Debt Instrument [Line Items]
Eligible project costs to be reimbursed							$ 5,130,000,000
Eligible project costs to be reimbursed, percentage									70.00%
Borrowings made			$ 835,000,000
Interest rate			3.213%
Borrowings outstanding	3,460,000,000				3,460,000,000		3,460,000,000
Amortization period for line of credit facility									5 years
GEORGIA POWER CO | 2014 FFB Credit Facility | U.S. Treasury Rate
Debt Instrument [Line Items]
Basis spread									0.375%
GEORGIA POWER CO | Additional FFB Credit Facility
Debt Instrument [Line Items]
Eligible project costs to be reimbursed, percentage			70.00%
Amounts received under Guarantee Settlement Agreement, less Customer Refunds			$ 1,492,000,000
MISSISSIPPI POWER CO
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding	40,000,000				40,000,000		40,000,000
Borrowing capacity	150,000,000				150,000,000		150,000,000
Repayments of short-term debt							0	200,000,000
MISSISSIPPI POWER CO | Municipal bonds | Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002
Debt Instrument [Line Items]
Debt face amount			$ 43,000,000
MISSISSIPPI POWER CO | Credit Arrangement
Debt Instrument [Line Items]
Borrowing capacity	50,000,000				50,000,000		50,000,000
SOUTHERN Co GAS
Debt Instrument [Line Items]
Borrowing capacity	1,750,000,000				1,750,000,000		1,750,000,000
SOUTHERN POWER CO
Debt Instrument [Line Items]
Borrowing capacity	600,000,000	$ 600,000,000			600,000,000		600,000,000			750,000,000
Repayments of short-term debt							100,000,000	$ 0
SOUTHERN POWER CO | Notes Payable to Banks
Debt Instrument [Line Items]
Repayments of short-term debt		100,000,000
Southern Company Gas Capital
Debt Instrument [Line Items]
Borrowing capacity	1,250,000,000	$ 1,750,000,000			1,250,000,000		1,250,000,000			$ 1,900,000,000
Nicor Gas
Debt Instrument [Line Items]
Borrowing capacity	$ 500,000,000				$ 500,000,000		$ 500,000,000
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO
Debt Instrument [Line Items]
Undivided ownership interest	45.70%				45.70%		45.70%
Failure to vote, percentage of ownership interests									90.00%		90.00%

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Financing - Schedule of Credit Arrangements (Details) - USD ($)	Jun. 30, 2019	May 31, 2019	Apr. 30, 2019
Line of Credit Facility [Line Items]
Expires, 2019	$ 3,000,000
Expires, 2020	530,000,000
Expires, 2022	150,000,000
Expires, 2024	6,900,000,000
Total	7,583,000,000
Unused	7,524,000,000
Due within One Year No Term Out	33,000,000
Southern Company
Line of Credit Facility [Line Items]
Expires, 2019	0
Expires, 2020	0
Expires, 2022	0
Expires, 2024	2,000,000,000
Total	2,000,000,000
Unused	1,999,000,000
Due within One Year No Term Out	0
ALABAMA POWER CO
Line of Credit Facility [Line Items]
Expires, 2019	3,000,000
Expires, 2020	500,000,000
Expires, 2022	0
Expires, 2024	800,000,000
Total	1,303,000,000
Unused	1,303,000,000
Due within One Year No Term Out	3,000,000
GEORGIA POWER CO
Line of Credit Facility [Line Items]
Expires, 2019	0
Expires, 2020	0
Expires, 2022	0
Expires, 2024	1,750,000,000
Total	1,750,000,000
Unused	1,736,000,000
Due within One Year No Term Out	0
MISSISSIPPI POWER CO
Line of Credit Facility [Line Items]
Expires, 2019	0
Expires, 2020	0
Expires, 2022	150,000,000
Expires, 2024	0
Total	150,000,000
Unused	150,000,000
Due within One Year No Term Out	0
SOUTHERN POWER CO
Line of Credit Facility [Line Items]
Expires, 2019	0
Expires, 2020	0
Expires, 2022	0
Expires, 2024	600,000,000
Total	600,000,000	$ 600,000,000	$ 750,000,000
Unused	561,000,000
Due within One Year No Term Out	0
SOUTHERN POWER CO | Standby Letters of Credit
Line of Credit Facility [Line Items]
Total	120,000,000
Unused	30,000,000
SOUTHERN Co GAS
Line of Credit Facility [Line Items]
Expires, 2019	0
Expires, 2020	0
Expires, 2022	0
Expires, 2024	1,750,000,000
Total	1,750,000,000
Unused	1,745,000,000
Due within One Year No Term Out	0
Other
Line of Credit Facility [Line Items]
Expires, 2019	0
Expires, 2020	30,000,000
Expires, 2022	0
Expires, 2024	0
Total	30,000,000
Unused	30,000,000
Due within One Year No Term Out	30,000,000
Southern Company Gas Capital
Line of Credit Facility [Line Items]
Total	1,250,000,000	$ 1,750,000,000	$ 1,900,000,000
Nicor Gas
Line of Credit Facility [Line Items]
Total	$ 500,000,000

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Financing - Schedule of Long-Term Debt Financing Activities (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($)
Debt Instrument [Line Items]
Senior Note Maturities, Redemptions, and Repurchases	$ 2,300
Revenue Bond Issuances and Reofferings of Purchased Bonds	556
Revenue Bond Maturities, Redemptions, and Repurchases	248
Other Long-Term Debt Issuances	835
Other Long-Term Debt Redemptions and Maturities	12
Southern Company
Debt Instrument [Line Items]
Senior Note Maturities, Redemptions, and Repurchases	2,100
Revenue Bond Issuances and Reofferings of Purchased Bonds	0
Revenue Bond Maturities, Redemptions, and Repurchases	0
Other Long-Term Debt Issuances	0
Other Long-Term Debt Redemptions and Maturities	0
ALABAMA POWER CO
Debt Instrument [Line Items]
Senior Note Maturities, Redemptions, and Repurchases	200
Revenue Bond Issuances and Reofferings of Purchased Bonds	0
Revenue Bond Maturities, Redemptions, and Repurchases	0
Other Long-Term Debt Issuances	0
Other Long-Term Debt Redemptions and Maturities	0
GEORGIA POWER CO
Debt Instrument [Line Items]
Senior Note Maturities, Redemptions, and Repurchases	0
Revenue Bond Issuances and Reofferings of Purchased Bonds	513
Revenue Bond Maturities, Redemptions, and Repurchases	223
Other Long-Term Debt Issuances	835
Other Long-Term Debt Redemptions and Maturities	3
MISSISSIPPI POWER CO
Debt Instrument [Line Items]
Senior Note Maturities, Redemptions, and Repurchases	0
Revenue Bond Issuances and Reofferings of Purchased Bonds	43
Revenue Bond Maturities, Redemptions, and Repurchases	0
Other Long-Term Debt Issuances	0
Other Long-Term Debt Redemptions and Maturities	0
Other
Debt Instrument [Line Items]
Senior Note Maturities, Redemptions, and Repurchases	0
Revenue Bond Issuances and Reofferings of Purchased Bonds	0
Revenue Bond Maturities, Redemptions, and Repurchases	25
Other Long-Term Debt Issuances	0
Other Long-Term Debt Redemptions and Maturities	$ 9

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Financing - Shares Used to Compute Diluted Earnings Per Share (Details) - shares shares in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Debt Disclosure [Abstract]
As reported shares	1,044	1,014	1,041	1,012
Effect of stock-based compensation	8	0	8	5
Diluted shares	1,052	1,014	1,049	1,017

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Income Taxes (Details) - USD ($) $ in Billions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Income Tax Contingency [Line Items]
Effective tax (benefit) rate	33.50%	(3.20%)
GEORGIA POWER CO
Income Tax Contingency [Line Items]
Effective tax (benefit) rate	21.70%	(53.50%)
MISSISSIPPI POWER CO
Income Tax Contingency [Line Items]
Effective tax (benefit) rate	14.00%	18.70%
SOUTHERN POWER CO
Income Tax Contingency [Line Items]
Effective tax (benefit) rate	(35.50%)	(1386.50%)
SOUTHERN Co GAS
Income Tax Contingency [Line Items]
Effective tax (benefit) rate	18.00%	39.10%
Investment Tax Credit Carryforward
Income Tax Contingency [Line Items]
Federal ITC/PTC carryforward	$ 2.0		$ 2.4

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Retirement Benefits (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Amortization:
Net (gain)/loss
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, expected future employer contributions, remainder of fiscal year	$ 0		$ 0
Pension Plans and Postretirement Plans
Service cost	73,000,000	89,000,000	146,000,000	$ 179,000,000
Interest cost	123,000,000	116,000,000	246,000,000	232,000,000
Expected return on plan assets	(221,000,000)	(235,000,000)	(442,000,000)	(471,000,000)
Amortization:
Prior service costs	1,000,000	1,000,000	1,000,000	2,000,000
Regulatory asset	0	0	0	0
Net (gain)/loss	30,000,000	54,000,000	60,000,000	107,000,000
Net periodic pension cost (income)	6,000,000	25,000,000	11,000,000	49,000,000
Pension Plans | ALABAMA POWER CO
Pension Plans and Postretirement Plans
Service cost	17,000,000	20,000,000	34,000,000	39,000,000
Interest cost	29,000,000	25,000,000	57,000,000	50,000,000
Expected return on plan assets	(52,000,000)	(53,000,000)	(103,000,000)	(104,000,000)
Amortization:
Prior service costs	1,000,000	1,000,000	1,000,000	1,000,000
Regulatory asset	0	0	0	0
Net (gain)/loss	9,000,000	13,000,000	18,000,000	27,000,000
Net periodic pension cost (income)	4,000,000	6,000,000	7,000,000	13,000,000
Pension Plans | GEORGIA POWER CO
Pension Plans and Postretirement Plans
Service cost	18,000,000	21,000,000	37,000,000	43,000,000
Interest cost	39,000,000	35,000,000	78,000,000	70,000,000
Expected return on plan assets	(73,000,000)	(74,000,000)	(146,000,000)	(148,000,000)
Amortization:
Prior service costs	1,000,000	1,000,000	1,000,000	1,000,000
Regulatory asset	0	0	0	0
Net (gain)/loss	11,000,000	17,000,000	22,000,000	34,000,000
Net periodic pension cost (income)	(4,000,000)	0	(8,000,000)	0
Pension Plans | MISSISSIPPI POWER CO
Pension Plans and Postretirement Plans
Service cost	3,000,000	4,000,000	6,000,000	8,000,000
Interest cost	5,000,000	5,000,000	11,000,000	10,000,000
Expected return on plan assets	(10,000,000)	(10,000,000)	(20,000,000)	(20,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	2,000,000	2,000,000	3,000,000	5,000,000
Net periodic pension cost (income)	0	1,000,000	0	3,000,000
Pension Plans | SOUTHERN POWER CO
Pension Plans and Postretirement Plans
Service cost	1,000,000	2,000,000	3,000,000	4,000,000
Interest cost	2,000,000	2,000,000	3,000,000	3,000,000
Expected return on plan assets	(3,000,000)	(2,000,000)	(5,000,000)	(5,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	0	0	0	1,000,000
Net periodic pension cost (income)	0	2,000,000	1,000,000	3,000,000
Pension Plans | SOUTHERN Co GAS
Pension Plans and Postretirement Plans
Service cost	6,000,000	8,000,000	12,000,000	16,000,000
Interest cost	9,000,000	9,000,000	18,000,000	19,000,000
Expected return on plan assets	(15,000,000)	(17,000,000)	(30,000,000)	(35,000,000)
Amortization:
Prior service costs	0	0	(1,000,000)	(1,000,000)
Regulatory asset	4,000,000	4,000,000	7,000,000	7,000,000
Net (gain)/loss	0	3,000,000	1,000,000	6,000,000
Net periodic pension cost (income)	4,000,000	7,000,000	7,000,000	12,000,000
Postretirement Benefits
Pension Plans and Postretirement Plans
Service cost	4,000,000	6,000,000	9,000,000	12,000,000
Interest cost	17,000,000	18,000,000	34,000,000	37,000,000
Expected return on plan assets	(17,000,000)	(17,000,000)	(33,000,000)	(34,000,000)
Amortization:
Prior service costs	1,000,000	1,000,000	2,000,000	3,000,000
Regulatory asset	0	0	0	0
Net (gain)/loss	0	4,000,000	(1,000,000)	7,000,000
Net periodic pension cost (income)	5,000,000	12,000,000	11,000,000	25,000,000
Postretirement Benefits | ALABAMA POWER CO
Pension Plans and Postretirement Plans
Service cost	1,000,000	2,000,000	2,000,000	3,000,000
Interest cost	4,000,000	4,000,000	8,000,000	8,000,000
Expected return on plan assets	(7,000,000)	(7,000,000)	(13,000,000)	(13,000,000)
Amortization:
Prior service costs	1,000,000	1,000,000	2,000,000	2,000,000
Regulatory asset	0	0	0	0
Net (gain)/loss	0	1,000,000	0	1,000,000
Net periodic pension cost (income)	(1,000,000)	1,000,000	(1,000,000)	1,000,000
Postretirement Benefits | GEORGIA POWER CO
Pension Plans and Postretirement Plans
Service cost	1,000,000	1,000,000	2,000,000	3,000,000
Interest cost	6,000,000	7,000,000	13,000,000	14,000,000
Expected return on plan assets	(6,000,000)	(7,000,000)	(12,000,000)	(13,000,000)
Amortization:
Prior service costs	0	1,000,000	0	1,000,000
Regulatory asset	0	0	0	0
Net (gain)/loss	0	2,000,000	0	4,000,000
Net periodic pension cost (income)	1,000,000	4,000,000	3,000,000	9,000,000
Postretirement Benefits | MISSISSIPPI POWER CO
Pension Plans and Postretirement Plans
Service cost	0	1,000,000	0	1,000,000
Interest cost	1,000,000	1,000,000	2,000,000	2,000,000
Expected return on plan assets	(1,000,000)	(1,000,000)	(1,000,000)	(1,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	0	0	0	0
Net periodic pension cost (income)	0	1,000,000	1,000,000	2,000,000
Postretirement Benefits | SOUTHERN POWER CO
Pension Plans and Postretirement Plans
Service cost	0	0	0	0
Interest cost	0	0	0	0
Expected return on plan assets	0	0	0	0
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0	0	0	0
Net (gain)/loss	0	0	0	0
Net periodic pension cost (income)	0	0	0	0
Postretirement Benefits | SOUTHERN Co GAS
Pension Plans and Postretirement Plans
Service cost	0	0	1,000,000	1,000,000
Interest cost	3,000,000	3,000,000	5,000,000	5,000,000
Expected return on plan assets	(1,000,000)	(2,000,000)	(3,000,000)	(4,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	1,000,000	2,000,000	3,000,000	3,000,000
Net (gain)/loss	(1,000,000)	0	(2,000,000)	0
Net periodic pension cost (income)	$ 2,000,000	$ 3,000,000	$ 4,000,000	$ 5,000,000

XML

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Assets:
Derivatives	$ 191	$ 313
Liabilities:
Derivatives	185	235
Collateral already posted, aggregate fair value	178
ALABAMA POWER CO
Assets:
Derivatives	3	2
Liabilities:
Derivatives	15	6
GEORGIA POWER CO
Assets:
Derivatives	0	0
Investments in trusts	30
Liabilities:
Derivatives	74	17
MISSISSIPPI POWER CO
Assets:
Derivatives	0	1
Liabilities:
Derivatives	16	7
SOUTHERN POWER CO
Assets:
Derivatives	61	76
Liabilities:
Derivatives	26	28
SOUTHERN Co GAS
Assets:
Derivatives	127	233
Liabilities:
Derivatives	39	124
Collateral already posted, aggregate fair value	178	$ 277
Fair Value, Measurements, Recurring
Assets:
Cash equivalents	846
Other investments	26
Total	3,361
Liabilities:
Contingent consideration	21
Total	712
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	841
Other investments	9
Total	1,936
Liabilities:
Contingent consideration	0
Total	405
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	5
Other investments	17
Total	1,359
Liabilities:
Contingent consideration	0
Total	264
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents	0
Other investments	0
Total	12
Liabilities:
Contingent consideration	21
Total	43
Fair Value, Measurements, Recurring | Net Asset Value as a Practical Expedient (NAV)
Assets:
Total	54
Fair Value, Measurements, Recurring | Energy-related derivatives
Assets:
Derivatives	459
Liabilities:
Derivatives	616
Fair Value, Measurements, Recurring | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	270
Liabilities:
Derivatives	405
Fair Value, Measurements, Recurring | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	177
Liabilities:
Derivatives	189
Fair Value, Measurements, Recurring | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	12
Liabilities:
Derivatives	22
Fair Value, Measurements, Recurring | Foreign currency derivatives
Assets:
Derivatives	60
Liabilities:
Derivatives	23
Fair Value, Measurements, Recurring | Foreign currency derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | Foreign currency derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	60
Liabilities:
Derivatives	23
Fair Value, Measurements, Recurring | Foreign currency derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | Interest rate derivatives
Liabilities:
Derivatives	52
Fair Value, Measurements, Recurring | Interest rate derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | Interest rate derivatives | Significant Other Observable Inputs (Level 2)
Liabilities:
Derivatives	52
Fair Value, Measurements, Recurring | Interest rate derivatives | Significant Unobservable Inputs (Level 3)
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | Domestic equity
Assets:
Investments in trusts	827
Fair Value, Measurements, Recurring | Domestic equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	703
Fair Value, Measurements, Recurring | Domestic equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	124
Fair Value, Measurements, Recurring | Domestic equity | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Foreign equity
Assets:
Investments in trusts	268
Fair Value, Measurements, Recurring | Foreign equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	62
Fair Value, Measurements, Recurring | Foreign equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	206
Fair Value, Measurements, Recurring | Foreign equity | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | U.S. Treasury and government agency securities
Assets:
Investments in trusts	307
Fair Value, Measurements, Recurring | U.S. Treasury and government agency securities | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | U.S. Treasury and government agency securities | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	307
Fair Value, Measurements, Recurring | U.S. Treasury and government agency securities | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Municipal bonds
Assets:
Investments in trusts	72
Fair Value, Measurements, Recurring | Municipal bonds | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Municipal bonds | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	72
Fair Value, Measurements, Recurring | Municipal bonds | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Pooled funds – fixed income
Assets:
Investments in trusts	16
Fair Value, Measurements, Recurring | Pooled funds – fixed income | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Pooled funds – fixed income | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	16
Fair Value, Measurements, Recurring | Pooled funds – fixed income | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Corporate bonds
Assets:
Investments in trusts	322
Fair Value, Measurements, Recurring | Corporate bonds | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	23
Fair Value, Measurements, Recurring | Corporate bonds | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	299
Fair Value, Measurements, Recurring | Corporate bonds | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Mortgage and asset backed securities
Assets:
Investments in trusts	74
Fair Value, Measurements, Recurring | Mortgage and asset backed securities | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Mortgage and asset backed securities | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	74
Fair Value, Measurements, Recurring | Mortgage and asset backed securities | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Private equity
Assets:
Investments in trusts	54
Fair Value, Measurements, Recurring | Private equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Private equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Private equity | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Private equity | Net Asset Value as a Practical Expedient (NAV)
Assets:
Investments in trusts	54
Fair Value, Measurements, Recurring | Cash and cash equivalents
Assets:
Investments in trusts	1
Fair Value, Measurements, Recurring | Cash and cash equivalents | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	1
Fair Value, Measurements, Recurring | Cash and cash equivalents | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Cash and cash equivalents | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | Other
Assets:
Investments in trusts	29
Fair Value, Measurements, Recurring | Other | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	27
Fair Value, Measurements, Recurring | Other | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	2
Fair Value, Measurements, Recurring | Other | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO
Assets:
Cash equivalents	435
Other investments	17
Total	1,421
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	430
Other investments	0
Total	978
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	5
Other investments	17
Total	389
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents	0
Other investments	0
Total	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Net Asset Value as a Practical Expedient (NAV)
Assets:
Total	54
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Energy-related derivatives
Assets:
Derivatives	6
Liabilities:
Derivatives	18
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	6
Liabilities:
Derivatives	18
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Domestic equity
Assets:
Investments in trusts	569
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Domestic equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	456
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Domestic equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	113
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Domestic equity | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Foreign equity
Assets:
Investments in trusts	122
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Foreign equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	62
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Foreign equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	60
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Foreign equity | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | U.S. Treasury and government agency securities
Assets:
Investments in trusts	21
Fair Value, Measurements, Recurring | ALABAMA POWER CO | U.S. Treasury and government agency securities | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | U.S. Treasury and government agency securities | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	21
Fair Value, Measurements, Recurring | ALABAMA POWER CO | U.S. Treasury and government agency securities | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Municipal bonds
Assets:
Investments in trusts	1
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Municipal bonds | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Municipal bonds | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	1
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Municipal bonds | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Corporate bonds
Assets:
Investments in trusts	164
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Corporate bonds | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	23
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Corporate bonds | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	141
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Corporate bonds | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Mortgage and asset backed securities
Assets:
Investments in trusts	25
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Mortgage and asset backed securities | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Mortgage and asset backed securities | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	25
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Mortgage and asset backed securities | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Private equity
Assets:
Investments in trusts	54
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Private equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Private equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Private equity | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Private equity | Net Asset Value as a Practical Expedient (NAV)
Assets:
Investments in trusts	54
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Other
Assets:
Investments in trusts	7
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Other | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	7
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Other | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Other | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO
Assets:
Total	984
Liabilities:
Total	80
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Total	267
Liabilities:
Total	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Total	717
Liabilities:
Total	80
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Unobservable Inputs (Level 3)
Assets:
Total	0
Liabilities:
Total	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Energy-related derivatives
Assets:
Derivatives	6
Liabilities:
Derivatives	43
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	6
Liabilities:
Derivatives	43
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Interest rate derivatives
Liabilities:
Derivatives	37
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Interest rate derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Interest rate derivatives | Significant Other Observable Inputs (Level 2)
Liabilities:
Derivatives	37
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Interest rate derivatives | Significant Unobservable Inputs (Level 3)
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Domestic equity
Assets:
Investments in trusts	248
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Domestic equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	247
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Domestic equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	1
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Domestic equity | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Foreign equity
Assets:
Investments in trusts	143
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Foreign equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Foreign equity | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	143
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Foreign equity | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | U.S. Treasury and government agency securities
Assets:
Investments in trusts	286
Fair Value, Measurements, Recurring | GEORGIA POWER CO | U.S. Treasury and government agency securities | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | U.S. Treasury and government agency securities | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	286
Fair Value, Measurements, Recurring | GEORGIA POWER CO | U.S. Treasury and government agency securities | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Municipal bonds
Assets:
Investments in trusts	71
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Municipal bonds | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Municipal bonds | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	71
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Municipal bonds | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Corporate bonds
Assets:
Investments in trusts	158
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Corporate bonds | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Corporate bonds | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	158
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Corporate bonds | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Mortgage and asset backed securities
Assets:
Investments in trusts	50
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Mortgage and asset backed securities | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Mortgage and asset backed securities | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	50
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Mortgage and asset backed securities | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Other
Assets:
Investments in trusts	22
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Other | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Investments in trusts	20
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Other | Significant Other Observable Inputs (Level 2)
Assets:
Investments in trusts	2
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Other | Significant Unobservable Inputs (Level 3)
Assets:
Investments in trusts	0
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO
Assets:
Cash equivalents	170
Total	173
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	170
Total	170
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	0
Total	3
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents	0
Total	0
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Energy-related derivatives
Assets:
Derivatives	3
Liabilities:
Derivatives	19
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	3
Liabilities:
Derivatives	19
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO
Assets:
Cash equivalents	177
Total	239
Liabilities:
Contingent consideration	21
Total	48
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	177
Total	177
Liabilities:
Contingent consideration	0
Total	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	0
Total	62
Liabilities:
Contingent consideration	0
Total	27
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents	0
Total	0
Liabilities:
Contingent consideration	21
Total	21
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Energy-related derivatives
Assets:
Derivatives	2
Liabilities:
Derivatives	4
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	2
Liabilities:
Derivatives	4
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Foreign currency derivatives
Assets:
Derivatives	60
Liabilities:
Derivatives	23
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Foreign currency derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Foreign currency derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	60
Liabilities:
Derivatives	23
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Foreign currency derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	0
Liabilities:
Derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS
Assets:
Total	473
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Total	271
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2)
Assets:
Total	190
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3)
Assets:
Total	12
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives
Assets:
Derivatives	442
Liabilities:
Derivatives	532
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Derivatives	270
Liabilities:
Derivatives	405
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives | Significant Other Observable Inputs (Level 2)
Assets:
Derivatives	160
Liabilities:
Derivatives	105
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Energy-related derivatives | Significant Unobservable Inputs (Level 3)
Assets:
Derivatives	12
Liabilities:
Derivatives	22
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Domestic equity
Assets:
Non-qualified deferred compensation trusts	10
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Domestic equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Non-qualified deferred compensation trusts	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Domestic equity | Significant Other Observable Inputs (Level 2)
Assets:
Non-qualified deferred compensation trusts	10
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Domestic equity | Significant Unobservable Inputs (Level 3)
Assets:
Non-qualified deferred compensation trusts	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Foreign equity
Assets:
Non-qualified deferred compensation trusts	4
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Foreign equity | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Non-qualified deferred compensation trusts	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Foreign equity | Significant Other Observable Inputs (Level 2)
Assets:
Non-qualified deferred compensation trusts	4
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Foreign equity | Significant Unobservable Inputs (Level 3)
Assets:
Non-qualified deferred compensation trusts	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Pooled funds – fixed income
Assets:
Non-qualified deferred compensation trusts	16
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Pooled funds – fixed income | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Non-qualified deferred compensation trusts	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Pooled funds – fixed income | Significant Other Observable Inputs (Level 2)
Assets:
Non-qualified deferred compensation trusts	16
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Pooled funds – fixed income | Significant Unobservable Inputs (Level 3)
Assets:
Non-qualified deferred compensation trusts	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Cash and cash equivalents
Assets:
Non-qualified deferred compensation trusts	1
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Cash and cash equivalents | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Non-qualified deferred compensation trusts	1
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Cash and cash equivalents | Significant Other Observable Inputs (Level 2)
Assets:
Non-qualified deferred compensation trusts	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Cash and cash equivalents | Significant Unobservable Inputs (Level 3)
Assets:
Non-qualified deferred compensation trusts	$ 0

XML

Fair Value Measurements - Schedule of Increase (Decrease) In Fair Value Of Funds (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ 75	$ 14	$ 227	$ 4
ALABAMA POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	38	15	125	10
GEORGIA POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ 37	$ (1)	$ 102	$ (6)

XML

Fair Value Measurements - Narrative (Details) $ in Millions	Jun. 30, 2019 USD ($) $ / MMBTU
ALABAMA POWER CO | Private equity
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair value	$ 54
Unfunded commitments	45
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Energy-related derivatives
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair value of derivatives	$ (10)
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Energy-related derivatives | Forward Price | Valuation, Market Approach | Minimum
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Measurement input (usd per mmbtu) | $ / MMBTU	0.09
SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Energy-related derivatives | Forward Price | Valuation, Market Approach | Maximum
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Measurement input (usd per mmbtu) | $ / MMBTU	1.39

XML

Fair Value Measurements - Financial Instruments for which Carrying Amount did not Equal Fair Value (Details) $ in Millions	Jun. 30, 2019 USD ($)
Long-term debt, including securities due within one year:
Carrying amount	$ 42,596
Fair value	45,394
ALABAMA POWER CO
Long-term debt, including securities due within one year:
Carrying amount	7,922
Fair value	8,717
GEORGIA POWER CO
Long-term debt, including securities due within one year:
Carrying amount	10,969
Fair value	11,749
MISSISSIPPI POWER CO
Long-term debt, including securities due within one year:
Carrying amount	1,618
Fair value	1,657
SOUTHERN POWER CO
Long-term debt, including securities due within one year:
Carrying amount	5,011
Fair value	5,261
SOUTHERN Co GAS
Long-term debt, including securities due within one year:
Carrying amount	5,916
Fair value	$ 6,420

XML

Fair Value Measurements - Fair Value of Commodity Derivative Contracts that Include a Significant Unobservable Component (Details) - SOUTHERN Co GAS - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	$ (19)	$ 0
Transfers to Level 3	(3)	(33)
Changes in fair value	12	23
Ending balance	$ (10)	$ (10)

XML

Derivatives - Energy-Related and Interest Rate Derivatives (Details) MMBTU in Millions, $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($) MMBTU
Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	536
Interest rate derivatives
Interest rate derivatives
Notional Amount	$ 3,000
Fair Value Gain (Loss) at June 30, 2019	$ (53)
ALABAMA POWER CO | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	88
GEORGIA POWER CO | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	200
GEORGIA POWER CO | Interest rate derivatives | March 2025 | Cash Flow Hedges of Forecasted Debt
Interest rate derivatives
Notional Amount	$ 250
Weighted Average Interest Rate Paid	2.23%
Fair Value Gain (Loss) at June 30, 2019	$ (6)
GEORGIA POWER CO | Interest rate derivatives | September 2029 | Cash Flow Hedges of Forecasted Debt
Interest rate derivatives
Notional Amount	$ 250
Weighted Average Interest Rate Paid	2.39%
Fair Value Gain (Loss) at June 30, 2019	$ (10)
GEORGIA POWER CO | Interest rate derivatives | March 2030 | Cash Flow Hedges of Forecasted Debt
Interest rate derivatives
Notional Amount	$ 250
Weighted Average Interest Rate Paid	2.40%
Fair Value Gain (Loss) at June 30, 2019	$ (9)
GEORGIA POWER CO | Interest rate derivatives | February 2044 | Cash Flow Hedges of Forecasted Debt
Interest rate derivatives
Notional Amount	$ 250
Weighted Average Interest Rate Paid	2.48%
Fair Value Gain (Loss) at June 30, 2019	$ (12)
GEORGIA POWER CO | Interest rate derivatives | December 2019 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Notional Amount	$ 200
Interest Rate Received	4.25%
Fair Value Gain (Loss) at June 30, 2019	$ (1)
GEORGIA POWER CO | LIBOR | Interest rate derivatives | December 2019 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Weighted Average Interest Rate Paid	2.46%
MISSISSIPPI POWER CO | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	101
SOUTHERN POWER CO | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	8
SOUTHERN Co GAS | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	139
SOUTHERN Co GAS | Energy-related, Natural Gas | Derivatives not designated as hedging instruments | Long
Energy-related derivative contracts
Derivative nonmonetary notional amount net long short position volume | MMBTU	4,000
SOUTHERN Co GAS | Energy-related, Natural Gas | Derivatives not designated as hedging instruments | Short
Energy-related derivative contracts
Derivative nonmonetary notional amount net long short position volume | MMBTU	3,900
Southern Company | Interest rate derivatives | June 2020 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Notional Amount	$ 300
Interest Rate Received	2.75%
Fair Value Gain (Loss) at June 30, 2019	$ (1)
Southern Company | Interest rate derivatives | July 2021 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Notional Amount	$ 1,500
Interest Rate Received	2.35%
Fair Value Gain (Loss) at June 30, 2019	$ (14)
Southern Company | LIBOR | Interest rate derivatives | June 2020 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Weighted Average Interest Rate Paid	0.92%
Southern Company | LIBOR | Interest rate derivatives | July 2021 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Weighted Average Interest Rate Paid	0.87%

XML

Derivatives - Narrative (Details) MMBTU in Millions	6 Months Ended
	Jun. 30, 2019 USD ($) MMBTU	Dec. 31, 2018 USD ($)
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	25
Cash flow hedge gain (loss) to be reclassified within twelve months	$ (18,000,000)
Collateral already posted, aggregate fair value	$ 178,000,000
ALABAMA POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	4
Cash flow hedge gain (loss) to be reclassified within twelve months	$ 0
GEORGIA POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	8
Cash flow hedge gain (loss) to be reclassified within twelve months	$ 0
MISSISSIPPI POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	4
Cash flow hedge gain (loss) to be reclassified within twelve months	$ 0
SOUTHERN POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	9
Cash flow hedge gain (loss) to be reclassified within twelve months	$ 0
Parent Company and Southern Power
Derivative [Line Items]
Foreign currency cash flow hedge gain (loss) to be reclassified during next 12 months	(23,000,000)
Registrants | Derivative Counterparties
Derivative [Line Items]
Collateral already posted, aggregate fair value	0
SOUTHERN Co GAS
Derivative [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months	0
Collateral already posted, aggregate fair value	$ 178,000,000	$ 277,000,000

XML

Derivatives - Foreign Currency Derivatives (Details) - 6 months ended Jun. 30, 2019 - Cash Flow Hedges of Forecasted Debt - Foreign currency derivatives € in Millions, $ in Millions	USD ($)	EUR (€)
Derivative [Line Items]
Pay Notional	$ 1,241
Receive Notional | €		€ 1,100
Fair Value Gain (Loss) at June 30, 2019	37
SOUTHERN POWER CO | June 2022
Derivative [Line Items]
Pay Notional	$ 677
Pay Rate	2.95%
Receive Notional | €		600
Receive Rate	1.00%
Fair Value Gain (Loss) at June 30, 2019	$ 14
SOUTHERN POWER CO | June 2026
Derivative [Line Items]
Pay Notional	$ 564
Pay Rate	3.78%
Receive Notional | €		€ 500
Receive Rate	1.85%
Fair Value Gain (Loss) at June 30, 2019	$ 23

XML

Derivatives - Derivative Financial Statement Presentation and Amounts With Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Derivatives, assets	$ 519	$ 837
Derivatives, liabilities	691	1,036
Derivative asset, Gross amounts offset	(328)	(524)
Derivative liability, Gross amounts offset	(506)	(801)
Derivative asset	191	313
Derivative liability	185	235
Collateral already posted, aggregate fair value	178
Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivatives, assets	442	741
Derivatives, liabilities	517	900
Derivatives not designated as hedging instruments | Gain (loss) on energy-related cash flow hedges | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	286	561
Derivatives not designated as hedging instruments | Gain (loss) on energy-related cash flow hedges | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	298	575
Derivatives not designated as hedging instruments | Gain (loss) on energy-related cash flow hedges | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	156	180
Derivatives not designated as hedging instruments | Gain (loss) on energy-related cash flow hedges | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	219	325
Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	16	17
Derivatives, liabilities	91	55
Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	7	8
Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	57	23
Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	9	9
Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	34	26
Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Assets held for sale, current
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Liabilities held for sale, current
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	6
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	61	79
Derivatives, liabilities	83	81
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	3
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	7	7
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	1
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1	2
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	50	19
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	2	30
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	23	23
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	60	75
Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
ALABAMA POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	6	6
Derivatives, liabilities	18	10
Derivative asset, Gross amounts offset	(3)	(4)
Derivative liability, Gross amounts offset	(3)	(4)
Derivative asset	3	2
Derivative liability	15	6
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	6	6
Derivatives, liabilities	18	10
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	4	3
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	11	4
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	3
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	7	6
GEORGIA POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	6	6
Derivatives, liabilities	80	23
Derivative asset, Gross amounts offset	(6)	(6)
Derivative liability, Gross amounts offset	(6)	(6)
Derivative asset	0	0
Derivative liability	74	17
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	6	6
Derivatives, liabilities	43	21
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	2
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	26	8
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	5	4
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	17	13
GEORGIA POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Derivatives, liabilities	37	2
GEORGIA POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
GEORGIA POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	37	2
MISSISSIPPI POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	3	3
Derivatives, liabilities	19	9
Derivative asset, Gross amounts offset	(3)	(2)
Derivative liability, Gross amounts offset	(3)	(2)
Derivative asset	0	1
Derivative liability	16	7
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	3	3
Derivatives, liabilities	19	9
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	1
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	10	3
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	2
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	9	6
SOUTHERN POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	62	79
Derivatives, liabilities	27	31
Derivative asset, Gross amounts offset	(1)	(3)
Derivative liability, Gross amounts offset	(1)	(3)
Derivative asset	61	76
Derivative liability	26	28
SOUTHERN POWER CO | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	0
Derivatives, liabilities	0	0
SOUTHERN POWER CO | Derivatives not designated as hedging instruments | Gain (loss) on energy-related cash flow hedges | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	0
SOUTHERN POWER CO | Derivatives not designated as hedging instruments | Gain (loss) on energy-related cash flow hedges | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	61	79
Derivatives, liabilities	27	31
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	3
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	3	6
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	1
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1	2
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	23	23
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	60	75
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
SOUTHERN Co GAS
Derivatives, Fair Value [Line Items]
Derivatives, assets	442	741
Derivatives, liabilities	532	909
Derivative asset, Gross amounts offset	(315)	(508)
Derivative liability, Gross amounts offset	(493)	(785)
Derivative asset	127	233
Derivative liability	39	124
Collateral already posted, aggregate fair value	178	277
Weather derivative premium		8
SOUTHERN Co GAS | Gain (loss) on energy-related cash flow hedges
Derivatives, Fair Value [Line Items]
Collateral already posted, aggregate fair value	12
SOUTHERN Co GAS | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivatives, assets	441	739
Derivatives, liabilities	517	899
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Gain (loss) on energy-related cash flow hedges | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	156	180
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Gain (loss) on energy-related cash flow hedges | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	219	325
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Gain (loss) on energy-related cash flow hedges | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, assets	285	559
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Gain (loss) on energy-related cash flow hedges | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	298	574
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	2
Derivatives, liabilities	11	9
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1	1
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	2
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	10	8
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Derivatives, liabilities	4	1
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Gain (loss) on energy-related cash flow hedges | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	$ 4	$ 1

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Derivatives - Pre-tax Effects of Derivatives Designated as Cash Flow Hedging Instruments (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Collateral already posted, aggregate fair value	$ 178		$ 178
Gain (Loss) Recognized in OCI on Derivative	(44)	$ (73)	(82)	$ (11)
GEORGIA POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	(37)	0	(37)	0
SOUTHERN POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	(3)	(74)	(41)	(11)
SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Collateral already posted, aggregate fair value	178		178		$ 277
Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(65)		(65)		(40)
Gain (Loss) Recognized in OCI on Derivative	(6)	0	(6)	12
Energy-related derivatives | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(48)		(48)		(19)
Energy-related derivatives | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(23)		(23)		(16)
Energy-related derivatives | Assets held for sale, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)					(6)
Energy-related derivatives | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	6		6		1
Energy-related derivatives | ALABAMA POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(13)		(13)		(6)
Energy-related derivatives | ALABAMA POWER CO | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(11)		(11)		(3)
Energy-related derivatives | ALABAMA POWER CO | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(5)		(5)		(3)
Energy-related derivatives | ALABAMA POWER CO | Assets held for sale, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)					0
Energy-related derivatives | ALABAMA POWER CO | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	3		3		0
Energy-related derivatives | GEORGIA POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(37)		(37)		(15)
Energy-related derivatives | GEORGIA POWER CO | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(25)		(25)		(6)
Energy-related derivatives | GEORGIA POWER CO | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(12)		(12)		(9)
Energy-related derivatives | GEORGIA POWER CO | Assets held for sale, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)					0
Energy-related derivatives | GEORGIA POWER CO | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0		0		0
Energy-related derivatives | MISSISSIPPI POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(16)		(16)		(6)
Energy-related derivatives | MISSISSIPPI POWER CO | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(10)		(10)		(2)
Energy-related derivatives | MISSISSIPPI POWER CO | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(6)		(6)		(4)
Energy-related derivatives | MISSISSIPPI POWER CO | Assets held for sale, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)					0
Energy-related derivatives | MISSISSIPPI POWER CO | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0		0		0
Energy-related derivatives | SOUTHERN POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	(2)	(1)	(2)	10
Energy-related derivatives | SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	1		1		(7)
Collateral already posted, aggregate fair value	12		12
Energy-related derivatives | SOUTHERN Co GAS | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(2)		(2)		(8)
Energy-related derivatives | SOUTHERN Co GAS | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0		0		0
Energy-related derivatives | SOUTHERN Co GAS | Assets held for sale, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)					0
Energy-related derivatives | SOUTHERN Co GAS | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	3		3		$ 1
Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	(37)	0	(37)	(2)
Foreign currency derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	(1)	(73)	(39)	(21)
Foreign currency derivatives | SOUTHERN POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	(1)	(73)	(39)	(21)
Total interest expense, net of amounts capitalized | Interest rate derivatives | GEORGIA POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	$ (37)	$ 0	$ (37)	$ 0

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Derivatives - Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Derivative [Line Items]
Depreciation and amortization	$ 755	$ 783	$ 1,506	$ 1,552
Total interest expense, net of amounts capitalized	(429)	(470)	(859)	(928)
Total other income (expense), net	99	78	176	138
Cash Flow Hedging | Gain (loss) on energy-related cash flow hedges | Total depreciation and amortization
Derivative [Line Items]
Gain (loss) on hedge	(1)	1	(4)	2
Cash Flow Hedging | Interest rate derivatives | Total interest expense, net of amounts capitalized
Derivative [Line Items]
Gain (loss) on hedge	(5)	(6)	(9)	(11)
Cash Flow Hedging | Foreign currency derivatives | Total interest expense, net of amounts capitalized
Derivative [Line Items]
Gain (loss) on hedge	(6)	(7)	(12)	(12)
Cash Flow Hedging | Foreign currency derivatives | Total other income (expense), net
Derivative [Line Items]
Gain (loss) on hedge	16	(73)	(8)	(37)
Fair Value Hedging | Interest rate derivatives | Total interest expense, net of amounts capitalized
Derivative [Line Items]
Gain (loss) on hedge	19	(7)	33	(31)
SOUTHERN POWER CO
Derivative [Line Items]
Depreciation and amortization	119	125	237	240
Total interest expense, net of amounts capitalized	(41)	(46)	(84)	(93)
Total other income (expense), net	40	2	41	5
SOUTHERN POWER CO | Cash Flow Hedging | Gain (loss) on energy-related cash flow hedges | Total depreciation and amortization
Derivative [Line Items]
Gain (loss) on hedge	(1)	1	(4)	2
SOUTHERN POWER CO | Cash Flow Hedging | Foreign currency derivatives | Total interest expense, net of amounts capitalized
Derivative [Line Items]
Gain (loss) on hedge	(6)	(7)	(12)	(12)
SOUTHERN POWER CO | Cash Flow Hedging | Foreign currency derivatives | Total other income (expense), net
Derivative [Line Items]
Gain (loss) on hedge	$ 16	$ (73)	$ (8)	$ (37)

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Derivatives - Cumulative Basis Adjustments for Fair Value Hedges (Details) - Fair Value Hedging - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Securities due within one year
Derivative [Line Items]
Carrying Amount of the Hedged Item	$ (499)	$ (498)
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	1	2
Securities due within one year | GEORGIA POWER CO
Derivative [Line Items]
Carrying Amount of the Hedged Item	(499)	(498)
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	1	2
Long-term debt
Derivative [Line Items]
Carrying Amount of the Hedged Item	(2,087)	(2,052)
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	$ 7	$ 41

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Derivatives - Pre-tax Effects of Derivatives Not Designated as Hedging (Details) - Derivatives not designated as hedging instruments - Energy-related derivatives - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	$ 45	$ (26)	$ 86	$ (39)
Natural gas revenues
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	50	(28)	83	(43)
Cost of natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	(5)	2	3	4
SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	45	(26)	86	(39)
SOUTHERN Co GAS | Natural gas revenues
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	50	(28)	83	(43)
SOUTHERN Co GAS | Cost of natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	$ (5)	$ 2	$ 3	$ 4

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Acquisitions and Dispositions - Southern Company Narrative (Details) - USD ($) $ in Millions		3 Months Ended	6 Months Ended		12 Months Ended
	Jan. 01, 2019	Jun. 30, 2019	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2019	Jul. 22, 2019
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Preliminary gain			$ 2,512	$ (35)
Goodwill impairment		$ 32	$ 32
Disposal Group, Disposed of by Sale, Not Discontinued Operations | GULF POWER CO
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of businesses, net of cash divested	$ 5,800
Amount of indebtedness assumed at closing	$ 1,300
Disposal Group, Held-for-sale, Not Discontinued Operations | PowerSecure Utility Infrastructure Services Unit
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Goodwill impairment		$ 32
Scenario, Forecast | Disposal Group, Disposed of by Sale, Not Discontinued Operations | GULF POWER CO
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Preliminary gain					$ 2,500
Preliminary gain, net of tax					$ 1,300
Subsequent Event | Disposal Group, Disposed of by Sale, Not Discontinued Operations | PowerSecure Utility Infrastructure Services Unit
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale price						$ 71

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Acquisitions and Dispositions - Southern Power Narrative (Details) $ in Millions			1 Months Ended	6 Months Ended	7 Months Ended
	Oct. 01, 2019 USD ($)	Jun. 13, 2019 USD ($) MW	Jun. 30, 2019 USD ($) MW	Jun. 30, 2019 USD ($) MW	Dec. 31, 2019 USD ($)	May 31, 2019 MW	May 04, 2019 MW	Dec. 31, 2018 USD ($)
Business Acquisition [Line Items]
Construction work in progress			$ 7,568	$ 7,568				$ 7,254
Property, plant, and equipment, subject to lien			114,867	114,867				116,914
SOUTHERN POWER CO
Business Acquisition [Line Items]
Construction work in progress			419	419				430
Property, plant, and equipment, subject to lien			14,518	14,518				$ 14,883
SOUTHERN POWER CO | Lien
Business Acquisition [Line Items]
Property, plant, and equipment, subject to lien			545	545
SOUTHERN POWER CO | Disposal Group, Held-for-sale, Not Discontinued Operations | Mankato expansion | Scenario, Forecast
Business Acquisition [Line Items]
Gain on termination fee	$ 15
SOUTHERN POWER CO | Disposal Group, Held-for-sale, Not Discontinued Operations | Nacogdoches Biomass-Fueled Facility
Business Acquisition [Line Items]
Approximate nameplate capacity (MW) | MW		115
Nacogdoches biomass-fueled facility		$ 461
After tax gain		$ 88
SOUTHERN POWER CO | Wind Generating Facility
Business Acquisition [Line Items]
Gain on sale				14
SOUTHERN POWER CO | Series of Construction Projects
Business Acquisition [Line Items]
Construction work in progress			186	186
SOUTHERN POWER CO | Series of Construction Projects | Minimum
Business Acquisition [Line Items]
Estimated future construction payments			405	405
SOUTHERN POWER CO | Series of Construction Projects | Maximum
Business Acquisition [Line Items]
Estimated future construction payments			450	$ 450
SOUTHERN POWER CO | Diamond State Generation Partners
Business Acquisition [Line Items]
Contributions to acquire majority interest			$ 116
SOUTHERN POWER CO | Diamond State Generation Partners | Scenario, Forecast
Business Acquisition [Line Items]
Contributions to acquire majority interest					$ 173
SOUTHERN POWER CO | Mankato expansion
Business Acquisition [Line Items]
Approximate nameplate capacity (MW) | MW			385	385		385	385

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Acquisitions and Dispositions - Schedule of Construction Projects (Details) - SOUTHERN POWER CO - MW	1 Months Ended	3 Months Ended
	May 31, 2019	Jun. 30, 2020	Dec. 31, 2019	Jun. 30, 2019	May 04, 2019	Aug. 31, 2018	May 31, 2018
Mankato expansion
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)	385			385	385
PPA Contract Period	20 years
Wild Horse Mountain | Wild Horse Mountain
Business Acquisition [Line Items]
Ownership percentage by parent							100.00%
Reading | Reading
Business Acquisition [Line Items]
Ownership percentage by parent						100.00%
Reading | Reading | Class B Membership Interest
Business Acquisition [Line Items]
Ownership percentage by parent						100.00%
Scenario, Forecast | Wild Horse Mountain
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)			100
PPA Contract Period			20 years
Scenario, Forecast | Reading
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)		200
PPA Contract Period		12 years

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Acquisitions and Dispositions - Assets Held for Sale (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Assets Held for Sale:
Current assets	$ 58	$ 393
Liabilities Held for Sale:
Current liabilities	36	425
Other non-current liabilities	39	2,836
SOUTHERN POWER CO
Liabilities Held for Sale:
Current liabilities	10	15
Disposal Group, Held-for-sale, Not Discontinued Operations
Assets Held for Sale:
Current assets	58	393
Total property, plant, and equipment	588	4,583
Goodwill and other intangible assets	51	40
Other non-current assets	46	727
Total Assets Held for Sale	743	5,743
Liabilities Held for Sale:
Current liabilities	36	425
Other non-current liabilities	39	932
Long-term debt		1,286
Accumulated deferred income taxes		618
Total Liabilities Held for Sale	75	3,261
Disposal Group, Held-for-sale, Not Discontinued Operations | SOUTHERN POWER CO
Assets Held for Sale:
Current assets	10	8
Total property, plant, and equipment	559	536
Goodwill and other intangible assets	40	40
Other non-current assets	0	0
Total Assets Held for Sale	609	584
Liabilities Held for Sale:
Current liabilities	10	15
Other non-current liabilities	0	0
Long-term debt		0
Accumulated deferred income taxes		0
Total Liabilities Held for Sale	$ 10	$ 15

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Acquisitions and Dispositions - Pre-tax Profit (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
GULF POWER CO
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Earnings before income taxes	$ 0	$ 31	$ 0	$ 87
SOUTHERN POWER CO | Florida Plants
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Earnings before income taxes	0	14	0	24
SOUTHERN POWER CO | Plant Nacogdoches
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Earnings before income taxes	$ 9	$ 7	$ 16	$ 13

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Leases - Major Categories of Lease Obligations (Details) $ in Millions	Jun. 30, 2019 USD ($)
Lessee, Lease, Description [Line Items]
Lease obligations	$ 2,218
Electric generating units
Lessee, Lease, Description [Line Items]
Lease obligations	1,072
Real estate/land
Lessee, Lease, Description [Line Items]
Lease obligations	800
Communication towers
Lessee, Lease, Description [Line Items]
Lease obligations	147
Railcars
Lessee, Lease, Description [Line Items]
Lease obligations	54
Other
Lessee, Lease, Description [Line Items]
Lease obligations	145
ALABAMA POWER CO
Lessee, Lease, Description [Line Items]
Lease obligations	190
ALABAMA POWER CO | Electric generating units
Lessee, Lease, Description [Line Items]
Lease obligations	150
ALABAMA POWER CO | Real estate/land
Lessee, Lease, Description [Line Items]
Lease obligations	4
ALABAMA POWER CO | Communication towers
Lessee, Lease, Description [Line Items]
Lease obligations	1
ALABAMA POWER CO | Railcars
Lessee, Lease, Description [Line Items]
Lease obligations	25
ALABAMA POWER CO | Other
Lessee, Lease, Description [Line Items]
Lease obligations	10
GEORGIA POWER CO
Lessee, Lease, Description [Line Items]
Lease obligations	1,686
GEORGIA POWER CO | Electric generating units
Lessee, Lease, Description [Line Items]
Lease obligations	1,580
GEORGIA POWER CO | Real estate/land
Lessee, Lease, Description [Line Items]
Lease obligations	62
GEORGIA POWER CO | Communication towers
Lessee, Lease, Description [Line Items]
Lease obligations	3
GEORGIA POWER CO | Railcars
Lessee, Lease, Description [Line Items]
Lease obligations	27
GEORGIA POWER CO | Other
Lessee, Lease, Description [Line Items]
Lease obligations	14
MISSISSIPPI POWER CO
Lessee, Lease, Description [Line Items]
Lease obligations	7
MISSISSIPPI POWER CO | Electric generating units
Lessee, Lease, Description [Line Items]
Lease obligations	0
MISSISSIPPI POWER CO | Real estate/land
Lessee, Lease, Description [Line Items]
Lease obligations	2
MISSISSIPPI POWER CO | Communication towers
Lessee, Lease, Description [Line Items]
Lease obligations	0
MISSISSIPPI POWER CO | Railcars
Lessee, Lease, Description [Line Items]
Lease obligations	3
MISSISSIPPI POWER CO | Other
Lessee, Lease, Description [Line Items]
Lease obligations	2
SOUTHERN POWER CO
Lessee, Lease, Description [Line Items]
Lease obligations	395
SOUTHERN POWER CO | Electric generating units
Lessee, Lease, Description [Line Items]
Lease obligations	0
SOUTHERN POWER CO | Real estate/land
Lessee, Lease, Description [Line Items]
Lease obligations	395
SOUTHERN POWER CO | Communication towers
Lessee, Lease, Description [Line Items]
Lease obligations	0
SOUTHERN POWER CO | Railcars
Lessee, Lease, Description [Line Items]
Lease obligations	0
SOUTHERN POWER CO | Other
Lessee, Lease, Description [Line Items]
Lease obligations	0
SOUTHERN Co GAS
Lessee, Lease, Description [Line Items]
Lease obligations	94
SOUTHERN Co GAS | Electric generating units
Lessee, Lease, Description [Line Items]
Lease obligations	0
SOUTHERN Co GAS | Real estate/land
Lessee, Lease, Description [Line Items]
Lease obligations	81
SOUTHERN Co GAS | Communication towers
Lessee, Lease, Description [Line Items]
Lease obligations	13
SOUTHERN Co GAS | Railcars
Lessee, Lease, Description [Line Items]
Lease obligations	0
SOUTHERN Co GAS | Other
Lessee, Lease, Description [Line Items]
Lease obligations	$ 0

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Leases - Narrative (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($)
Lessee, Lease, Description [Line Items]
Remaining terms	14 years
Total estimate obligations of leases that have not yet commenced	$ 81
Maximum
Lessee, Lease, Description [Line Items]
Lease term, lease not yet commenced	31 years
Real estate | Maximum
Lessee, Lease, Description [Line Items]
Remaining terms	25 years
Communication towers | Maximum
Lessee, Lease, Description [Line Items]
Lessee, lease term	10 years
Lessee, renewal period	20 years
Fuel cells | Maximum
Lessee, Lease, Description [Line Items]
Lessor, lease term, operating lease	15 years
GEORGIA POWER CO
Lessee, Lease, Description [Line Items]
Remaining terms	10 years 6 months
Lease obligations	$ 1,517
GEORGIA POWER CO | Real estate | Maximum
Lessee, Lease, Description [Line Items]
Remaining terms	25 years
GEORGIA POWER CO | Electric generating units | Affiliate
Lessee, Lease, Description [Line Items]
Lease obligations	$ 660
GEORGIA POWER CO | Electric generating units | Minimum
Lessee, Lease, Description [Line Items]
Remaining terms	4 years
GEORGIA POWER CO | Electric generating units | Maximum
Lessee, Lease, Description [Line Items]
Remaining terms	18 years
GEORGIA POWER CO | Outdoor lighting | Maximum
Lessee, Lease, Description [Line Items]
Lessor, lease term, operating lease	5 years
SOUTHERN Co GAS
Lessee, Lease, Description [Line Items]
Remaining terms	9 years 8 months 12 days
Lease obligations	$ 94
SOUTHERN Co GAS | Maximum
Lessee, Lease, Description [Line Items]
Lessor, remaining term	24 years
SOUTHERN Co GAS | Real estate | Maximum
Lessee, Lease, Description [Line Items]
Remaining terms	25 years
SOUTHERN POWER CO
Lessee, Lease, Description [Line Items]
Remaining terms	33 years 6 months
Lease obligations	$ 395
Total estimate obligations of leases that have not yet commenced	$ 81
SOUTHERN POWER CO | Maximum
Lessee, Lease, Description [Line Items]
Lease term, lease not yet commenced	31 years
SOUTHERN POWER CO | Land | Maximum
Lessee, Lease, Description [Line Items]
Lessee, lease term	48 years
SOUTHERN POWER CO | Electric generating units | Maximum
Lessee, Lease, Description [Line Items]
Lessor, lease term, operating lease	28 years
ALABAMA POWER CO
Lessee, Lease, Description [Line Items]
Remaining terms	3 years 7 months 6 days
Lease obligations	$ 185
ALABAMA POWER CO | Electric generating units | Minimum
Lessee, Lease, Description [Line Items]
Remaining terms	4 years
ALABAMA POWER CO | Electric generating units | Maximum
Lessee, Lease, Description [Line Items]
Remaining terms	18 years
ALABAMA POWER CO | Outdoor lighting | Maximum
Lessee, Lease, Description [Line Items]
Lessor, lease term, operating lease	5 years
MISSISSIPPI POWER CO
Lessee, Lease, Description [Line Items]
Remaining terms	7 years
Lease obligations	$ 7
MISSISSIPPI POWER CO | Electric generating units | Maximum
Lessee, Lease, Description [Line Items]
Lessor, lease term, sales-type lease	20 years
MISSISSIPPI POWER CO | Outdoor lighting | Maximum
Lessee, Lease, Description [Line Items]
Lessor, lease term, operating lease	5 years

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Leases - Balance Sheet Amounts Recorded for Operating and Financing Leases (Details) $ in Millions	Jun. 30, 2019 USD ($)
Operating Leases
Operating lease ROU assets, net, including held for sale	$ 1,907
Operating lease ROU assets, net	1,862
Operating lease obligations - current, including held for sale	241
Operating lease obligations - current	228
Operating lease obligations - non current, including held for sale	1,733
Operating lease obligations - non current	1,702
Total operating lease obligations, including held for sale	1,974
Finance Leases
Finance lease ROU assets, net	237
Finance lease obligations - current	24
Finance lease obligations - noncurrent	220
Total finance lease obligations	244
ALABAMA POWER CO
Operating Leases
Operating lease ROU assets, net	152
Operating lease obligations - current	48
Operating lease obligations - non current	137
Total operating lease obligations	185
Finance Leases
Finance lease ROU assets, net	5
Finance lease obligations - current	1
Finance lease obligations - noncurrent	4
Total finance lease obligations	5
GEORGIA POWER CO
Operating Leases
Operating lease ROU assets, net	1,492
Operating lease obligations - current	140
Operating lease obligations - non current	1,377
Total operating lease obligations	1,517
Finance Leases
Finance lease ROU assets, net	142
Finance lease obligations - current	10
Finance lease obligations - noncurrent	159
Total finance lease obligations	169
MISSISSIPPI POWER CO
Operating Leases
Operating lease ROU assets, net	7
Operating lease obligations - current	2
Operating lease obligations - non current	5
Total operating lease obligations	7
Finance Leases
Finance lease ROU assets, net	0
Finance lease obligations - current	0
Finance lease obligations - noncurrent	0
Total finance lease obligations	0
SOUTHERN POWER CO
Operating Leases
Operating lease ROU assets, net	370
Operating lease obligations - current	22
Operating lease obligations - non current	373
Total operating lease obligations	395
Finance Leases
Finance lease ROU assets, net	0
Finance lease obligations - current	0
Finance lease obligations - noncurrent	0
Total finance lease obligations	0
SOUTHERN Co GAS
Operating Leases
Operating lease ROU assets, net	95
Operating lease obligations - current	15
Operating lease obligations - non current	79
Total operating lease obligations	94
Finance Leases
Finance lease ROU assets, net	0
Finance lease obligations - current	0
Finance lease obligations - noncurrent	0
Total finance lease obligations	$ 0

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Leases - Lease Costs (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Lease cost
Operating lease cost	$ 77	$ 147
Finance lease cost:
Amortization of ROU assets	7	14
Interest on lease obligations	3	6
Total finance lease cost	10	20
Short-term lease costs	13	30
Variable lease cost	29	48
Sublease income	0	0
Total lease cost	129	245
ALABAMA POWER CO
Lease cost
Operating lease cost	13	20
Finance lease cost:
Amortization of ROU assets	0	0
Interest on lease obligations	0	0
Total finance lease cost	0	0
Short-term lease costs	6	11
Variable lease cost	1	1
Sublease income	0	0
Total lease cost	20	32
GEORGIA POWER CO
Lease cost
Operating lease cost	50	99
Finance lease cost:
Amortization of ROU assets	4	7
Interest on lease obligations	4	9
Total finance lease cost	8	16
Short-term lease costs	6	12
Variable lease cost	25	41
Sublease income	0	0
Total lease cost	89	168
MISSISSIPPI POWER CO
Lease cost
Operating lease cost	1	1
Finance lease cost:
Amortization of ROU assets	0	0
Interest on lease obligations	0	0
Total finance lease cost	0	0
Short-term lease costs	0	0
Variable lease cost	0	0
Sublease income	0	0
Total lease cost	1	1
SOUTHERN POWER CO
Lease cost
Operating lease cost	7	14
Finance lease cost:
Amortization of ROU assets	0	0
Interest on lease obligations	0	0
Total finance lease cost	0	0
Short-term lease costs	0	0
Variable lease cost	1	3
Sublease income	0	0
Total lease cost	8	17
SOUTHERN Co GAS
Lease cost
Operating lease cost	5	9
Finance lease cost:
Amortization of ROU assets	0	0
Interest on lease obligations	0	0
Total finance lease cost	0	0
Short-term lease costs	0	0
Variable lease cost	0	0
Sublease income	0	0
Total lease cost	$ 5	$ 9

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Leases - Other Information (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($)
Cash paid for amounts included in the measurements of lease obligations:
Operating cash flows from operating leases	$ 129
Operating cash flows from finance leases	2
Financing cash flows from finance leases	16
ROU assets obtained in exchange for new operating lease obligations	55
ROU assets obtained in exchange for new finance lease obligations	$ 33
Weighted-average remaining lease term in years:
Operating leases	14 years
Finance leases	18 years 3 months 18 days
Weighted-average discount rate:
Operating leases	4.53%
Finance leases	5.05%
ALABAMA POWER CO
Cash paid for amounts included in the measurements of lease obligations:
Operating cash flows from operating leases	$ 20
Operating cash flows from finance leases	0
Financing cash flows from finance leases	0
ROU assets obtained in exchange for new operating lease obligations	5
ROU assets obtained in exchange for new finance lease obligations	$ 1
Weighted-average remaining lease term in years:
Operating leases	3 years 7 months 6 days
Finance leases	12 years 9 months 18 days
Weighted-average discount rate:
Operating leases	3.33%
Finance leases	3.67%
GEORGIA POWER CO
Cash paid for amounts included in the measurements of lease obligations:
Operating cash flows from operating leases	$ 75
Operating cash flows from finance leases	10
Financing cash flows from finance leases	3
ROU assets obtained in exchange for new operating lease obligations	13
ROU assets obtained in exchange for new finance lease obligations	$ 28
Weighted-average remaining lease term in years:
Operating leases	10 years 6 months
Finance leases	11 years
Weighted-average discount rate:
Operating leases	4.46%
Finance leases	10.69%
MISSISSIPPI POWER CO
Cash paid for amounts included in the measurements of lease obligations:
Operating cash flows from operating leases	$ 1
Operating cash flows from finance leases	0
Financing cash flows from finance leases	0
ROU assets obtained in exchange for new operating lease obligations	0
ROU assets obtained in exchange for new finance lease obligations	$ 0
Weighted-average remaining lease term in years:
Operating leases	7 years
Weighted-average discount rate:
Operating leases	4.06%
SOUTHERN POWER CO
Cash paid for amounts included in the measurements of lease obligations:
Operating cash flows from operating leases	$ 12
Operating cash flows from finance leases	0
Financing cash flows from finance leases	0
ROU assets obtained in exchange for new operating lease obligations	0
ROU assets obtained in exchange for new finance lease obligations	$ 0
Weighted-average remaining lease term in years:
Operating leases	33 years 6 months
Weighted-average discount rate:
Operating leases	5.68%
SOUTHERN Co GAS
Cash paid for amounts included in the measurements of lease obligations:
Operating cash flows from operating leases	$ 9
Operating cash flows from finance leases	0
Financing cash flows from finance leases	0
ROU assets obtained in exchange for new operating lease obligations	13
ROU assets obtained in exchange for new finance lease obligations	$ 0
Weighted-average remaining lease term in years:
Operating leases	9 years 8 months 12 days
Weighted-average discount rate:
Operating leases	3.73%

XML

Leases - Maturities of Lease Liabilities (Details) $ in Millions	Jun. 30, 2019 USD ($)
Operating leases:
2019 (remaining)	$ 178
2020	295
2021	279
2022	268
2023	204
Thereafter	1,661
Total	2,885
Less: Present value discount	911
Operating lease obligations, including held for sale	1,974
Finance leases:
2019 (remaining)	16
2020	33
2021	27
2022	23
2023	18
Thereafter	266
Total	383
Less: Present value discount	139
Finance lease obligations	244
ALABAMA POWER CO
Operating leases:
2019 (remaining)	33
2020	53
2021	52
2022	52
2023	4
Thereafter	2
Total	196
Less: Present value discount	11
Operating lease obligations	185
Finance leases:
2019 (remaining)	0
2020	1
2021	1
2022	1
2023	1
Thereafter	1
Total	5
Less: Present value discount	0
Finance lease obligations	5
GEORGIA POWER CO
Operating leases:
2019 (remaining)	129
2020	203
2021	198
2022	196
2023	197
Thereafter	990
Total	1,913
Less: Present value discount	396
Operating lease obligations	1,517
Finance leases:
2019 (remaining)	16
2020	28
2021	25
2022	25
2023	25
Thereafter	165
Total	284
Less: Present value discount	115
Finance lease obligations	169
MISSISSIPPI POWER CO
Operating leases:
2019 (remaining)	1
2020	2
2021	1
2022	1
2023	1
Thereafter	2
Total	8
Less: Present value discount	1
Operating lease obligations	7
Finance leases:
2019 (remaining)	0
2020	0
2021	0
2022	0
2023	0
Thereafter	0
Total	0
Less: Present value discount	0
Finance lease obligations	0
SOUTHERN POWER CO
Operating leases:
2019 (remaining)	13
2020	22
2021	23
2022	23
2023	24
Thereafter	849
Total	954
Less: Present value discount	559
Operating lease obligations	395
Finance leases:
2019 (remaining)	0
2020	0
2021	0
2022	0
2023	0
Thereafter	0
Total	0
Less: Present value discount	0
Finance lease obligations	0
SOUTHERN Co GAS
Operating leases:
2019 (remaining)	9
2020	17
2021	16
2022	13
2023	11
Thereafter	49
Total	115
Less: Present value discount	21
Operating lease obligations	94
Finance leases:
2019 (remaining)	0
2020	0
2021	0
2022	0
2023	0
Thereafter	0
Total	0
Less: Present value discount	0
Finance lease obligations	$ 0

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Leases - Lease Income (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	$ 2	$ 5
Lease income - operating leases	67	139
Variable lease income	115	182
Total lease income	184	326
GEORGIA POWER CO
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	0	0
Lease income - operating leases	19	39
Variable lease income	0	0
Total lease income	19	39
MISSISSIPPI POWER CO
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	2	5
Lease income - operating leases	0	0
Variable lease income	0	0
Total lease income	2	5
SOUTHERN POWER CO
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	0	0
Lease income - operating leases	39	80
Variable lease income	125	198
Total lease income	164	278
SOUTHERN Co GAS
Lessor, Lease, Description [Line Items]
Lease income - interest income on sales-type leases	0	0
Lease income - operating leases	9	17
Variable lease income	0	0
Total lease income	$ 9	$ 17

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Leases - Undiscounted Cash Flows to be Received Under Tolling Arrangements Accounted for as Sales-type Leases (Details) $ in Millions	Jun. 30, 2019 USD ($)
Lessor, Lease, Description [Line Items]
2019 (remaining)	$ 7
2020	14
2021	14
2022	13
2023	12
Thereafter	135
Total undiscounted cash flows	195
Lease receivable	106
Difference between undiscounted cash flows and discounted cash flows	89
MISSISSIPPI POWER CO
Lessor, Lease, Description [Line Items]
2019 (remaining)	7
2020	14
2021	14
2022	13
2023	12
Thereafter	135
Total undiscounted cash flows	195
Lease receivable	106
Difference between undiscounted cash flows and discounted cash flows	$ 89

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Leases - Undiscounted Cash Flows to be Received Under PPAs Accounted for as Operating Leases (Details) $ in Millions	Jun. 30, 2019 USD ($)
Lessor, Lease, Description [Line Items]
2019 (remaining)	$ 75
2020	125
2021	118
2022	109
2023	103
Thereafter	1,142
Total	1,672
GEORGIA POWER CO
Lessor, Lease, Description [Line Items]
2019 (remaining)	13
2020	26
2021	18
2022	8
2023	2
Thereafter	0
Total	67
SOUTHERN POWER CO
Lessor, Lease, Description [Line Items]
2019 (remaining)	52
2020	65
2021	66
2022	68
2023	69
Thereafter	350
Total	670
SOUTHERN Co GAS
Lessor, Lease, Description [Line Items]
2019 (remaining)	17
2020	35
2021	35
2022	34
2023	34
Thereafter	497
Total	$ 652

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Segment and Related Information - Narrative (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019 USD ($) state	Jun. 30, 2018 USD ($)	Jun. 30, 2019 USD ($) state pipeline segment	Jun. 30, 2018 USD ($)
Segment Reporting Information [Line Items]
Number of states in which entity operates | state	3		3
Total operating revenues	$ 5,098	$ 5,627	$ 10,510	$ 11,999
Natural gas
Segment Reporting Information [Line Items]
Total operating revenues	689	706	2,163	2,314
SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Total operating revenues	510	555	953	1,064
SOUTHERN POWER CO | Wholesale revenues, affiliates
Segment Reporting Information [Line Items]
Total operating revenues	117	109	204	192
SOUTHERN POWER CO | Traditional Electric Operating Companies | Wholesale revenues, affiliates
Segment Reporting Information [Line Items]
Total operating revenues	$ 117	109	$ 204	192
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Number of states in which entity operates | state	4		4
Total operating revenues	$ 689	730	$ 2,163	2,369
Number of reportable segments | segment			4
SOUTHERN Co GAS | Pipeline
Segment Reporting Information [Line Items]
Number of pipeline construction projects | pipeline			2
SOUTHERN Co GAS | SNG
Segment Reporting Information [Line Items]
Ownership percentage, equity method investment	50.00%		50.00%
SOUTHERN Co GAS | Dalton Pipeline
Segment Reporting Information [Line Items]
Ownership percentage, equity method investment	50.00%		50.00%
SOUTHERN Co GAS | Natural gas
Segment Reporting Information [Line Items]
Total operating revenues	$ 688	710	$ 2,163	2,341
SOUTHERN Co GAS | Traditional Electric Operating Companies | Natural gas
Segment Reporting Information [Line Items]
Total operating revenues	0	0	0	0
SOUTHERN Co GAS | SOUTHERN POWER CO | Natural gas
Segment Reporting Information [Line Items]
Total operating revenues	$ 16	$ 22	$ 33	$ 58

XML

Segment and Related Information - Financial Data for Business Segments (Details) $ in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2019 USD ($)	Mar. 31, 2019 USD ($)	Jun. 30, 2018 USD ($) utility	Mar. 31, 2018 USD ($)	Jun. 30, 2019 USD ($)	Jun. 30, 2018 USD ($) utility	Dec. 31, 2018 USD ($)
Segment Reporting Information [Line Items]
Operating revenues	$ 5,098		$ 5,627		$ 10,510	$ 11,999
Segment net income (loss)	899	$ 2,084	(154)	$ 938	2,982	784
Goodwill	5,282				5,282		$ 5,315
Total assets	114,867				114,867		116,914
Goodwill impairment	32				32
Asset impairment					32	161
Loss on disposition	(8)		36		(2,506)	36
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	689		730		2,163	2,369
Segment net income (loss)	106	270	(31)	279	376	248
Goodwill	5,015				5,015		5,015
Total assets	20,761				20,761		21,448
Goodwill impairment	0		0		0	42
Loss on disposition	0		$ 36		0	$ 36
SOUTHERN Co GAS | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Segment Reporting Information [Line Items]
Number of natural gas distribution utilities disposed | utility			3			3
SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Operating revenues	510		$ 555		953	$ 1,064
Segment net income (loss)	174	$ 56	22	$ 121	230	143
Total assets	14,518				14,518		14,883
Asset impairment	0		119		0	119
Impairment charge, net of tax			89			89
Loss on disposition	(23)		0		(23)	0
SOUTHERN POWER CO | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Plant Nacogdoches
Segment Reporting Information [Line Items]
Pre-tax gain on the sale of Plant Nacogdoches	23				23
Gain on the sale of Plant Nacogdoches, after tax	88				88
Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	4,290		4,565		8,085	8,948
Segment net income (loss)	956		(26)		1,576	706
Goodwill	2				2		2
Total assets	92,049				92,049		93,959
Traditional Electric Operating Companies | GEORGIA POWER AND MISSISSIPPI POWER CO | Kemper County Energy Facility
Segment Reporting Information [Line Items]
Public utilities, property, plant and equipment, amount of loss (recovery) on plant abandonment	4		1,100		6	1,100
Public utilities, property, plant and equipment, amount of loss (recovery) on plant abandonment after tax	3		800		5	800
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	689		730		2,163	2,369
SOUTHERN Co GAS | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Pivotal Home Solutions
Segment Reporting Information [Line Items]
Goodwill impairment						42
All Other | Disposal Group, Disposed of by Sale, Not Discontinued Operations | GULF POWER CO
Segment Reporting Information [Line Items]
Preliminary pre-tax gain (reduction)	15				2,500
Preliminary after-tax gain (reduction)	(11)				1,300
Gas Distribution Operations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Goodwill	4,034				4,034		4,034
Gas Distribution Operations | SOUTHERN Co GAS | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Segment Reporting Information [Line Items]
Operating revenues			70			237
Gas Marketing Services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Goodwill	981				981		981
Operating revenues			24			55
Loss on disposition			36			36
Operating Segments | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	682		724		2,177	2,381
Segment net income (loss)	103		(8)		376	284
Total assets	21,360				21,360		21,918
Operating Segments | Traditional Electric Operating Companies | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	3,899		4,124		7,343	8,104
Segment net income (loss)	782		(48)		1,346	563
Goodwill	0				0		0
Total assets	78,314				78,314		79,382
Operating Segments | SOUTHERN POWER CO | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	510		555		953	1,064
Segment net income (loss)	174		22		230	143
Goodwill	2				2		2
Total assets	14,518				14,518		14,883
Operating Segments | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	689		730		2,163	2,369
Segment net income (loss)	106		(31)		376	248
Goodwill	5,015				5,015		5,015
Total assets	20,761				20,761		21,448
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues	186		381		368	782
Segment net income (loss)	(154)		(100)		1,041	(174)
Goodwill	265				265		298
Total assets	3,343				3,343		3,285
Operating Segments | All Other | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	13		11		24	26
Segment net income (loss)	3		(23)		0	(36)
Total assets	10,934				10,934		11,112
Operating Segments | Gas Distribution Operations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	568		643		1,740	1,856
Segment net income (loss)	58		68		191	216
Total assets	17,397				17,397		17,266
Operating Segments | Gas Pipeline Investments | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	8		8		16	16
Segment net income (loss)	25		21		57	48
Total assets	1,768				1,768		1,763
Operating Segments | Wholesale Gas Services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	48		(16)		134	150
Segment net income (loss)	23		(21)		70	83
Total assets	668				668		1,302
Less Gross Gas Costs	1,238		1,454		3,165	3,393
Operating Segments | Wholesale Gas Services | SOUTHERN Co GAS | Third Party Gross Revenues
Segment Reporting Information [Line Items]
Operating revenues	1,223		1,336		3,148	3,274
Operating Segments | Wholesale Gas Services | SOUTHERN Co GAS | Intercompany Revenues
Segment Reporting Information [Line Items]
Operating revenues	63		102		151	269
Operating Segments | Wholesale Gas Services | SOUTHERN Co GAS | Total Gross Revenues
Segment Reporting Information [Line Items]
Operating revenues	1,286		1,438		3,299	3,543
Operating Segments | Gas Marketing Services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	58		89		287	359
Segment net income (loss)	(3)		(76)		58	(63)
Total assets	1,527				1,527		1,587
Eliminations
Segment Reporting Information [Line Items]
Operating revenues	(67)		(49)		(106)	(100)
Segment net income (loss)	(9)		3		(11)	4
Goodwill	0				0		0
Total assets	(1,286)				(1,286)		(1,778)
Eliminations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	(6)		(5)		(38)	(38)
Segment net income (loss)	0		0		0	0
Total assets	(11,533)				(11,533)		(11,582)
Eliminations | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	(119)		(114)		(211)	(220)
Segment net income (loss)	0		$ 0		0	$ 0
Goodwill	0				0		0
Total assets	$ (783)				$ (783)		$ (306)

XML

Segment and Related Information - Financial Data for Products and Services (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Concentration Risk [Line Items]
Operating revenues	$ 5,098	$ 5,627	$ 10,510	$ 11,999
Retail
Concentration Risk [Line Items]
Operating revenues	3,540	3,740	6,623	7,308
Wholesale
Concentration Risk [Line Items]
Operating revenues	542	616	1,041	1,239
Other
Concentration Risk [Line Items]
Operating revenues	161	170	331	330
Gas Distribution Operations
Concentration Risk [Line Items]
Operating revenues	562	642	1,724	1,865
Electric Utilities' Revenues
Concentration Risk [Line Items]
Operating revenues	4,290	4,565	8,085	8,948
Electric Utilities' Revenues | Retail
Concentration Risk [Line Items]
Operating revenues	3,540	3,740	6,623	7,308
Electric Utilities' Revenues | Wholesale
Concentration Risk [Line Items]
Operating revenues	542	616	1,041	1,239
Electric Utilities' Revenues | Other
Concentration Risk [Line Items]
Operating revenues	208	209	421	401
Southern Company Gas' Revenues
Concentration Risk [Line Items]
Operating revenues	689	730	2,163	2,369
Southern Company Gas' Revenues | Gas Distribution Operations
Concentration Risk [Line Items]
Operating revenues	563	638	1,724	1,838
Southern Company Gas' Revenues | Gas Distribution Operations | Revenues | Product Concentration Risk | Three Gas Distribution Operations
Concentration Risk [Line Items]
Operating revenues		70		237
Southern Company Gas' Revenues | Gas Marketing Services
Concentration Risk [Line Items]
Operating revenues	58	89	287	359
Southern Company Gas' Revenues | Gas Marketing Services | Revenues | Product Concentration Risk | Pivotal Home Solutions
Concentration Risk [Line Items]
Operating revenues		24		55
Southern Company Gas' Revenues | Other
Concentration Risk [Line Items]
Operating revenues	$ 68	$ 3	$ 152	$ 172