10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2018

OR

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number	Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification No.
1-3526	The Southern Company (A Delaware Corporation) 30 Ivan Allen Jr. Boulevard, N.W. Atlanta, Georgia 30308 (404) 506-5000	58-0690070
1-3164	Alabama Power Company (An Alabama Corporation) 600 North 18th Street Birmingham, Alabama 35203 (205) 257-1000	63-0004250
1-6468	Georgia Power Company (A Georgia Corporation) 241 Ralph McGill Boulevard, N.E. Atlanta, Georgia 30308 (404) 506-6526	58-0257110
001-31737	Gulf Power Company (A Florida Corporation) One Energy Place Pensacola, Florida 32520 (850) 444-6111	59-0276810
001-11229	Mississippi Power Company (A Mississippi Corporation) 2992 West Beach Boulevard Gulfport, Mississippi 39501 (228) 864-1211	64-0205820
001-37803	Southern Power Company (A Delaware Corporation) 30 Ivan Allen Jr. Boulevard, N.W. Atlanta, Georgia 30308 (404) 506-5000	58-2598670
1-14174	Southern Company Gas (A Georgia Corporation) Ten Peachtree Place, N.E. Atlanta, Georgia 30309 (404) 584-4000	58-2210952

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
Gulf 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 September 30, 2018
The Southern Company	Par Value $5 Per Share	1,028,888,684
Alabama Power Company	Par Value $40 Per Share	30,537,500
Georgia Power Company	Without Par Value	9,261,500
Gulf Power Company	Without Par Value	7,392,717
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, Gulf 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

September 30, 2018

		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
	Management's Discussion and Analysis of Financial Condition and Results of Operations	17
	Alabama Power Company
	Condensed Statements of Income	61
	Condensed Statements of Comprehensive Income	61
	Condensed Statements of Cash Flows	62
	Condensed Balance Sheets	63
	Management's Discussion and Analysis of Financial Condition and Results of Operations	65
	Georgia Power Company
	Condensed Statements of Income	82
	Condensed Statements of Comprehensive Income	82
	Condensed Statements of Cash Flows	83
	Condensed Balance Sheets	84
	Management's Discussion and Analysis of Financial Condition and Results of Operations	86
	Gulf Power Company
	Condensed Statements of Income	113
	Condensed Statements of Comprehensive Income	113
	Condensed Statements of Cash Flows	114
	Condensed Balance Sheets	115
	Management's Discussion and Analysis of Financial Condition and Results of Operations	117
	Mississippi Power Company
	Condensed Statements of Operations	133
	Condensed Statements of Comprehensive Income	133
	Condensed Statements of Cash Flows	134
	Condensed Balance Sheets	135
	Management's Discussion and Analysis of Financial Condition and Results of Operations	137
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	158
	Condensed Consolidated Statements of Comprehensive Income	158
	Condensed Consolidated Statements of Cash Flows	159
	Condensed Consolidated Balance Sheets	160
	Management's Discussion and Analysis of Financial Condition and Results of Operations	162

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q

September 30, 2018

		Page Number
	PART I—FINANCIAL INFORMATION (CONTINUED)
	Southern Company Gas and Subsidiary Companies
	Condensed Consolidated Statements of Income	177
	Condensed Consolidated Statements of Comprehensive Income	177
	Condensed Consolidated Statements of Cash Flows	178
	Condensed Consolidated Balance Sheets	179
	Management's Discussion and Analysis of Financial Condition and Results of Operations	181
	Notes to the Condensed Financial Statements	207
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	59
Item 4.	Controls and Procedures	59
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	286
Item 1A.	Risk Factors	286
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	291
	Signatures	295

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
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
Chattanooga Gas	Chattanooga Gas Company, a wholly-owned subsidiary of Southern Company Gas
Clean Power Plan	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
CO2	Carbon dioxide
COD	Commercial operation date
Contractor Settlement Agreement	The December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the Vogtle 3 and 4 Agreement
Cooperative Energy	Electric cooperative in Mississippi
CPCN	Certificate of public convenience and necessity
Customer Refunds	Refunds issued to Georgia Power customers in 2018 as ordered by the Georgia PSC related to the Guarantee Settlement Agreement
CWIP	Construction work in progress
Dalton Pipeline	A 50% undivided ownership interest of Southern Company Gas in a pipeline facility in Georgia
DOE	U.S. Department of Energy
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
Fitch	Fitch Ratings, Inc.
Form 10-K	Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas for the year ended December 31, 2017, as applicable
GAAP	U.S. generally accepted accounting principles
Georgia Power	Georgia Power Company
GHG	Greenhouse gas

5

DEFINITIONS

(continued)

Term	Meaning
Guarantee Settlement Agreement	The June 9, 2017 settlement agreement between the Vogtle Owners and Toshiba related to certain payment obligations of the EPC Contractor guaranteed by Toshiba
Gulf Power	Gulf Power Company
Heating Degree Days	A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Horizon Pipeline	Horizon Pipeline Company, LLC
IGCC	Integrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility (Plant Ratcliffe)
IIC	Intercompany interchange contract
Illinois Commission	Illinois Commerce Commission
Interim Assessment Agreement	Agreement entered into by the Vogtle Owners and the EPC Contractor to allow construction to continue after the EPC Contractor's bankruptcy filing
IRS	Internal Revenue Service
ITC	Investment tax credit
JEA	Jacksonville Electric Authority
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
LIFO	Last-in, first-out
LNG	Liquefied natural gas
Loan Guarantee Agreement	Loan guarantee agreement entered into by Georgia Power with the DOE in 2014, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4
LOCOM	Lower of weighted average cost or current market price
LTSA	Long-term service agreement
MEAG	Municipal Electric Authority of Georgia
Merger	The merger, effective July 1, 2016, of a wholly-owned, direct subsidiary of Southern Company with and into Southern Company Gas, with Southern Company Gas continuing as the surviving corporation
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.
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 plan
registrants	Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and Southern Company Gas
ROE	Return on equity
S&P	S&P Global Ratings, a division of S&P Global Inc.
SCS	Southern Company Services, Inc. (the Southern Company system service company)
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
SPSH	SP Solar Holdings I, LP
SP Wind	SP Wind Holdings II, LLC
Tax Reform Legislation	The Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018
Toshiba	Toshiba Corporation, parent company of Westinghouse
traditional electric operating companies	Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
Triton	Triton Container Investments, LLC
VCM	Vogtle Construction Monitoring
Virginia Commission	Virginia State Corporation Commission
Virginia Natural Gas	Virginia Natural Gas, Inc., a wholly-owned subsidiary of Southern Company Gas

7

DEFINITIONS

(continued)

Term	Meaning
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 the 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
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 wholesale business, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, projected equity ratios, costs of modernization efforts, 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, completion of announced dispositions, filings with state and federal regulatory authorities, impacts of the Tax Reform Legislation, federal and state income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "would," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• the impact of recent and future federal and state regulatory changes, including environmental laws and regulations governing air, water, land, and protection of other natural resources, and also changes in tax 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 uncertainty surrounding the Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of Southern Company and its subsidiaries;

• current and future litigation or regulatory investigations, proceedings, or inquiries;

• 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 such as self-generation and distributed generation technologies;

• variations in demand for electricity and natural gas, including those relating to weather, the general economy, population and business growth (and declines), the effects of energy conservation and efficiency measures, and any potential economic impacts resulting from federal fiscal decisions;

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

• limits on pipeline capacity;

• 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 scale, including changes in labor costs, availability, and productivity, challenges with management of contractors, subcontractors, or vendors, adverse weather conditions, shortages, increased costs or inconsistent quality of equipment, materials, and labor, including any changes related to imposition of import tariffs, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance;

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

• investment performance of the Southern Company system's 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 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 Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;

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

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

• litigation or other disputes related to the Kemper County energy facility;

• the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;

• 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 dispositions of Gulf Power, Southern Power's plants located in Florida, and the Mankato natural gas facility and the proposed sale of a noncontrolling interest in Southern Power's wind facilities, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;

• the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected and the possibility that costs related to the integration of Southern Company and Southern Company Gas will be greater than expected;

• 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;

• changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;

• the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;

• 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 such as influenzas, 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 September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Operating Revenues:
Retail electric revenues	$	4,605		$	4,615		$	11,913		$	11,786
Wholesale electric revenues	693			718			1,923			1,867
Other electric revenues	170			168			509			510
Natural gas revenues (includes alternative revenue programs of $5, $-, $(23), and $9, respectively)	492			532			2,806			2,746
Other revenues	199			168			1,007			494
Total operating revenues	6,159			6,201			18,158			17,403
Operating Expenses:
Fuel	1,310			1,285			3,514			3,372
Purchased power	257			256			760			646
Cost of natural gas	104			134			1,053			1,085
Cost of other sales	120			90			688			293
Other operations and maintenance	1,404			1,341			4,217			4,100
Depreciation and amortization	787			767			2,338			2,236
Taxes other than income taxes	319			303			990			941
Estimated loss on plants under construction	1			34			1,105			3,155
Gain on dispositions, net	(353		)	—			(317		)	(19		)
Impairment charges	36			—			197			—
Total operating expenses	3,985			4,210			14,545			15,809
Operating Income	2,174			1,991			3,613			1,594
Other Income and (Expense):
Allowance for equity funds used during construction	36			18			99			133
Earnings from equity method investments	36			32			108			100
Interest expense, net of amounts capitalized	(458		)	(407		)	(1,386		)	(1,248		)
Other income (expense), net	57			65			195			165
Total other income and (expense)	(329		)	(292		)	(984		)	(850		)
Earnings Before Income Taxes	1,845			1,699			2,629			744
Income taxes	623			590			598			317
Consolidated Net Income	1,222			1,109			2,031			427
Dividends on preferred and preference stock of subsidiaries	4			10			12			32
Net income attributable to noncontrolling interests	54			30			71			48
Consolidated Net Income Attributable to Southern Company	$	1,164		$	1,069		$	1,948		$	347
Common Stock Data:
Earnings per share -
Basic	$	1.14		$	1.07		$	1.92		$	0.35
Diluted	$	1.13		$	1.06		$	1.91		$	0.35
Average number of shares of common stock outstanding (in millions)
Basic	1,023			1,003			1,016			998
Diluted	1,029			1,010			1,021			1,005
Cash dividends paid per share of common stock	$	0.60		$	0.58		$	1.78		$	1.72

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 September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Consolidated Net Income	$	1,222		$	1,109		$	2,031		$	427
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(4), $15, $(6), and $32, respectively	(11		)	25			(19		)	54
Reclassification adjustment for amounts included in net income, net of tax of $5, $(10), $21, and $(36), respectively	14			(17		)	60			(59		)
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $3, $1, $4, and $2, respectively	8			1			11			3
Total other comprehensive income (loss)	11			9			52			(2		)
Comprehensive Income	1,233			1,118			2,083			425
Dividends on preferred and preference stock of subsidiaries	4			10			12			32
Comprehensive income attributable to noncontrolling interests	54			30			71			48
Consolidated Comprehensive Income Attributable to Southern Company	$	1,175		$	1,078		$	2,000		$	345

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 Nine Months Ended September 30,
	2018			2017
	(in millions)
Operating Activities:
Consolidated net income	$	2,031		$	427
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	2,647			2,564
Deferred income taxes	(286		)	15
Allowance for equity funds used during construction	(99		)	(133		)
Pension, postretirement, and other employee benefits	(60		)	(64		)
Settlement of asset retirement obligations	(160		)	(137		)
Stock based compensation expense	108			95
Estimated loss on plants under construction	1,081			3,148
Gain on dispositions, net	(324		)	(22		)
Impairment charges	197			—
Other, net	(21		)	(80		)
Changes in certain current assets and liabilities —
-Receivables	37			423
-Prepayments	14			(39		)
-Natural gas for sale	87			—
-Other current assets	(90		)	(66		)
-Accounts payable	(248		)	(467		)
-Accrued taxes	839			157
-Accrued compensation	(138		)	(230		)
-Retail fuel cost over recovery	36			(211		)
-Other current liabilities	(67		)	(129		)
Net cash provided from operating activities	5,584			5,251
Investing Activities:
Business acquisitions, net of cash acquired	(64		)	(1,016		)
Property additions	(5,793		)	(5,242		)
Nuclear decommissioning trust fund purchases	(846		)	(585		)
Nuclear decommissioning trust fund sales	840			580
Dispositions	2,773			66
Cost of removal, net of salvage	(252		)	(208		)
Change in construction payables, net	91			120
Investment in unconsolidated subsidiaries	(93		)	(134		)
Payments pursuant to LTSAs	(157		)	(189		)
Other investing activities	1			(77		)
Net cash used for investing activities	(3,500		)	(6,685		)
Financing Activities:
Decrease in notes payable, net	(1,225		)	(515		)
Proceeds —
Long-term debt	1,950			4,068
Common stock	878			613
Preferred stock	—			250
Short-term borrowings	3,150			1,263
Redemptions and repurchases —
Long-term debt	(4,498		)	(1,981		)
Preferred and preference stock	—			(150		)
Short-term borrowings	(1,800		)	(409		)
Distributions to noncontrolling interests	(86		)	(89		)
Capital contributions from noncontrolling interests	1,333			79
Payment of common stock dividends	(1,805		)	(1,716		)
Other financing activities	(237		)	(113		)
Net cash provided from (used for) financing activities	(2,340		)	1,300
Net Change in Cash, Cash Equivalents, and Restricted Cash	(256		)	(134		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	2,147			1,992
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	1,891		$	1,858
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $53 and $72 capitalized for 2018 and 2017, respectively)	$	1,402		$	1,286
Income taxes, net	137			(187		)
Noncash transactions — Accrued property additions at end of period	1,125			805

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 September 30, 2018			At December 31, 2017
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,847		$	2,130
Receivables —
Customer accounts receivable	1,730			1,806
Energy marketing receivables	498			607
Unbilled revenues	738			810
Under recovered fuel clause revenues	105			171
Other accounts and notes receivable	690			698
Accumulated provision for uncollectible accounts	(33		)	(44		)
Materials and supplies	1,418			1,438
Fossil fuel for generation	390			594
Natural gas for sale	486			595
Prepaid expenses	354			452
Other regulatory assets, current	522			604
Assets held for sale, current	407			12
Other current assets	232			199
Total current assets	9,384			10,072
Property, Plant, and Equipment:
In service	100,672			103,542
Less: Accumulated depreciation	30,739			31,457
Plant in service, net of depreciation	69,933			72,085
Nuclear fuel, at amortized cost	844			883
Construction work in progress	7,655			6,904
Total property, plant, and equipment	78,432			79,872
Other Property and Investments:
Goodwill	5,315			6,268
Equity investments in unconsolidated subsidiaries	1,569			1,513
Other intangible assets, net of amortization of $225 and $186 at September 30, 2018 and December 31, 2017, respectively	674			873
Nuclear decommissioning trusts, at fair value	1,872			1,832
Leveraged leases	794			775
Miscellaneous property and investments	258			249
Total other property and investments	10,482			11,510
Deferred Charges and Other Assets:
Deferred charges related to income taxes	792			825
Unamortized loss on reacquired debt	328			206
Other regulatory assets, deferred	6,196			6,943
Assets held for sale	4,667			—
Other deferred charges and assets	1,436			1,577
Total deferred charges and other assets	13,419			9,551
Total Assets	$	111,717		$	111,005

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 September 30, 2018			At December 31, 2017
	(in millions)
Current Liabilities:
Securities due within one year	$	3,013		$	3,892
Notes payable	2,564			2,439
Energy marketing trade payables	521			546
Accounts payable	2,246			2,530
Customer deposits	524			542
Accrued taxes	1,060			636
Accrued interest	422			488
Accrued compensation	800			959
Asset retirement obligations, current	348			351
Other regulatory liabilities, current	349			337
Liabilities held for sale, current	355			—
Other current liabilities	763			874
Total current liabilities	12,965			13,594
Long-term Debt	41,425			44,462
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	6,035			6,842
Deferred credits related to income taxes	6,651			7,256
Accumulated deferred ITCs	2,377			2,267
Employee benefit obligations	2,017			2,256
Asset retirement obligations, deferred	5,817			4,473
Accrued environmental remediation	269			389
Other cost of removal obligations	2,330			2,684
Other regulatory liabilities, deferred	153			239
Liabilities held for sale	2,835			—
Other deferred credits and liabilities	454			691
Total deferred credits and other liabilities	28,938			27,097
Total Liabilities	83,328			85,153
Redeemable Preferred Stock of Subsidiaries	324			324
Stockholders' Equity:
Common Stockholders' Equity:
Common stock, par value $5 per share —
Authorized — 1.5 billion shares
Issued — 1.0 billion shares
Treasury — September 30, 2018: 1.0 million shares
— December 31, 2017: 0.9 million shares
Par value	5,140			5,038
Paid-in capital	10,905			10,469
Treasury, at cost	(39		)	(36		)
Retained earnings	9,048			8,885
Accumulated other comprehensive loss	(177		)	(189		)
Total Common Stockholders' Equity	24,877			24,167
Noncontrolling Interests	3,188			1,361
Total Stockholders' Equity	28,065			25,528
Total Liabilities and Stockholders' Equity	$	111,717		$	111,005

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

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2018 vs. THIRD QUARTER 2017

AND

YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017

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 four traditional electric operating companies are vertically integrated utilities providing electric service in four 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. During the second quarter 2018, Southern Power completed the sale of a 33% equity interest in a limited partnership indirectly owning substantially all of its solar facilities. On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. On November 5, 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of $650 million. Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. In July 2018, Southern Company Gas completed sales of three of its natural gas distribution utilities. During the second quarter 2018, Southern Company Gas also completed the sale of Pivotal Home Solutions. The Southern Company system's other business activities include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers. Customer solutions include distributed generation systems, utility infrastructure solutions, and energy efficiency products and services. 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. See FUTURE EARNINGS POTENTIAL and Note (J) to the Condensed Financial Statements herein for additional information regarding disposition activity.

On May 20, 2018, Southern Company entered into a stock purchase agreement with NextEra Energy to sell Gulf Power for an aggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $1.3 billion), subject to certain adjustments. The completion of the sale is expected to occur in the first quarter 2019 and is subject to the satisfaction or waiver of certain closing conditions. The ultimate outcome of this matter cannot be determined at this time. See Note (J) to the Condensed Financial Statements under "Southern Company's Sale of Gulf Power" herein for additional information.

In 2018, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Atlanta Gas Light, and Nicor Gas reached agreements with their respective state PSCs or other applicable state regulatory agencies relating to the regulatory impacts of the Tax Reform Legislation, which, for some companies, included capital structure adjustments expected to help mitigate the potential adverse impacts to certain of their credit metrics. See Note (B) to the Condensed Financial Statements under "Regulatory Matters" herein for additional information regarding state PSC or other regulatory agency actions related to the Tax Reform Legislation. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation.

17

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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). 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 cost forecast and estimated contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for a total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds). Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC has stated the $7.3 billion estimate included in the seventeenth VCM proceeding does not represent a cost cap, Georgia Power did not seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast (or any related financing costs) in the nineteenth VCM report filed with the Georgia PSC on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs included in the revised construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018.

As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. On September 26, 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4. In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and certain of MEAG's wholly-owned subsidiaries, including MEAG Power SPVJ, LLC (MEAG SPVJ), to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners and (ii) a term sheet 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. Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain provisions of the Vogtle Owner Term Sheet.

In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In September 2018, the DOE extended the conditional commitment to March 31, 2019. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions.

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

See FUTURE EARNINGS POTENTIAL – "Construction Program – Nuclear Construction" and ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information.

18

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Net Income

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$95	8.9	$1,601	N/M

N/M - Not meaningful

Consolidated net income attributable to Southern Company was $1.2 billion ($1.14 per share) for the third quarter 2018 compared to $1.1 billion ($1.07 per share) for the corresponding period in 2017. The increase was primarily due to lower federal income tax expense as a result of the Tax Reform Legislation and higher retail electric revenues due to warmer weather in the third quarter 2018 compared to the corresponding period in 2017. These increases were partially offset by reductions in retail revenues related to Tax Reform Legislation impacts and an increase in operations and maintenance expenses.

Consolidated net income attributable to Southern Company was $1.9 billion ($1.92 per share) for year-to-date 2018 compared to $347 million ($0.35 per share) for the corresponding period in 2017. The increase was primarily due to charges of $3.2 billion ($2.2 billion after tax) in 2017 related to the Kemper IGCC at Mississippi Power, partially offset by a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss on Georgia Power's construction of Plant Vogtle Units 3 and 4. Also contributing to the increase were lower federal income tax expense as a result of the Tax Reform Legislation and higher retail electric revenues due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017, partially offset by reductions in retail revenues related to Tax Reform Legislation impacts and impairment charges at Southern Power and Southern Company Gas, primarily related to the dispositions described in Note (J) to the Condensed Financial Statements herein.

Retail Electric Revenues

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(10)	(0.2)	$127	1.1

In the third quarter 2018, retail electric revenues were $4.61 billion compared to $4.62 billion for the corresponding period in 2017. For year-to-date 2018, retail electric revenues were $11.9 billion compared to $11.8 billion for the corresponding period in 2017.

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

	Third Quarter 2018					Year-to-Date 2018
	(in millions)			(% change)		(in millions)			(% change)
Retail electric – prior year	$	4,615				$	11,786
Estimated change resulting from –
Rates and pricing	(198		)	(4.2	)	(444		)	(3.8	)
Sales growth	43			0.9		65			0.6
Weather	80			1.7		297			2.5
Fuel and other cost recovery	65			1.4		209			1.8
Retail electric – current year	$	4,605		(0.2	)%	$	11,913		1.1	%

Revenues associated with changes in rates and pricing decreased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to revenues deferred as regulatory liabilities for future

19

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

customer bill credits related to the Tax Reform Legislation and decreases in revenues recognized under the NCCR tariff at Georgia Power. The year-to-date 2018 decrease was partially offset by higher contributions from variable demand-driven pricing from commercial and industrial customers at Georgia Power.

See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power," " – Georgia Power – Rate Plans," and " – Gulf Power – Retail Base Rate Cases" 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 increased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017. In the third quarter and year-to-date 2018, weather-adjusted residential KWH sales increased 1.2% and 0.8%, respectively, and weather-adjusted commercial KWH sales increased 0.8% and 0.6%, respectively, primarily due to customer growth. Industrial KWH sales increased 2.4% and 1.9% in the third quarter and year-to-date 2018, respectively, primarily in the primary metals sector, largely due to strong domestic demand for steel and aluminum, partially offset by decreased sales in the chemicals and paper sectors, primarily due to customer maintenance outages and on-site cogeneration.

Fuel and other cost recovery revenues increased $65 million and $209 million in the third quarter and year-to-date 2018, respectively, when compared to the corresponding periods in 2017 primarily due to higher energy sales resulting from colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017. Electric rates for the traditional electric operating companies includeprovisions 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

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(25)	(3.5)	$56	3.0

Wholesale electric revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives 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 third quarter 2018,wholesale electric revenues were $693 million compared to $718 million for the corresponding period in 2017. This decrease was related to a $20 million decrease in energy revenues and a $5 million decrease in capacity revenues. The decrease in energy revenues is primarily related to a decrease in non-PPA revenues from short-term sales at Southern Power and a decrease in revenue under the Shared Services Agreement

20

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(SSA) between Mississippi Power and Cooperative Energy. These decreases were partially offset by an increase in revenues at Southern Power from new natural gas PPAs from existing facilities, an increase in sales from renewable facilities, and an increase in fuel costs that are contractually recovered through PPAs.

For year-to-date 2018, wholesale electric revenues were $1.92 billion compared to $1.87 billion for the corresponding period in 2017. This increase was related to a $70 million increase in energy revenues, partially offset by a $14 million decrease in capacity revenues. The increase in energy revenues primarily related to Southern Power included revenues from new natural gas PPAs from existing facilities, an increase in fuel costs that are contractually recovered through PPAs, and an increase in sales from renewable facilities. These increases were partially offset by a decrease in non-PPA revenues from short-term sales at Southern Power and a decrease in revenue under the SSA between Mississippi Power and Cooperative Energy.

Natural Gas Revenues

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(40)	(7.5)	$60	2.2

In the third quarter 2018, natural gas revenues were $492 million compared to $532 million for the corresponding period in 2017. For year-to-date 2018, natural gas revenues were $2.8 billion compared to $2.7 billion for the corresponding period in 2017.

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

	Third Quarter 2018					Year-to-Date 2018
	(in millions)			(% change)		(in millions)			(% change)
Natural gas revenues – prior year	$	532				$	2,746
Estimated change resulting from –
Infrastructure replacement programs and base rate changes	—			—		53			1.9
Gas costs and other cost recovery	(16		)	(3.0	)	(24		)	(0.9	)
Weather	1			0.2		17			0.6
Wholesale gas services	17			3.2		46			1.7
Dispositions(*)	(43		)	(8.1	)	(30		)	(1.1	)
Other	1			0.2		(2		)	—
Natural gas revenues – current year	$	492		(7.5	)%	$	2,806		2.2	%

(*) Includes Pivotal Utility Holdings' disposition of Elizabethtown Gas and Elkton Gas as well as NUI Corporation's disposition of Pivotal Utility Holdings, which primarily consisted of Florida City Gas. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

Revenues attributable to infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased for year-to-date 2018 due to continued investments recovered through infrastructure replacement programs and base rate increases as a result of rate cases, partially offset by revenue reductions for the impacts of the Tax Reform Legislation.

Revenues attributable to gas costs and other cost recovery in the third quarter 2018 decreased primarily due to reduced natural gas prices during the third quarter 2018 compared to the corresponding period in 2017 and decreased volumes of natural gas sold in the third quarter 2018 as a result of fewer customers served following the dispositions. Revenues attributable to gas costs and other cost recovery for year-to-date 2018 decreased due to reduced natural gas prices during 2018 compared to the corresponding period in 2017, partially offset by increased volumes of natural gas sold in 2018 as a result of colder weather, as determined by Heating Degree Days.

21

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Revenues increased due to colder weather, as determined by Heating Degree Days, in 2018 compared to the corresponding periods in 2017 that affected the utility customers in Illinois and Southern Company Gas' gas marketing services customers in Georgia and Illinois.

Revenues attributable to Southern Company Gas' wholesale gas services business increased primarily due to increased commercial activity, partially offset by derivative losses.

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

Other Revenues

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$31	18.5	$513	103.8

In the third quarter 2018, other revenues were $199 million compared to $168 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $1.0 billion compared to $494 million for the corresponding period in 2017. These increases were related to an increase in sales of products and services from additional customer contracts in distributed generation and utility infrastructure at PowerSecure, partially offset by a decrease in revenues resulting from the sale of Pivotal Home Solutions on June 4, 2018 at Southern Company Gas. The year-to-date 2018 increase was primarily related to storm restoration services in Puerto Rico. Additionally, these increases reflect $21 million and $40 million of revenues in the third quarter and year-to-date 2018, respectively, from unregulated sales of products and services that were reclassified to other revenues as a result of the adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). In prior periods, these revenues were included in other income (expense), net. See Note (A) to the Condensed Financial Statements herein for additional information regarding the adoption of ASC 606.

Fuel and Purchased Power Expenses

	Third Quarter 2018 vs. Third Quarter 2017			Year-to-Date 2018 vs. Year-to-Date 2017
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	25	1.9	$	142	4.2
Purchased power	1		0.4	114		17.6
Total fuel and purchased power expenses	$	26		$	256

In the third quarter 2018, total fuel and purchased power expenses were $1.6 billion compared to $1.5 billion for the corresponding period in 2017. The increase was primarily the result of a $68 million increase in the volume of KWHs generated and purchased, partially offset by a $42 million decrease in the average cost of fuel and purchased power.

For year-to-date 2018, total fuel and purchased power expenses were $4.3 billion compared to $4.0 billion for the corresponding period in 2017. The increase was primarily the result of a $300 million increase in the volume of KWHs generated and purchased, partially offset by a $74 million net decrease in the average cost of fuel and purchased power. In addition, fuel expense increased $30 million for 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.

22

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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" and " – Alabama Power – Accounting Order" 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:

	Third Quarter 2018	Third Quarter 2017	Year-to-Date 2018	Year-to-Date 2017
Total generation (in billions of KWHs)	56	55	153	147
Total purchased power (in billions of KWHs)	6	6	16	14
Sources of generation (percent) —
Gas	47	47	46	46
Coal	32	31	30	30
Nuclear	14	15	15	16
Hydro	2	2	3	2
Other	5	5	6	6
Cost of fuel, generated (in cents per net KWH)(a)—
Gas	2.78	2.92	2.79	2.93
Coal	2.75	2.75	2.79	2.82
Nuclear	0.81	0.80	0.80	0.80
Average cost of fuel, generated (in cents per net KWH)(a)	2.47	2.52	2.47	2.51
Average cost of purchased power (in cents per net KWH)(b)	5.32	5.36	5.52	5.32

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

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

Fuel

In the third quarter 2018, fuel expense was $1.31 billion compared to $1.29 billion for the corresponding period in 2017. The increase was primarily due to a 7.5% increase in the volume of KWHs generated by natural gas and a 1.3% increase in the volume of KWHs generated by coal, partially offset by a 4.8% decrease in the average cost of natural gas per KWH generated.

For year-to-date 2018, fuel expense was $3.5 billion compared to $3.4 billion for the corresponding period in 2017. The increase was primarily due to a 9.3% increase in the volume of KWHs generated by natural gas and a 4.1% increase in the volume of KWHs generated by coal, partially offset by a 4.8% decrease in the average cost of natural gas per KWH generated and a 1.1% decrease in the average cost of coal per KWH generated.

Purchased Power

For year-to-date 2018, purchased power expense was $760 million compared to $646 million for the corresponding period in 2017. The increase was primarily due to a 10.5% increase in the volume of KWHs purchased and a 3.8% increase in the average cost per KWH purchased.

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

23

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cost of Natural Gas

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(30)	(22.4)	$(32)	(2.9)

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 75% and 83% of total cost of natural gas for the third quarter and year-to-date 2018, respectively.

In the third quarter 2018, cost of natural gas was $104 million compared to $134 million for the corresponding period in 2017. The decrease reflects $14 million related to the Southern Company Gas Dispositions, which resulted in a decrease in the volume of natural gas sold in the third quarter 2018 as a result of fewer gas distribution customers, and a 3.2% decrease in natural gas prices during the third quarter 2018 compared to the corresponding period in 2017.

For year-to-date 2018, cost of natural gas was $1.05 billion compared to $1.09 billion for the corresponding period in 2017. The decrease reflects $8 million related to the Southern Company Gas Dispositions, which resulted in a decrease in the volume of natural gas sold in 2018 as a result of fewer gas distribution customers, as well as an 8.4% decrease in natural gas prices during 2018, partially offset by an increase in the volume of natural gas sold in 2018 as a result of colder weather compared to the corresponding period in 2017.

Cost of Other Sales

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$30	33.3	$395	134.8

In the third quarter 2018, cost of other sales was $120 million compared to $90 million for the corresponding period in 2017. For year-to-date 2018, cost of other sales was $688 million compared to $293 million for the corresponding period in 2017. These increases were related to an increase in sales of products and services from additional customer contracts in distributed generation and utility infrastructure at PowerSecure. The year-to-date 2018 increase was primarily related to storm restoration services in Puerto Rico.

Other Operations and Maintenance Expenses

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$63	4.7	$117	2.9

In the third quarter 2018, other operations and maintenance expenses were $1.4 billion compared to $1.3 billion for the corresponding period in 2017. The increase was primarily due to a $22 million increase in electric transmission and distribution costs, primarily due to additional line maintenance, and $21 million of disposition-related costs at Southern Company Gas. The increase also reflects $21 million of expenses from unregulated sales of products and services that were reclassified to other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net.

For year-to-date 2018, other operations and maintenance expenses were $4.2 billion compared to $4.1 billion for the corresponding period in 2017. The increase was primarily due to a $60 million increase in electric transmission and distribution costs, primarily due to additional line maintenance, and $29 million of disposition-related costs at

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Southern Company Gas. The increase also reflects $51 million of expenses from unregulated sales of products and services that were reclassified to other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. These increases were partially offset by a $32.5 million charge in the first quarter 2017 related to the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with the settlement of Gulf Power's 2017 rate case. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.

See Note (A) to the Condensed Financial Statements herein for additional information regarding the adoption of ASC 606.

Depreciation and Amortization

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$20	2.6	$102	4.6

In the third quarter 2018, depreciation and amortization was $787 million compared to $767 million for the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $2.3 billion compared to $2.2 billion for the corresponding period in 2017. These increases primarily reflect increases of $18 million and $76 million for the third quarter and year-to-date 2018, respectively, related to additional plant in service. Additionally, the year-to-date 2018 increase was due to $34 million in depreciation credits recognized in 2017, as authorized in Gulf Power's 2013 rate case settlement. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.

Taxes Other Than Income Taxes

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$16	5.3	$49	5.2

In the third quarter 2018, taxes other than income taxes were $319 million compared to $303 million for the corresponding period in 2017. For year-to-date 2018, taxes other than income taxes were $990 million compared to $941 million for the corresponding period in 2017. These increases were primarily due to increased property taxes at the traditional electric operating companies and investment capital taxes at Southern Company Gas. Also contributing to the year-to-date 2018 increase was an increase in municipal franchise fees primarily related to higher retail revenues at Georgia Power and an increase in revenue tax expenses as a result of higher revenues at Southern Company Gas.

Estimated Loss on Plants Under Construction

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(33)	(97.1)	$(2,050)	(65.0)

In the third quarter 2018, estimated loss on plants under construction was $1 million compared to $34 million for the corresponding period in 2017. For year-to-date 2018, estimated loss on plants under construction was $1.1 billion compared to $3.2 billion for the corresponding period in 2017. The third quarter 2018 decrease was primarily due to lower costs associated with abandonment and related closure activities for the mine and gasifier-related assets of the Kemper IGCC at Mississippi Power. The year-to-date 2018 decrease was primarily due to revisions to the estimated construction costs for, and subsequent suspension in June 2017 of, the Kemper IGCC at Mississippi

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Power, partially offset by charges in 2018 related to Georgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4.

See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" and "Nuclear Construction" herein for additional information.

Gain on Dispositions, Net

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$353	N/M	$298	N/M

N/M - Not meaningful

In the third quarter and year-to-date 2018, a net gain on dispositions of $353 million ($40 million gain after tax) and $317 million ($35 million loss after tax), respectively, were recorded related to the Southern Company Gas Dispositions. The year-to-date 2018 increase in gain on dispositions, net was partially offset by a $19 million decrease in gains from sales of integrated transmission system assets at Georgia Power. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information regarding related income taxes which substantially offset the gains for the Southern Company Gas Dispositions.

Impairment Charges

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$36	N/M	$197	N/M

N/M - Not meaningful

Southern Power recorded a $36 million asset impairment charge in the third quarter 2018 on wind turbine equipment held for development projects and a $119 million asset impairment charge in the second quarter 2018 in contemplation of the sale of its Florida plants. Additionally, Southern Company Gas recorded a goodwill impairment charge of $42 million during the first quarter 2018 in contemplation of the sale of Pivotal Home Solutions.

See Notes (A) and (J) to the Condensed Financial Statements herein under "Goodwill and Other Intangible Assets" and under "Southern Power – Sale of Florida Plants" and "Southern Company Gas," respectively, for additional information.

Allowance for Equity Funds Used During Construction

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$18	100.0	$(34)	(25.6)

In the third quarter 2018, AFUDC equity was $36 million compared to $18 million in the corresponding period in 2017. The increase was primarily due to a higher AFUDC rate resulting from a higher equity ratio and lower short-term borrowings at Georgia Power and a higher AFUDC base related to environmental and transmission projects at Alabama Power.

For year-to-date 2018, AFUDC equity was $99 million compared to $133 million in the corresponding period in 2017. The decrease primarily resulted from Mississippi Power's suspension of the Kemper IGCC construction in June 2017, partially offset by a higher AFUDC rate resulting from a higher equity ratio and lower short-term borrowings at Georgia Power and a higher AFUDC base related to environmental and transmission projects at Alabama Power.

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See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$51	12.5	$138	11.1

In the third quarter 2018, interest expense, net of amounts capitalized was $458 million compared to $407 million in the corresponding period in 2017. For year-to-date 2018, interest expense, net of amounts capitalized was $1.4 billion compared to $1.2 billion in the corresponding period in 2017. These increases were primarily due to an increase in variable interest rates and average outstanding debt at the parent company and a $33 million net reduction in the third quarter 2017 following a settlement with the IRS related to research and experimental deductions at Mississippi Power, partially offset by a decrease in average outstanding debt at Georgia Power. The year-to-date 2018 increase was also due to new debt issuances and short-term debt at Southern Company Gas and a reduction in AFUDC debt of $24 million related to the Kemper IGCC project suspension in June 2017 at Mississippi Power.

See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein, Note 6 to the financial statements of Southern Company in Item 8 of the Form 10-K, and Note (F) to the Condensed Financial Statements herein for additional information.

Other Income (Expense), Net

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(8)	(12.3)	$30	18.2

In the third quarter 2018, other income (expense), net was $57 million compared to $65 million for the corresponding period in 2017. The decrease was primarily due to a reduction of gains from the settlement of contractor litigation claims at Southern Company Gas, partially offset by a gain from a joint-development wind project at Southern Power, which is attributable to Southern Power's partner in the project and fully offset within noncontrolling interests.

For year-to-date 2018, other income (expense), net was $195 million compared to $165 million for the corresponding period in 2017. The increase was primarily due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018 and a gain from a joint-development wind project at Southern Power, which is attributable to Southern Power's partner in the project and fully offset within noncontrolling interests, partially offset by a reduction of gains from the settlement of contractor litigation claims at Southern Company Gas.

See Note (B) to the Condensed Financial Statements herein under "General Litigation Matters – Mississippi Power" and "Regulatory Matters – Southern Company Gas – Atlanta Gas Light's Pipeline Replacement Program" and Note (J) to the Condensed Financial Statements herein under "Southern Power – Development Projects" for additional information.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Income Taxes

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$33	5.6	$281	88.6

In the third quarter 2018, income taxes were $623 million compared to $590 million for the corresponding period in 2017. The increase was primarily due to tax expense related to the sales of Elizabethtown Gas, Elkton Gas, and Florida City Gas and the recognition of a valuation allowance on certain state tax credit carryforwards at Georgia Power, partially offset by lower federal income tax expense as well as the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation and a decrease in pre-tax earnings (excluding the gains on the sales of Elizabethtown Gas, Elkton Gas, and Florida City Gas).

For year-to-date 2018, income taxes were $598 million compared to $317 million for the corresponding period in 2017. The increase was primarily due to an increase in pre-tax earnings, primarily resulting from charges recorded in 2017 related to the Kemper IGCC at Mississippi Power partially offset by the estimated probable loss on Plant Vogtle Units 3 and 4 at Georgia Power recognized in the second quarter 2018, and tax expense related to the Southern Company Gas Dispositions. This increase was partially offset by lower federal income tax expense as well as the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation and the net state income tax benefits arising from the reorganizations of certain of Southern Power's legal entities.

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

Dividends on Preferred and Preference Stock of Subsidiaries

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(6)	(60.0)	$(20)	(62.5)

In the third quarter 2018, dividends on preferred and preference stock of subsidiaries was $4 million compared to $10 million for the corresponding period in 2017. For year-to-date 2018, dividends on preferred and preference stock of subsidiaries was $12 million compared to $32 million for the corresponding period in 2017. These decreases were primarily due to the 2017 redemptions of all outstanding shares of preferred and preference stock at Georgia Power.

See Note 6 the financial statements of Southern Company under "Redeemable Preferred Stock of Subsidiaries" in Item 8 of the Form 10-K for additional information. Also see FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein for information on Mississippi Power's redemption of all of its outstanding preferred stock subsequent to September 30, 2018.

Net Income Attributable to Noncontrolling Interests

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$24	80.0	$23	47.9

Substantially all noncontrolling interests relate to renewable projects at Southern Power. See Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information.

In the third quarter 2018, net income attributable to noncontrolling interests was $54 million compared to $30 million for the corresponding period in 2017. The increase was due to $14 million of other income allocations attributable to a joint-development wind project and $10 million of net income allocations primarily due to the sale of a 33% equity interest in SPSH in 2018, the company holding substantially all of Southern Power's solar facilities.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For year-to-date 2018, net income attributable to noncontrolling interests was $71 million compared to $48 million for the corresponding period in 2017. The increase was primarily due to $21 million of net income allocations due to the sale of a 33% equity interest in SPSH in 2018 and $14 million of other income allocations attributable to a joint-development wind project, partially offset by a reduction of $10 million of net income allocations to other partnership interests, primarily due to the tax equity partnership for Gaskell West 1.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Company's future earnings potential. 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 and limited projected demand growth over the next several years. Plant Vogtle Units 3 and 4 construction and rate recovery and the profitability of Southern Power's competitive wholesale business and successful additional investments in renewable and other energy projects are also major factors.

Future earnings for the electricity and natural gas businesses will be driven primarily by customer growth. 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, future acquisitions and construction of electric generating facilities, the impact of tax credits from renewable 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 May 20, 2018, Southern Company entered into a stock purchase agreement with NextEra Energy to sell all of the capital stock of Gulf Power for an aggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $1.3 billion), subject to (i) customary adjustments for indebtedness and working capital and (ii) reduction by the amount (if any) by which Gulf Power fails to meet a specified capital expenditure target. The completion of the sale is expected to occur in the first quarter 2019 and is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) approval by the FERC and the Federal Communications Commission, (ii) the entry into certain ancillary agreements, including transmission-related agreements and a transition services agreement, among the parties and

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their affiliates, and (iii) other customary closing conditions. See Note (J) to the Condensed Financial Statements under "Southern Company's Sale of Gulf Power" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $365 million, which includes the final working capital adjustment. This disposition resulted in an estimated net loss of $73 million, which includes $39 million of income tax expense, the calculation of which is expected to be finalized in the fourth quarter 2018. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded during the first quarter 2018.

On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion and an additional $40 million for working capital, subject to a final working capital adjustment expected in the fourth quarter 2018. This disposition resulted in an estimated pre-tax gain of approximately $230 million and an after-tax gain of approximately $18 million, the calculations of which are expected to be finalized in the fourth quarter 2018.

On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy for a total cash purchase price of $530 million (less $3 million of indebtedness assumed at closing for customer deposits) and an additional $60 million for cash and other working capital, which includes the final working capital adjustment. This disposition resulted in an estimated pre-tax gain of approximately $121 million and an after-tax gain of approximately $20 million, the calculations of which are expected to be finalized in the fourth quarter 2018.

The after-tax impacts of the Southern Company Gas Dispositions included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

In May 2018, Southern Power completed the sale of a 33% equity interest in SPSH, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, for an aggregate purchase price of approximately $1.2 billion. On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. The transaction is subject to Public Utility Commission of Texas approval and is expected to close by the end of 2018. On November 5, 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of $650 million. The transaction is subject to the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and FERC and state commission approvals and is expected to close mid-2019. See Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information. The ultimate outcome of these matters cannot be determined at this time.

For additional information relating to these issues, see RISK FACTORS in Item 1A 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. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. A

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major portion of these costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, 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 fully 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 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 of Southern Company under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Laws and Regulations

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.

On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.

Coal Combustion Residuals

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" of Southern Company in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).

The EPA published certain amendments to the CCR Rule, which became effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. Specific site impacts are being evaluated by the traditional electric operating companies.

On October 15, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a mandate that broadens the CCR Rule to regulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that the EPA will issue a series of rulemakings to address this court action. The Southern Company system is evaluating the extent of potential impacts on legacy units but anticipates no significant impacts to its ongoing CCR strategies due to this mandate. The ultimate impact of these changes will not be known until the EPA rulemaking and any legal challenges are finalized.

In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related to the CCR Rule. The revised cost estimates were based on information from feasibility studies performed on ash ponds in use

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at plants operated by Alabama Power, including a plant jointly-owned by Mississippi Power. During the second quarter 2018, Alabama Power's management completed its analysis of these studies which indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology. As the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material.

Georgia Power continues to perform engineering studies related to its plans to close the ash ponds at all of its generating plants, including one jointly owned with Gulf Power, in compliance with federal and state CCR rules. Georgia Power also continues to refine its closure strategy and cost estimates for each ash pond and is preparing permit applications as required by the State of Georgia CCR rule. While Georgia Power and Gulf Power believe their recorded liabilities for ash pond closures appropriately reflect their obligations under the current closure strategies they have elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase their ARO liabilities. It is not currently possible to quantify the impacts of any increase related to a change in closure strategies and/or ongoing engineering studies for the current closure strategies, and the timing of future cash outflows is indeterminable at this time; however, the impact on Georgia Power's and Gulf Power's ARO liabilities is expected to be material. As permit applications advance, engineering studies continue, and the timing of individual ash pond closures develops further during the fourth quarter 2018, Georgia Power and Gulf Power will record any necessary changes to their ARO liabilities.

The traditional electric operating companies expect to continue to periodically update their ARO cost estimates, which could increase further, as additional information becomes available. Absent continued recovery of ARO costs through regulated rates, Southern Company's results of operations, cash flows, and financial condition could be materially impacted. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

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

Nuclear Decommissioning

See Note 1 to the financial statements of Southern Company under "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" and "Nuclear Decommissioning" herein for additional information.

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

Georgia Power expects to complete updated decommissioning cost site studies for Plant Hatch and Plant Vogtle Units 1 and 2 in the fourth quarter 2018, which could result in additional changes to Southern Company's ARO liability. The ultimate outcome of these studies cannot be determined at this time.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Southern Company in Item 7 of the Form 10-K for additional information regarding the Clean Power Plan and domestic GHG policies.

On August 31, 2018, the EPA published a proposed Clean Power Plan replacement rule known as the Affordable Clean Energy rule (ACE Rule), which would require states to develop unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of September 30, 2018, the Southern Company system has ownership interests in44 fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to the Southern Company system is currently unknown and will depend on changes

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between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal proceedings.

Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, complete construction of Plant Vogtle Units 3 and 4, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time.

FERC Matters

Market-Based Rate Authority

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Market-Based Rate Authority" of Southern Company in Item 7 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies'and Southern Power's 2014 and 2017 triennial market power analyses.

On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companiesand Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companiesand Southern Power made the compliance filing required by the order. These proceedings are concluded.

Open Access Transmission Tariff

On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companiesclaiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies'open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companiesfiled their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material to Southern Company's results of operations. The ultimate outcome of this matter cannot be determined at this time.

Southern Company Gas

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

The Atlantic Coast Pipeline has experienced challenges to its permits since construction began earlier in 2018 and continues to work with the appropriate agencies to obtain the necessary permits. The PennEast Pipeline continues to work with state and federal agencies to obtain the required permits to begin construction. Any material permitting delays may impact forecasted capital expenditures and in-service dates. The ultimate outcome of these matters cannot be determined at this time.

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Regulatory Matters

Fuel Cost Recovery

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Fuel Cost Recovery" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power – Rate ECR" and "Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery for the traditional electric operating companies.

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. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – 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.

On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. At September 30, 2018, Alabama Power's equity ratio was approximately 47%. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" of Southern Company in Item 7 of the Form 10-K for additional information.

Rate RSE

The approved modifications to Rate RSE became effective June 2018 and are applicable for January 2019 billings and thereafter. The modifications include reducing the top of the allowed weighted common equity return (WCER) range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range.

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

In accordance with an established retail tariff that provides for an interim adjustment to customer billings to recognize the impact of a change in the statutory income tax rate, Alabama Power has returned $151 million through September 30, 2018 and anticipates returning a total of approximately $257 million to retail customers through bill credits by December 31, 2018 as a result of the change in the federal income tax rate under the Tax Reform Legislation.

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Rate ECR

On May 1, 2018, the Alabama PSC approved an increase to Rate ECR from 2.015 cents per KWH to 2.353 cents per KWH effective July 2018 which is expected to result in additional collections of approximately $100 million through December 31, 2018. The approved increase in the Rate ECR factor will have no significant effect on Southern Company's net income, but will increase operating cash flows related to fuel cost recovery in 2018. Absent any further order from the Alabama PSC, in January 2019, the rate will return to the originally authorized 5.910 cents per KWH.

Accounting Order

On May 1, 2018, the Alabama PSC approved an accounting order that authorizes Alabama Power to defer the benefits of federal excess deferred income taxes associated with the Tax Reform Legislation for the year ending December 31, 2018 as a regulatory liability and to use up to $30 million of such deferrals to offset under recovered amounts under Rate ECR. Any remaining amounts will be used for the benefit of customers as determined by the Alabama PSC. As of September 30, 2018, Alabama Power had applied the full $30 million to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 5 to the financial statements of Southern Company under "Federal Tax Reform Legislation" 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 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 (B) to the Condensed Financial Statements under "Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's NCCR tariff. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information regarding Georgia Power's fuel cost recovery.

Rate Plans

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Georgia Power – Rate Plans" of Southern Company in Item 7 of the Form 10-K for additional information regarding Georgia Power's 2013 ARP and the Georgia PSC's 2018 order related to the Tax Reform Legislation.

On April 3, 2018, the Georgia PSC approved a settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation (Georgia Power Tax Reform Settlement Agreement). Pursuant to the Georgia Power Tax Reform Settlement Agreement, to reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power will refund to customers a total of $330 million through bill credits. Georgia Power issued bill credits of approximately $130 million in October 2018 and will issue bill credits of approximately $95 million in June 2019 and $105 million in February 2020. In addition, Georgia Power is deferring as a regulatory liability (i) the revenue equivalent of the tax expense reduction resulting from legislation lowering the Georgia state income tax rate from 6.00% to 5.75% in 2019 and (ii) the entire benefit of approximately $700 million in federal and state excess accumulated deferred income taxes. At September 30, 2018, Georgia Power's related regulatory liability balance totaled $655 million. The amortization of these regulatory liabilities is expected to be addressed in Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. If there is not a base rate case in 2019, customers will receive $185 million in annual bill credits beginning in 2020, with any additional federal and state income tax savings deferred as a regulatory liability, until Georgia Power's next base rate case.

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To address the negative cash flow and credit metric impacts of the Tax Reform Legislation, the Georgia PSC also approved an increase in Georgia Power's retail equity ratio to the lower of (i) Georgia Power's actual common equity weight in its capital structure or (ii) 55%, until Georgia Power's next base rate case. At September 30, 2018, Georgia Power's actual retail common equity ratio (on a 13-month average basis) was approximately 53%. Benefits from reduced federal income tax rates in excess of the amounts refunded to customers will be retained by Georgia Power to cover the carrying costs of the incremental equity in 2018 and 2019.

Storm Damage Recovery

See Note 3 to the financial statements of Southern Company under "Regulatory Matters–Georgia Power– Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.

Georgia Power is accruing$30 millionannually through December 31, 2019, as provided in the 2013 ARP, for incremental operations and maintenance costs of damage from major storms to its transmission and distribution facilities. As ofSeptember 30, 2018, the total balance in Georgia Power's regulatory asset related to storm damage was$311 million. During October 2018, Hurricane Michael caused significant damage to Georgia Power's transmission and distribution facilities. Georgia Power currently estimates the costs of repairing the damage will total approximately$125 million to $150 million, which will be charged to Georgia Power's storm damage reserve or capitalized. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. The ultimate outcome of this matter cannot be determined at this time.

Gulf Power

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

Storm Damage Cost Recovery

On October 10, 2018, Hurricane Michael made landfall on the Gulf Coast of Florida causing substantial damage in Gulf Power's service territory. Gulf Power currently estimates the costs of repairing the damages to its transmission and distribution lines and uninsured facilities will total approximately $350 million to $400 million, which primarily will be charged to Gulf Power's property damage reserve or capitalized. Gulf Power maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generating facilities and other property. At September 30, 2018, Gulf Power had a balance of approximately $48 million in its property damage reserve. In accordance with the settlement agreement approved by the Florida PSC in April 2017 (2017 Gulf Power Rate Case Settlement Agreement), Gulf Power can petition the Florida PSC to seek recovery of the costs associated with Hurricane Michael, along with replenishing the property damage reserve to approximately $40 million. Any recovery from customers would begin, on an interim basis, 60 days following the filing of the cost recovery petition. The ultimate outcome of this matter cannot be determined at this time.

Retail Base Rate Case

As a continuation of the 2017 Gulf Power Rate Case Settlement Agreement, on March 26, 2018, the Florida PSC approved a stipulation and settlement agreement among Gulf Power and three intervenors addressing the retail revenue requirement effects of the Tax Reform Legislation (Gulf Power Tax Reform Settlement Agreement).

The Gulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates implemented April 1, 2018 and also provided for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through a reduced fuel cost recovery rate over the remainder of 2018. Through September 30, 2018, approximately $53 million of this refund has been reflected in customer bills. As a result of the

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Gulf Power Tax Reform Settlement Agreement, the Florida PSC also approved an increase in Gulf Power's maximum equity ratio from 52.5% to 53.5% for all retail regulatory purposes.

As part of the Gulf Power Tax Reform Settlement Agreement, a limited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was initiated on April 30, 2018. On October 30, 2018, the Florida PSC approved a $9.6 million annual reduction in base rate revenues effective January 2019, which concluded this proceeding. Through September 30, 2018, Gulf Power has deferred $7 million of related 2018 tax benefits as a regulatory liability to be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.

Mississippi Power

On February 7, 2018, Mississippi Power submitted its revised 2018 projected PEP filing to the Mississippi PSC, which reflected the impacts of the Tax Reform Legislation, requesting an increase in annual retail revenues of $26 million based on a performance-adjusted ROE of 9.33% and an increased equity ratio of 55%.

On July 27, 2018, Mississippi Power and the Mississippi Public Utilities Staff (MPUS) entered into a settlement agreement with respect to the 2018 PEP filing and all unresolved PEP filings for prior years (PEP Settlement Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement became effective with the first billing cycle of September 2018. The PEP Settlement Agreement provides for an increase of approximately $21.6 million in annual base retail revenues, which excludes certain compensation costs contested by the MPUS, as well as approximately $2 million which was subsequently approved for recovery through a separate Mississippi Power cost rider. Under the PEP Settlement Agreement, Mississippi Power is deferring the contested compensation costs for 2018 and 2019 as a regulatory asset. The Mississippi PSC is currently expected to rule on the appropriate treatment for such costs in connection with Mississippi Power's next base rate case, which is scheduled to be filed in the fourth quarter 2019 (2019 Base Rate Case). The ultimate outcome of this matter cannot be determined at this time.

Pursuant to the PEP Settlement Agreement, Mississippi Power's performance-adjusted allowed ROE is 9.31% and its allowed equity ratio remains at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power retained $44 million of excess accumulated deferred income taxes resulting from the Tax Reform Legislation, which had been proposed to be amortized beginning in 2018, until the conclusion of the 2019 Base Rate Case. Further, Mississippi Power will seek equity contributions sufficient to restore its equity ratio (which was 45% at September 30, 2018) to 50% by December 31, 2018. In the event Mississippi Power's actual average equity ratio for 2018 is more than 1% higher or lower than the 50% target, Mississippi Power will defer the corresponding difference in its revenue requirement as a regulatory asset or liability for resolution in the 2019 Base Rate Case.

Pursuant to the PEP Settlement Agreement, PEP proceedings are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolved all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power recognized revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.

Southern Company Gas

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Southern Company Gas" of Southern Company in Item 7 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information.

On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation.

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The Georgia PSC maintained Atlanta Gas Light's previously authorized earnings band based on a ROE between 10.55% and 10.95% and increased the allowed equity ratio by 4% to an equity ratio of 55% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. Additionally, Atlanta Gas Light is required to file a traditional base rate case on or before June 1, 2019 for rates effective January 1, 2020.

On May 2, 2018, the Illinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately $44 million in annual base rate revenues became effective May 5, 2018. Nicor Gas' previously-authorized capital structure and ROE of 9.8% were not addressed in the rehearing and remain unchanged.

Kemper County Energy Facility

For additional information on the Kemper County energy facility, see Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K.

As the mining permit holder for the Kemper County energy facility, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. Mine reclamation began in the first quarter 2018.

As of September 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the third quarter 2018 and $45 million ($34 million after tax) for year-to-date 2018, primarily resulting from the abandonment and related closure activities 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 to cost up to $20 million pre-tax (excluding salvage, net of dismantlement costs), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $2 million for the remainder of 2018, $8 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.

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

Reserve Margin Plan

On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP), as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costs related to the Kemper County energy facility. Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being thetwo-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adverse impact on customer rates.

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

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its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding 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 3 and 12 to the financial statements of Southern Company under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" and "Southern Power – Construction Projects in Progress," respectively, in Item 8 of the Form 10-K and Note (J) 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 3 to the financial statements of Southern Company under "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 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, VCM reports, and the NCCR tariff.

In 2009, the Georgia PSC certified construction of 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 Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired in July 2017 when Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement. Under the Vogtle Services Agreement, Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement 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

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terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.

In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor.

Cost and Schedule

In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. 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 September 30, 2018(b)	(4.3		)
Remaining estimate to complete(a)	$	4.1

(a) Excludes financing costs expected to be capitalized through AFUDC of approximately $350 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 $3.2 billion, of which $1.8 billion had been incurred through September 30, 2018.

The table above reflects the $0.7 billion increase to the base capital cost forecast reported in the second quarter 2018 and is based on the cost reforecast performed prior to the nineteenth VCM filing, which primarily resulted from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.

Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power did not seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs) in the nineteenth VCM report that was filed with the Georgia PSC on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018, which includes the total increase in the base capital cost forecast and construction contingency estimate.

As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale); or other

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issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule continue to increase significantly through the remainder of 2018 and into 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers 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 resolution of Inspections, Tests, Analyses, and Acceptance Criteria (ITAAC) and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Joint Owner Contracts

In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective August 31, 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.

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

Amendments to the Vogtle Joint Ownership Agreements

In connection with the vote to continue construction, Georgia Power entered into (i) the Vogtle Owner Term Sheet with the other Vogtle Owners and MEAG's wholly-owned subsidiaries MEAG SPVJ, MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners, and (ii) a term sheet (MEAG Term Sheet and, together with the Vogtle Owner Term Sheet, Term Sheets) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 (Project J) under certain circumstances. Pursuant to the Vogtle Owner Term Sheet, the Vogtle Joint Ownership Agreements will be modified as follows: (i) each Vogtle Owner will pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units

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3 and 4 which forms the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million of additional construction costs; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests.

If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion. In this event, Georgia Power will have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Vogtle Owner. If Georgia Power accepts the offer to purchase a portion of another Vogtle Owner's ownership interest in Plant Vogtle Units 3 and 4, the ownership interest(s) to be conveyed from the tendering Vogtle Owner(s) to Georgia Power would be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Vogtle Owner(s) and by Georgia Power as of the commercial operation date of Plant Vogtle Unit 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Vogtle Owner in accordance with the second and third items described in the paragraph above would be treated as payments made by the applicable Vogtle Owner.

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

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

Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain of the above provisions of the Vogtle Owner Term Sheet.

Under the Vogtle Owner Term Sheet, the provisions of the Vogtle Joint Ownership Agreements requiring that Vogtle Owners holding 90% of the ownership interests in Plant Vogtle Units 3 and 4 vote to continue construction following certain adverse events (Project Adverse Events) will be modified. Pursuant to the Vogtle Joint Ownership Agreements and the Vogtle Owner Term Sheet, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain Project Adverse Events occur, including: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Vogtle Owner Term Sheet provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for

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which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule. Under the Vogtle Owner Term Sheet, Georgia Power may cancel the project at any time in its sole discretion.

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

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

Purchase of PTCs During Commercial Operation

In addition, under the terms of the Vogtle Owner Term Sheet, Georgia Power agreed to purchase additional PTCs from OPC, Dalton, MEAG SPVM, MEAG SPVP, and MEAG SPVJ (to the extent any MEAG SPVJ PTC rights remain after any purchases required under the MEAG Term Sheet as described below) at varying purchase prices dependent upon the actual cost to complete construction of Plant Vogtle Units 3 and 4 as compared to the EAC included in the nineteenth VCM report. The purchases will be at the option of the applicable Vogtle Owner and will occur during the month after such PTCs are earned.

Potential Funding to MEAG Project J

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

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

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

Under the terms of the MEAG Term Sheet, Georgia Power may decline to provide any funding in the form of advances, including in the event of a failure to receive any required Georgia PSC or DOE approvals, and cancel the project in lieu of providing such funding.

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

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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. As of September 30, 2018, Georgia Power had recovered approximately $1.8 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. Georgia Power expects to file on November 9, 2018 to increase the NCCR tariff by approximately $90 million annually, effective January 1, 2019, pending Georgia PSC approval.

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) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying 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 $25 million in 2017 and are estimated to have negative earnings impacts of approximately $100 million in 2018 and an aggregate of $680 million from 2019 to 2022.

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In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. On March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's final decision and denial of Georgia Watch's motion for reconsideration. Georgia Power believes the two appeals have no merit; however, an adverse outcome in either 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.

The Georgia PSC has approved eighteen VCM reports covering the periods through December 31, 2017, including total construction capital costs incurred through that date of $4.9 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds). On August 31, 2018, Georgia Power filed its nineteenth VCM report with the Georgia PSC, which requested approval of $578 million of construction capital costs incurred from January 1, 2018 through June 30, 2018.

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

See RISK FACTORS of Southern Company in Item 1A herein and 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

As of September 30, 2018, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In September 2018, the DOE extended the conditional commitment to March 31, 2019. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements of Southern Company under "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 (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and conditions to borrowing.

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

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.

Southern Power

In April 2018, Southern Power completed the final stage of a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization resulted in net state tax benefits related to certain changes in apportionment rates totaling approximately $54 million, which were recorded in the first half of 2018.

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In September 2018, Southern Power also completed a legal reorganization of eight operating wind facilities under a new holding company, SP Wind, which resulted in net state tax benefits totaling approximately $11 million related to certain changes in apportionment rates.

Other Matters

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

The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) 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 Note (B) 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.

On October 2, 2018, the Mississippi PSC approved executed agreements between Mississippi Power and its largest retail customer, Chevron, for Mississippi Power to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The new agreements are not expected to have a material impact on earnings.

Litigation

In 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled to include, among other things, Southern Company as a defendant. The individual plaintiff alleged that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches unjustly enriched Mississippi Power and Southern Company. The plaintiffs sought unspecified actual damages and punitive damages; asked the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; asked the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and sought attorney's fees, costs, and interest. The plaintiffs also sought an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. In June 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. In July 2017, the plaintiffs filed notice of an appeal. On July 13, 2018, Mississippi Power and Southern Company reached a settlement agreement with the plaintiffs and the plaintiffs' appeal was dismissed with prejudice. The settlement had no material impact on Southern Company's financial statements.

In January 2017, a putative securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In June 2017, the plaintiffs filed an amended

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complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. In July 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition in September 2017. On March 29, 2018, the U.S. District Court for the Northern District of Georgia, Atlanta Division, issued an order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers of Southern Company and Mississippi Power and dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. On April 26, 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. On August 10, 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal.

In February 2017, Jean Vineyard filed a shareholder derivative lawsuit and, in May 2017, Judy Mesirov filed a shareholder derivative lawsuit, each in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. In August 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On April 25, 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.

In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On May 4, 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.

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

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

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Investments in Leveraged Leases

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters – Investments in Leveraged Leases" of Southern Company in Item 7 and Note 1 to the financial statements of Southern Company under "Leveraged Leases" in Item 8 of the Form 10-K for additional information regarding the leveraged lease agreements of a subsidiary of Southern Company Holdings Inc. (Southern Holdings) and concerns about the financial and operational performance of one of the lessees and the associated generation assets.

The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. As a result of operational improvements in the first half of 2018, the June 2018 lease payment was paid in full and the December 2018 lease payment is currently expected to be paid in full. However, operational issues and the resulting cash liquidity challenges persist and significant concerns continue regarding the lessee's ability to make the remaining semi-annual lease payments. These operational challenges may also impact the expected residual value of the assets at the end of the lease term in 2047. If any future lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders would represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable, which would result in a reduction in net income of approximately $86 million after tax based on the lease receivable balance as of September 30, 2018. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired as of September 30, 2018. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments. The ultimate outcome of this matter cannot be determined at this time.

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 Note 1 to the financial statements of Southern Company 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 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.

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

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

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In its order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

In the second quarter 2018, Georgia Power revised its base cost forecast and estimated contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for a total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds). Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC has stated the $7.3 billion estimate included in the seventeenth VCM proceeding does not represent a cost cap, Georgia Power did not seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast in the nineteenth VCM report filed with the Georgia PSC on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs included in the revised construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018.

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

As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule continue to increase significantly through the remainder of 2018 and into 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers 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 resolution of ITAAC and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

The ultimate outcome of these matters cannot be determined at this time. Any extension of the in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4 is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Given the significant complexity involved in estimating the future costs to complete construction and start-up of Plant Vogtle Units 3 and 4 and the significant management judgment necessary to assess the related uncertainties surrounding future rate recovery of any projected cost increases, as well as the potential impact on Southern Company's results of operations and cash flows, Southern Company considers these items to be critical accounting

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estimates. See Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information.

Recently Issued Accounting Standards

See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Company in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company's recently adopted accounting standards.

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

Southern Company has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Southern Company expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Southern Company expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Southern Company also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.

The Southern Company system is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. The Southern Company system has substantially completed its lease inventory and determined its most significant leases involve PPAs, real estate, and communication towers where certain of Southern Company's subsidiaries are the lessee and PPAs where certain of Southern Company's subsidiaries are the lessor. While Southern Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in recording lease liabilities and right-of-use assets on Southern Company's balance sheet each totaling approximately $2.1 billion, with no material impact on Southern Company's statement of income.

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 September 30, 2018. 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 $5.6 billion for the first nine months of 2018, an increase of $0.3 billion from the corresponding period in 2017. The increase in net cash provided from operating activities was primarily due to increased fuel cost recovery and the timing of vendor payments. Net cash used for investing activities totaled $3.5 billion for the first nine months of 2018 primarily due to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric

50

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

generation, transmission, and distribution facilities and capital expenditures for Southern Company Gas' infrastructure replacement programs, partially offset by proceeds from the Southern Company Gas Dispositions. Net cash used for financing activities totaled $2.3 billion for the first nine months of 2018 primarily due to net redemptions and repurchases of long-term debt, common stock dividend payments, and a decrease in commercial paper borrowings, partially offset by net issuances of short-term bank debt, proceeds from Southern Power's sale of a 33% equity interest in a limited partnership indirectly owning substantially all of its solar facilities, and the issuance of common stock. 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 nine months of 2018 include the reclassification of $5.1 billion and $3.2 billion in total assets and liabilities held for sale, respectively, primarily associated with Gulf Power, as well as decreases of $2.8 billion and $0.4 billion in total assets and liabilities, respectively, associated with the Southern Company Gas Dispositions. See Note (J) to the Condensed Financial Statements under "Assets Held for Sale" and "Southern Company Gas" herein for additional information. After adjusting for these changes, other significant balance sheet changes include an increase of $4.0 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, as well as an increase in AROs at Alabama Power, partially offset by the second quarter 2018 charge related to the construction of Plant Vogtle Units 3 and 4; a decrease of $2.6 billion in long-term debt (including amounts due within one year) resulting from the repayment of long-term debt; an increase of $1.8 billion in noncontrolling interests primarily related to Southern Power's sale of a 33% equity interest in a limited partnership indirectly owning substantially all of its solar facilities; and an increase of $1.5 billion in ARO liabilities primarily related to revised estimates for ash pond closure costs at Alabama Power to comply with the CCR Rule. See Notes (A), (B), (F), and (J) to the Condensed Financial Statements under "Asset Retirement Obligations," "Nuclear Construction," "Financing Activities," and "Southern Power – Sale of Solar Facility Interests," respectively, herein for additional information.

At the end of the third quarter 2018, the market price of Southern Company's common stock was $43.60 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $24.18 per share, representing a market-to-book ratio of 180%, compared to $48.09, $23.99, and 201%, respectively, at the end of 2017. Southern Company's common stock dividend for the third quarter 2018 was $0.60 per share compared to $0.58 per share in the third quarter 2017.

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. Subsequent to September 30, 2018, Mississippi Power completed the redemption of $30 million aggregate principal amount of its Series G 5.40% Senior Notes due July 1, 2035 and $125 million aggregate principal amount of its Series 2009A 5.55% Senior Notes due March 1, 2019, Alabama Power purchased and held $120 million of pollution control revenue bonds, and Southern Company Gas Capital repaid at maturity $155 million aggregate principal amount of 3.50% Series B Senior Notes. An additional $2.6 billion will be required through September 30, 2019 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

The Southern Company system's construction program is currently estimated to total approximately $8.8 billion for 2018, $8.2 billion for 2019, $7.2 billion for 2020, $7.0 billion for 2021, and $6.7 billion for 2022. These amounts include expenditures of approximately $1.4 billion, $1.4 billion, $0.9 billion, $1.0 billion, and $0.6 billion for the construction of Plant Vogtle Units 3 and 4 in 2018, 2019, 2020, 2021, and 2022, respectively, and an average of approximately $0.5 billion per year for 2018 through 2022 for Southern Power's planned expenditures for plant acquisitions and placeholder growth, as revised subsequent to Tax Reform Legislation. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel, capital expenditures covered under LTSAs, and costs, which are immaterial to Southern Company, relating to assets divested during 2018 and held for sale at September 30, 2018. Estimated capital expenditures to comply with environmental laws and

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regulations included in these amounts are $1.1 billion, $0.3 billion, $0.4 billion, $0.5 billion, and $0.5 billion for 2018, 2019, 2020, 2021, and 2022, respectively. These estimated expenditures do not include any potential compliance costs associated with pending regulation of CO₂ emissions from fossil fuel-fired electric generating units.

The traditional electric operating companies also anticipate costs associated with closure and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in Southern Company's ARO liabilities. These costs, which are expected to change as the Southern Company system continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are currently estimated to be approximately $0.3 billion, $0.4 billion, $0.5 billion, $0.6 billion, and $0.5 billion for 2018, 2019, 2020, 2021, and 2022, respectively. For information regarding expected changes to these cost estimates during the fourth quarter 2018, see FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein. Also see Note 1 to the financial statements of Southern Company under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information on AROs.

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 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K and Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions.

The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only recently began initial operation in the global nuclear industry at 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 and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance. See Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "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. Southern Company also plans to utilize the proceeds from the disposition of Gulf Power when completed for future capital needs. 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 2018, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. 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.

In addition, in 2014, Georgia Power entered into the Loan Guarantee Agreement with the DOE, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. As of September 30, 2018, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. In July 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.

In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on March 31, 2019, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements of Southern Company under "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 regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

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 September 30, 2018, Southern Company's current liabilities exceeded current assets by $3.6 billion due to long-term debt that is due within one year of $3.0 billion (including approximately $1.3 billion at the parent company, $0.3 billion at Alabama Power, $0.5 billion at Georgia Power, $0.2 billion at Mississippi Power, and $0.5 billion at Southern Company Gas) and notes payable of $2.6 billion (including approximately $2.0 billion at the parent company, $0.1 billion at Georgia Power, $0.1 billion at Gulf Power, $0.2 billion at Southern Power, and $0.1 billion at Southern Company Gas). 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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At September 30, 2018, Southern Company and its subsidiaries had approximately $1.8 billion of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2018 were as follows:

	Expires												Executable Term Loans		Expires Within One Year
Company	2018		2019		2020		2022		Total		Unused		One Year		Term Out		No Term Out
	(in millions)
Southern Company(a)	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—	$	—	$	—
Alabama Power	—		33		500		800		1,333		1,333		—		—		33
Georgia Power	—		—		—		1,750		1,750		1,736		—		—		—
Gulf Power	20		25		235		—		280		280		45		45		—
Mississippi Power	—		100		—		—		100		100		—		—		—
Southern Power Company(b)	—		—		—		750		750		728		—		—		—
Southern Company Gas(c)	—		—		—		1,900		1,900		1,895		—		—		—
Other	—		30		—		—		30		30		—		—		30
Southern Company Consolidated	$	20	$	188	$	735	$	7,200	$	8,143	$	8,101	$	45	$	45	$	63

(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 2019, of which $22 million remains unused at September 30, 2018.

(c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.

See Note 6 to the financial statements of Southern Company 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 Southern Company, Alabama Power, and Southern Power Company contain covenants that limit debt levels and contain cross-acceleration or cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2018, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were in compliance with all such covenants. All but $40 million of the bank credit arrangements do not contain material adverse change clauses at the time of borrowings.

Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of September 30, 2018 was approximately $1.5 billion. In addition, at September 30, 2018, the traditional electric operating companies had approximately $573 million of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2018, Alabama Power purchased and held approximately $120 million of its outstanding pollution control revenue bonds required to be remarketed.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Company, the traditional electric operating companies (other than Mississippi Power), Southern Power Company, Southern Company Gas, and Nicor Gas 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.

Details of short-term borrowings were as follows:

	Short-term Debt at September 30, 2018				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	$	611	2.5	%	$	1,323	2.4	%	$	3,008
Short-term bank debt	1,953		2.9	%	1,790		3.0	%	2,003
Total	$	2,564	2.8	%	$	3,113	2.7	%

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2018.

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 September 30, 2018, Southern Company and its subsidiaries did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and/or Baa2 or below. These contracts are for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and construction of new generation at Plant Vogtle Units 3 and 4.

The maximum potential collateral requirements under these contracts at September 30, 2018 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	38
At BBB- and/or Baa3	$	578
At BB+ and/or Ba1(*)	$	2,120

(*) Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets, and would be likely to impact the cost at which they do so.

On February 26, 2018, Moody's revised its rating outlook for Mississippi Power from stable to positive. On August 8, 2018, Moody's upgraded Mississippi Power's senior unsecured rating to Baa3 from Ba1 and maintained the positive rating outlook.

On February 28, 2018, Fitch removed Mississippi Power from rating watch negative and revised its rating outlook from stable to positive.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Also on February 28, 2018, Fitch downgraded the senior unsecured long-term debt rating of Southern Company to BBB+ from A- with a stable outlook and of Georgia Power to A from A+ with a negative outlook. On August 9, 2018, Fitch downgraded the senior unsecured long-term debt rating of Georgia Power to A- from A.

On March 14, 2018, S&P upgraded the senior unsecured long-term debt rating of Mississippi Power to A- from BBB+. The outlook remained negative.

On May 21, 2018, S&P revised its rating outlook for Gulf Power from negative to stable.

On August 8, 2018, Moody's downgraded the senior unsecured debt rating of Georgia Power to Baa1 from A3.

On September 28, 2018, Moody's revised its rating outlooks for Southern Company, Alabama Power, and Georgia Power from negative to stable.

Also on September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and its subsidiaries (excluding Gulf Power and Mississippi Power).

As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries may be negatively impacted. Southern Company and most of its regulated subsidiaries have taken actions to mitigate the resulting impacts, which, among other alternatives, include adjusting capital structure. Absent actions by Southern Company and its subsidiaries that fully mitigate the impacts, the credit ratings of Southern Company and certain of its subsidiaries could be negatively affected. See Note 3 to the financial statements of Southern Company 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 related to the Tax Reform Legislation, including approvals of capital structure adjustments for Alabama Power, Georgia Power, Gulf Power, and Atlanta Gas Light by their respective state PSCs, which are expected to help mitigate the potential adverse impacts to certain of their credit metrics.

Financing Activities

During the first nine months of 2018, Southern Company issued approximately 9.2 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $338 million.

In addition, during the third quarter 2018, Southern Company issued a total of approximately 12.1 million shares of common stock through at-the-market issuances pursuant to sales agency agreements related to Southern Company's continuous equity offering program and received cash proceeds of approximately $540 million, net of approximately $5 million in commissions. Subsequent to September 30, 2018, Southern Company issued an additional approximately 2.5 million shares of common stock through at-the-market issuances and received cash proceeds of approximately $107 million, net of approximately $1 million in commissions.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2018:

Company	Senior Note Issuances		Senior Note Maturities, Redemptions, and Repurchases		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Issuances		Other Long-Term Debt Redemptions and Maturities(a)
	(in millions)
Southern Company(b)	$	750	$	1,000	$	—	$	—	$	—
Alabama Power	500		—		—		—		—
Georgia Power	—		1,000		469		—		107
Mississippi Power	600		—		43		—		900
Southern Power	—		350		—		—		420
Southern Company Gas	—		—		200		100		—
Other	—		—		—		—		10
Elimination(c)	—		—		—		—		(1		)
Southern Company Consolidated	$	1,850	$	2,350	$	712	$	100	$	1,436

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

(b) Represents the Southern Company parent entity.

(c) Represents reductions in affiliate capital lease obligations at Georgia Power, which are eliminated in Southern Company's Consolidated Financial Statements.

Except as otherwise described herein, Southern Company and its subsidiaries used the proceeds of debt issuances for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital. The subsidiaries also used the proceeds for their construction programs.

In March 2018, Southern Company entered into a $900 million short-term floating rate bank loan bearing interest based on one-month LIBOR, which was repaid in August 2018.

In April 2018, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, bearing interest at a rate agreed upon by Southern Company and the bank from time to time and payable on no less than 30 days' demand by the bank.

In June 2018, Southern Company repaid at maturity two $100 million short-term floating rate bank term loans.

In August 2018, Southern Company issued $750 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due February 14, 2020 bearing interest based on three-month LIBOR, entered into a $1.5 billion short-term floating rate bank loan bearing interest based on one-month LIBOR, and repaid $250 million borrowed in August 2017 pursuant to a short-term uncommitted bank credit arrangement.

In the third quarter 2018, Southern Company repaid at maturity $500 million aggregate principal amount of 1.55% Senior Notes and $500 million aggregate principal amount of Series 2013A 2.45% Senior Notes.

Subsequent to September 30, 2018, Alabama Power purchased and held $120 million aggregate principal amount of The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008. These bonds may be remarketed to the public in the future.

In January 2018, Georgia Power repaid its outstanding $150 million short-term floating rate bank loan due May 31, 2018.

In May 2018, through cash tender offers, Georgia Power repurchased and retired $89 million of the $250 million aggregate principal amount outstanding of its Series 2007A 5.65% Senior Notes due March 1, 2037, $326 million of

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

the $500 million aggregate principal amount outstanding of its Series 2009A 5.95% Senior Notes due February 1, 2039, and $335 million of the $600 million aggregate principal amount outstanding of its Series 2010B 5.40% Senior Notes due June 1, 2040, for an aggregate purchase price, excluding accrued and unpaid interest, of $902 million.

In March 2018, Mississippi Power entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $100 million was repaid in the third quarter 2018. The proceeds of this loan, together with the proceeds of Mississippi Power's $600 million senior notes issuances, were used to repay Mississippi Power's $900 million unsecured floating rate term loan.

Subsequent to September 30, 2018, Mississippi Power completed the redemption of all 334,210 outstanding shares of its preferred stock (as well as related depositary shares), with an aggregate par value of approximately $33.4 million; all $30 million aggregate principal amount outstanding of its Series G 5.40% Senior Notes due July 1, 2035; and all $125 million aggregate principal amount outstanding of its Series 2009A 5.55% Senior Notes due March 1, 2019.

In May 2018, Southern Power entered into two short-term floating rate bank loans, each for an aggregate principal amount of $100 million, which bear interest based on one-month LIBOR.

During the nine months ended September 30, 2018, Southern Power received approximately $148 million of third-party tax equity related to certain of its renewable facilities. See Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information.

Prior to its sale, in the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of gas facility revenue bonds to be redeemed.

In May 2018, Southern Company Gas Capital borrowed $95 million pursuant to a short-term uncommitted bank credit arrangement, guaranteed by Southern Company Gas, bearing interest at a rate agreed upon by Southern Company Gas Capital and the bank from time to time and payable on no less than 30 days' demand by the bank. The proceeds of the loan were used to repay short-term debt. In July 2018, Southern Company Gas Capital repaid this loan.

In July 2018, Nicor Gas agreed to issue $300 million aggregate principal amount of first mortgage bonds in a private placement, $100 million of which was issued in August 2018 and $200 million of which was issued in November 2018.

Subsequent to September 30, 2018, Southern Company Gas Capital repaid at maturity $155 million aggregate principal amount of 3.50% Series B Senior Notes.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company 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.

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PART I

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

During the nine months ended September 30, 2018, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Gulf 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 of each registrant under "Financial Instruments," Note 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 10 to the financial statements of Gulf Power, Mississippi Power, and Southern Company Gas, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also see Note (D) and Note (I) 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, Gulf 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, Gulf 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 third quarter 2018 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting.

59

ALABAMA POWER COMPANY

60

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,584		$	1,595		$	4,208		$	4,155
Wholesale revenues, non-affiliates	74			77			213			210
Wholesale revenues, affiliates	14			18			96			83
Other revenues	68			50			199			158
Total operating revenues	1,740			1,740			4,716			4,606
Operating Expenses:
Fuel	356			343			1,028			944
Purchased power, non-affiliates	64			57			176			132
Purchased power, affiliates	69			55			149			117
Other operations and maintenance	401			406			1,191			1,177
Depreciation and amortization	192			185			570			549
Taxes other than income taxes	97			93			289			284
Total operating expenses	1,179			1,139			3,403			3,203
Operating Income	561			601			1,313			1,403
Other Income and (Expense):
Allowance for equity funds used during construction	16			11			43			27
Interest expense, net of amounts capitalized	(82		)	(76		)	(240		)	(229		)
Other income (expense), net	9			10			24			35
Total other income and (expense)	(57		)	(55		)	(173		)	(167		)
Earnings Before Income Taxes	504			546			1,140			1,236
Income taxes	127			216			272			493
Net Income	377			330			868			743
Dividends on Preferred and Preference Stock	4			5			11			14
Net Income After Dividends on Preferred and Preference Stock	$	373		$	325		$	857		$	729

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2018		2017		2018		2017
	(in millions)				(in millions)
Net Income	$	377	$	330	$	868	$	743
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $-, $1, $1, and $2, respectively	1		1		3		3
Total other comprehensive income (loss)	1		1		3		3
Comprehensive Income	$	378	$	331	$	871	$	746

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

61

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2018			2017
	(in millions)
Operating Activities:
Net income	$	868		$	743
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	683			666
Deferred income taxes	104			260
Allowance for equity funds used during construction	(43		)	(27		)
Settlement of asset retirement obligations	(31		)	(20		)
Other, net	(6		)	59
Changes in certain current assets and liabilities —
-Receivables	(207		)	(163		)
-Prepayments	(26		)	(28		)
-Materials and supplies	(69		)	(29		)
-Other current assets	66			33
-Accounts payable	(194		)	(125		)
-Accrued taxes	225			159
-Accrued compensation	(41		)	(48		)
-Retail fuel cost over recovery	—			(76		)
-Other current liabilities	60			7
Net cash provided from operating activities	1,389			1,411
Investing Activities:
Property additions	(1,529		)	(1,211		)
Nuclear decommissioning trust fund purchases	(207		)	(174		)
Nuclear decommissioning trust fund sales	207			174
Cost of removal, net of salvage	(78		)	(82		)
Change in construction payables	30			105
Other investing activities	(23		)	(29		)
Net cash used for investing activities	(1,600		)	(1,217		)
Financing Activities:
Proceeds —
Senior notes	500			550
Capital contributions from parent company	495			337
Preferred stock	—			250
Redemptions —
Senior notes	—			(200		)
Pollution control revenue bonds	—			(36		)
Payment of common stock dividends	(602		)	(536		)
Other financing activities	(24		)	(26		)
Net cash provided from financing activities	369			339
Net Change in Cash, Cash Equivalents, and Restricted Cash	158			533
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	544			420
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	702		$	953
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $15 and $10 capitalized for 2018 and 2017, respectively)	$	220		$	217
Income taxes, net	30			146
Noncash transactions — Accrued property additions at end of period	275			189

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

62

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2018			At December 31, 2017
	(in millions)
Current Assets:
Cash and cash equivalents	$	702		$	544
Receivables —
Customer accounts receivable	455			355
Unbilled revenues	159			162
Under recovered regulatory clause revenues	48			—
Affiliated	68			43
Other accounts and notes receivable	54			55
Accumulated provision for uncollectible accounts	(9		)	(9		)
Fossil fuel stock	117			184
Materials and supplies	536			458
Prepaid expenses	59			85
Other regulatory assets, current	141			124
Other current assets	8			5
Total current assets	2,338			2,006
Property, Plant, and Equipment:
In service	29,568			27,326
Less: Accumulated provision for depreciation	9,932			9,563
Plant in service, net of depreciation	19,636			17,763
Nuclear fuel, at amortized cost	316			339
Construction work in progress	1,457			908
Total property, plant, and equipment	21,409			19,010
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	63			67
Nuclear decommissioning trusts, at fair value	938			903
Miscellaneous property and investments	127			124
Total other property and investments	1,128			1,094
Deferred Charges and Other Assets:
Deferred charges related to income taxes	236			239
Deferred under recovered regulatory clause revenues	88			54
Other regulatory assets, deferred	1,209			1,272
Other deferred charges and assets	202			189
Total deferred charges and other assets	1,735			1,754
Total Assets	$	26,610		$	23,864

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

63

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2018			At December 31, 2017
	(in millions)
Current Liabilities:
Securities due within one year	$	321		$	—
Accounts payable —
Affiliated	341			327
Other	425			585
Customer deposits	96			92
Accrued taxes —
Accrued income taxes	97			9
Other accrued taxes	132			45
Accrued interest	81			77
Accrued compensation	169			205
Asset retirement obligations, current	111			7
Other regulatory liabilities, current	57			1
Other current liabilities	46			52
Total current liabilities	1,876			1,400
Long-term Debt	7,803			7,628
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	2,882			2,760
Deferred credits related to income taxes	2,051			2,082
Accumulated deferred ITCs	107			112
Employee benefit obligations	283			304
Asset retirement obligations	3,090			1,702
Other cost of removal obligations	542			609
Other regulatory liabilities, deferred	52			84
Other deferred credits and liabilities	48			63
Total deferred credits and other liabilities	9,055			7,716
Total Liabilities	18,734			16,744
Redeemable Preferred Stock	291			291
Common Stockholder's Equity:
Common stock, par value $40 per share —
Authorized — 40,000,000 shares
Outstanding — 30,537,500 shares	1,222			1,222
Paid-in capital	3,490			2,986
Retained earnings	2,902			2,647
Accumulated other comprehensive loss	(29		)	(26		)
Total common stockholder's equity	7,585			6,829
Total Liabilities and Stockholder's Equity	$	26,610		$	23,864

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

64

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2018 vs. THIRD QUARTER 2017

AND

YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017

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, reliability, fuel, capital expenditures, and restoration following major storms. Alabama Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future. On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the retail rate impact and the growing pressure on its credit quality resulting from the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K for additional information on Alabama Power's established retail tariff.

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

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$48	14.8	$128	17.6

Alabama Power's net income after dividends on preferred and preference stock for the third quarter 2018 was $373 million compared to $325 million for the corresponding period in 2017. Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2018 was $857 million compared to $729 million for the corresponding period in 2017. These increases were primarily related to an increase in retail revenues associated with colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 in Alabama Power's service territory compared to the corresponding periods in 2017 and a decrease in income tax expense, partially offset by customer bill credits related to the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K for additional information.

65

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(11)	(0.7)	$53	1.3

In the third quarter 2018, retail revenues were $1.58 billion compared to $1.60 billion for the corresponding period in 2017. For year-to-date 2018, retail revenues were $4.21 billion compared to $4.16 billion for the corresponding period in 2017.

Details of the changes in retail revenues were as follows:

	Third Quarter 2018					Year-to-Date 2018
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	1,595				$	4,155
Estimated change resulting from –
Rates and pricing	(87		)	(5.5	)	(195		)	(4.7	)
Sales decline	(2		)	(0.1	)	(8		)	(0.1	)
Weather	37			2.3		130			3.1
Fuel and other cost recovery	41			2.6		126			3.0
Retail – current year	$	1,584		(0.7	)%	$	4,208		1.3	%

Revenues associated with changes in rates and pricing decreased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to customer bill credits related to the Tax Reform Legislation. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Alabama Power" herein and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.

Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017. Weather-adjusted commercial KWH sales decreased 1.1% and 1.4% for the third quarter and year-to-date 2018, respectively, and weather-adjusted residential KWH sales decreased 0.3% and 0.5% for the third quarter and year-to-date 2018, respectively, when compared to the corresponding periods in 2017 primarily due to lower customer usage related to energy efficiency. Industrial KWH sales increased 1.3% and 2.4% for the third quarter and year-to-date 2018, respectively, when compared to the corresponding periods in 2017 as a result of an increase in demand resulting from changes in production levels primarily in the primary metals sector, largely due to strong domestic demand for steel and aluminum, and in the pipelines sector, partially offset by a decrease in demand in the paper and chemicals sectors, primarily due to customer maintenance outages and on-site cogeneration.

Revenues resulting from changes in weather increased in the third quarter and year-to-date 2018 due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 in Alabama Power's service territory compared to the corresponding periods in 2017. For the third quarter 2018, the resulting increases were 3.9% and 2.2% for residential and commercial sales revenues, respectively. For year-to-date 2018, the resulting increases were 5.7% and 2.3% for residential and commercial sales revenues, respectively.

Fuel and other cost recovery revenues increased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to increases in KWH 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 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.

66

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Affiliates

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(4)	(22.2)	$13	15.7

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.

For year-to-date 2018, wholesale revenues from sales to affiliates were $96 million compared to $83 million for the corresponding period in 2017. The increase was primarily due to a 12% increase in the price of energy and a 3% increase in KWH sales as a result of increased demand due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017.

Other Revenues

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$18	36.0	$41	25.9

In the third quarter 2018, other revenues were $68 million compared to $50 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $199 million compared to $158 million for the corresponding period in 2017. These increases were primarily due to revenues related to unregulated sales of products and services that were reclassified as other revenues as a result of the adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). In prior periods, these revenues were included in other income (expense), net. See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's adoption of ASC 606. The year-to-date 2018 increase was partially offset by decreases in open access transmission tariff revenues primarily due to expected declines in customers' needs and a lower rate related to the Tax Reform Legislation.

Fuel and Purchased Power Expenses

	Third Quarter 2018 vs. Third Quarter 2017			Year-to-Date 2018 vs. Year-to-Date 2017
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	13	3.8	$	84	8.9
Purchased power – non-affiliates	7		12.3	44		33.3
Purchased power – affiliates	14		25.5	32		27.4
Total fuel and purchased power expenses	$	34		$	160

In the third quarter 2018, fuel and purchased power expenses were $489 million compared to $455 million for the corresponding period in 2017. The increase was primarily due to a $23 million increase related to the volume of KWHs generated and purchased and a $16 million increase related to the average cost of fuel, partially offset by a $5 million decrease in the average cost of purchased power.

For year-to-date 2018, fuel and purchased power expenses were $1.35 billion compared to $1.19 billion for the corresponding period in 2017. The increase was primarily due to a $98 million increase related to the volume of KWHs generated and purchased and a $32 million increase related to the average cost of fuel.

67

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In addition, fuel expense increased $30 million 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. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Accounting Order" herein for additional information.

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 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – 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:

	Third Quarter 2018	Third Quarter 2017	Year-to-Date 2018	Year-to-Date 2017
Total generation (in billions of KWHs)	16	16	47	46
Total purchased power (in billions of KWHs)	3	2	6	5
Sources of generation (percent) —
Coal	54	52	52	49
Nuclear	24	24	22	25
Gas	18	19	19	20
Hydro	4	5	7	6
Cost of fuel, generated (in cents per net KWH)(a)—
Coal	2.74	2.61	2.74	2.61
Nuclear	0.78	0.75	0.77	0.75
Gas	2.80	2.72	2.72	2.74
Average cost of fuel, generated (in cents per net KWH)(a)(b)	2.27	2.17	2.27	2.15
Average cost of purchased power (in cents per net KWH)(c)	5.43	5.65	5.59	5.57

(a) Cost of fuel, generated and average cost of fuel, generated excludes a $30 million adjustment for year-to-date 2018 associated with the Alabama PSC accounting order related to excess deferred income taxes.

(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 third quarter 2018, fuel expense was $356 million compared to $343 million for the corresponding period in 2017. The increase was primarily due to a 16.6% decrease in the volume of KWHs generated by hydro facilities due to lower rainfall, a 5.0% increase in the average cost of coal per KWH generated, a 4.0% increase in the average cost of nuclear fuel per KWH generated, and a 3.9% decrease in the volume of KWHs generated by nuclear facilities due to the timing of outages. In addition, the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, increased 2.9% and the volume of KWHs generated by coal increased 2.0%. These increases were partially offset by an 8.4% decrease in the volume of KWHs generated by natural gas.

For year-to-date 2018, fuel expense was $1.03 billion compared to $944 million for the corresponding period in 2017. The increase was primarily due to a 10.8% decrease in the volume of KWHs generated by nuclear facilities due to outages, a 6.9% increase in the volume of KWHs generated by coal, and a 5.0% increase in the average cost of coal per KWH generated. These increases were partially offset by an 11.7% increase in the volume of KWHs generated by hydro facilities due to the timing of rainfall and a 4.1% decrease in the volume of KWHs generated by natural gas.

68

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In addition, fuel expense increased $30 million 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. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Accounting Order" herein for additional information.

Purchased Power – Non-Affiliates

In the third quarter 2018, purchased power expense from non-affiliates was $64 million compared to $57 million for the corresponding period in 2017. The increase was primarily related to a 14.8% increase in the amount of energy purchased due to warmer weather in the third quarter 2018 compared to the corresponding period in 2017.

For year-to-date 2018, purchased power expense from non-affiliates was $176 million compared to $132 million for the corresponding period in 2017. The increase was primarily related to a 24.3% increase in the amount of energy purchased and a 6.7% increase in the average cost of purchased power per KWH due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017.

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 third quarter 2018, purchased power expense from affiliates was $69 million compared to $55 million for the corresponding period in 2017. The increase was primarily related to a 28% increase in the amount of energy purchased due to warmer weather in the third quarter 2018 compared to the corresponding period in 2017.

For year-to-date 2018, purchased power expense from affiliates was $149 million compared to $117 million for the corresponding period in 2017. The increase was primarily related to a 35% increase in the amount of energy purchased as a result of colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017.

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

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(5)	(1.2)	$14	1.2

For year-to-date 2018, other operations and maintenance expenses were $1.19 billion compared to $1.18 billion for the corresponding period in 2017. The increase was primarily due to $33 million of expenses from unregulated sales of products and services that were reclassified as other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. In addition, distribution costs increased $29 million primarily due to additional line maintenance. These increases were partially offset by a $23 million decrease in steam generation costs primarily due to the timing of outages, an $8 million decrease in employee benefits as a result of amounts capitalized in connection with an increase in construction projects, a $7 million decrease in nuclear generation costs primarily due to the timing of plant improvement projects, and a $6 million decrease in property insurance primarily due to the receipt of refunds.

See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's adoption of ASC 606.

69

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Depreciation and Amortization

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$7	3.8	$21	3.8

In the third quarter 2018, depreciation and amortization was $192 million compared to $185 million for the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $570 million compared to $549 million for the corresponding period in 2017. These increases were primarily due to additional plant in service related to steam generation, transmission, and distribution assets. See Note 1 to the financial statements of Alabama Power under "Depreciation and Amortization" in Item 8 of the Form 10-K for additional information.

Allowance for Equity Funds Used During Construction

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$5	45.5	$16	59.3

In the third quarter 2018, AFUDC equity was $16 million compared to $11 million for the corresponding period in 2017. For year-to-date 2018, AFUDC equity was $43 million compared to $27 million for the corresponding period in 2017. These increases were primarily due to an increase in capital expenditures related to environmental and transmission projects.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$6	7.9	$11	4.8

In the third quarter 2018, interest expense, net of amounts capitalized was $82 million compared to $76 million for the corresponding period in 2017. For year-to-date 2018, interest expense, net of amounts capitalized was $240 million compared to $229 million for the corresponding period in 2017. These increases were primarily due to an increase in the average debt outstanding and higher interest rates, partially offset by an increase in the amounts capitalized.

Other Income (Expense), Net

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(10.0)	$(11)	(31.4)

For year-to-date 2018, other income (expense), net was $24 million compared to $35 million for the corresponding period in 2017. This decrease was primarily due to the reclassification of revenues and expenses associated with unregulated sales of products and services to other revenues and operations and maintenance expense, respectively, as a result of the adoption of ASC 606. See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's adoption of ASC 606.

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Income Taxes

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(89)	(41.2)	$(221)	(44.8)

In the third quarter 2018, income taxes were $127 million compared to $216 million for the corresponding period in 2017. For year-to-date 2018, income taxes were $272 million compared to $493 million for the corresponding period in 2017. These decreases were primarily due to the reduction in the federal income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation and lower pre-tax earnings. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Accounting Order" and Note (H) to the Condensed Financial Statements under "Effective Tax Rate" herein 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 limited projected demand growth over the next several years. Future earnings will be impacted by customer growth. 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. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. A major portion of these costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, 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 fully 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

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flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters" and "Retail Regulatory Matters – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.

Environmental Laws and Regulations

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.

On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.

Coal Combustion Residuals

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).

The EPA published certain amendments to the CCR Rule, which became effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. Specific site impacts are being evaluated by Alabama Power.

On October 15, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a mandate that broadens the CCR Rule to regulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that the EPA will issue a series of rulemakings to address this court action. Alabama Power is evaluating the extent of potential impacts on legacy units. The ultimate impact of these changes will not be known until the EPA rulemaking and any legal challenges are finalized.

On April 20, 2018, the Alabama Environmental Management Commission approved a state CCR rule that has been provided to the EPA for a six-month review period. This state CCR rule is generally consistent with the federal CCR Rule. The ultimate outcome of this matter cannot be determined at this time.

In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related to the CCR Rule. The revised cost estimates were based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power. During the second quarter 2018, Alabama Power's management completed its analysis of these studies which indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology. As further analysis is performed and closure details are developed with respect to ash pond closures, Alabama Power expects to periodically update these cost estimates. As the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

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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 these matters cannot be determined at this time.

Nuclear Decommissioning

See Note 1 to the financial statements of Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" and "Nuclear Decommissioning" herein for additional information.

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

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information.

On August 31, 2018, the EPA published a proposed Clean Power Plan replacement rule known as the Affordable Clean Energy rule (ACE Rule), which would require states to develop unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of September 30, 2018, Alabama Power has ownership interests in20 fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to Alabama Power is currently unknown and will depend on changes between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal proceedings.

Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time.

FERC Matters

Market-Based Rate Authority

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Alabama Power in Item 7 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies' (including Alabama Power's) and Southern Power's 2014 and 2017 triennial market power analyses.

On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies (including Alabama Power) and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies (including Alabama Power) and Southern Power made the compliance filing required by the order. These proceedings are concluded.

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Open Access Transmission Tariff

On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies (including Alabama Power) claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Alabama Power's) open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Alabama Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material to Alabama Power's results of operations. The ultimate outcome of this matter cannot be determined at this time.

Relicensing of Hydroelectric Developments

See BUSINESS – "Regulation – Federal Power Act" in Item 1 of the Form 10-K for a discussion of Alabama

Power's hydroelectric developments on the Coosa River.

On July 6, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating the FERC's 2013 order issuing a new 30-year license to Alabama Power for seven hydroelectric developments on the Coosa River and remanding the proceeding to the FERC for further proceedings. Alabama Power continues to operate the Coosa River developments under annual licenses issued by the FERC. The ultimate outcome of this matter cannot be determined at this time.

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 Notes 1 and 3 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and "Retail Regulatory Matters," respectively, 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.

On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. At September 30, 2018, Alabama Power's equity ratio was approximately 47%. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" of Alabama Power in Item 7 of the Form 10-K for additional information.

Rate RSE

The approved modifications to Rate RSE became effective June 2018 and are applicable for January 2019 billings and thereafter. The modifications include reducing the top of the allowed weighted common equity return (WCER) range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range.

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

In accordance with an established retail tariff that provides for an interim adjustment to customer billings to recognize the impact of a change in the statutory income tax rate, Alabama Power has returned $151 million through September 30, 2018 and anticipates returning a total of approximately $257 million to retail customers through bill credits by December 31, 2018 as a result of the change in the federal income tax rate under the Tax Reform Legislation.

Rate ECR

On May 1, 2018, the Alabama PSC approved an increase to Rate ECR from 2.015 cents per KWH to 2.353 cents per KWH effective July 2018 which is expected to result in additional collections of approximately $100 million through December 31, 2018. The approved increase in the Rate ECR factor will have no significant effect on Alabama Power's net income, but will increase operating cash flows related to fuel cost recovery in 2018. Absent any further order from the Alabama PSC, in January 2019, the rate will return to the originally authorized 5.910 cents per KWH.

Accounting Order

On May 1, 2018, the Alabama PSC approved an accounting order that authorizes Alabama Power to defer the benefits of federal excess deferred income taxes associated with the Tax Reform Legislation for the year ending December 31, 2018 as a regulatory liability and to use up to $30 million of such deferrals to offset under recovered amounts under Rate ECR. Any remaining amounts will be used for the benefit of customers as determined by the Alabama PSC. As of September 30, 2018, Alabama Power had applied the full $30 million to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 5 to the financial statements of Alabama Power under "Federal Tax Reform Legislation" and "Current and Deferred Income Taxes" in Item 8 of the Form 10-K for additional information.

Plant Greene County

Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information regarding the joint ownership agreement. On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP) with the Mississippi PSC, which proposes a four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively. Mississippi Power's proposed Plant Greene County unit retirements would require the completion of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will monitor Mississippi Power's proposed RMP and associated regulatory process as well as the proposed transmission and system reliability improvements. Alabama Power will review all the facts and circumstances and will evaluate all its alternatives prior to reaching a final determination on the ongoing operations of Plant Greene County. The ultimate outcome of this matter cannot be determined at this time.

Request for Proposals for Future Generation

On September 21, 2018, Alabama Power issued a request for proposals of between 100 MWs and 1,200 MWs of capacity beginning no later than 2023. Any purchases will depend upon the cost competitiveness of the respective offers as well as other options available to Alabama Power. The ultimate outcome of this matter cannot be determined at this time.

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Alabama Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY –

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"Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Alabama Power," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.

Other Matters

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

The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) 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 Note (B) 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.

On March 2, 2018, the Alabama Department of Environmental Management (ADEM) issued proposed administrative orders assessing a penalty of $1.25 million to Alabama Power for unpermitted discharge of fluids and/or pollutants to groundwater at five electric generating plants. The orders were finalized and Alabama Power paid the penalty on September 27, 2018. This matter is now concluded.

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 Note 1 to the financial statements of Alabama Power 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.

Recently Issued Accounting Standards

See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Alabama Power in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Alabama Power's recently adopted accounting standards.

In 2016, the FASB issued ASU No. 2016-02, which requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Alabama Power will adopt the new standard effective January 1, 2019.

Alabama Power has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the

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adoption date of January 1, 2019, without restating prior periods. Alabama Power expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Alabama Power expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Alabama Power also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.

Alabama Power is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Alabama Power has substantially completed its lease inventory and determined its most significant leases involve PPAs. While Alabama Power has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in recording lease liabilities and right-of-use assets on Alabama Power's balance sheet each totaling approximately $200 million, with no material impact on Alabama Power's statement of income.

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 September 30, 2018. 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 $1.39 billion for the first nine months of 2018, a decrease of $22 million as compared to the first nine months of 2017. The decrease in net cash provided from operating activities was primarily due to the timing of vendor payments partially offset by income tax refunds received in 2018. Net cash used for investing activities totaled $1.60 billion for the first nine months of 2018 primarily due to gross property additions related to environmental, distribution, transmission, and steam assets. Net cash provided from financing activities totaled $369 million for the first nine months of 2018 primarily due to an issuance of long-term debt and additional capital contributions from Southern Company, partially offset by common stock dividend payments. 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 nine months of 2018 include increases of $2.40 billion in property, plant, and equipment primarily due to increases in AROs related to the CCR Rule and additions to distribution, transmission, and steam assets, $1.39 billion in AROs related to the CCR Rule and nuclear decommissioning, $504 million in additional paid-in capital primarily due to capital contributions from Southern Company, and $496 million in long-term debt primarily due to a senior note issuance. In addition, $321 million of long-term debt was reclassified as securities due within one year. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information related to changes in Alabama Power's AROs.

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. Subsequent to September 30, 2018, Alabama Power purchased and held $120 million aggregate principal amount of The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008. An additional $201 million will be required through September 30, 2019 to fund maturities of long-term debt.

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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.

In October 2018, Alabama Power's Board of Directors approved updates to its construction program that is currently estimated to total $1.8 billion for 2019, $1.6 billion for 2020, $1.6 billion for 2021, $1.4 billion for 2022, and $1.5 billion for 2023. The construction program includes capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental statutes and regulations included in these amounts are $0.3 billion for 2019, $0.1 billion for 2020, $0.2 billion for 2021, $0.2 billion for 2022, and $0.1 billion for 2023. These estimated expenditures do not include any potential compliance costs associated with pending regulation of CO₂ emissions from fossil-fuel-fired electric generating units.

Alabama Power anticipates costs associated with closure-in-place and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in Alabama Power's ARO liabilities. These costs, which are expected to change, could change materially as Alabama Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities. These costs are expected to begin in 2019 and are currently estimated to be approximately $232 million for 2019, $238 million for 2020, $246 million for 2021, $252 million for 2022, and $258 million for 2023. See FUTURE EARNINGS POTENTIAL – "Environmental Matters– Environmental Laws and Regulations – Coal Combustion Residuals" herein, Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein, and Note 1 to the financial statements of Alabama Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in 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 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. 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 September 30, 2018, Alabama Power had approximately $702 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2018 were as follows:

Expires										Expires Within One Year
2019		2020		2022		Total		Unused		Term Out		No Term Out
(in millions)
$	33	$	500	$	800	$	1,333	$	1,333	$	—	$	33

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See Note 6 to the financial statements of Alabama Power 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 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 September 30, 2018, Alabama Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

Subject to applicable market conditions, Alabama Power expects to renew or replace its bank credit arrangements as needed, prior to expiration. In connection therewith, Alabama Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

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 September 30, 2018. At September 30, 2018, Alabama Power had $120 million aggregate principal amount of fixed rate The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008 outstanding that were required to be reoffered within the next 12 months. Subsequent to September 30, 2018, Alabama Power purchased and held all of these bonds.

Alabama Power also has substantial cash flow from operating activities and access to 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.

Details of short-term borrowings were as follows:

	Short-term Debt at September 30, 2018				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	$	—	—	%	$	11	2.2	%	$	135
Short-term bank loan	3		3.7	%	3		3.7	%	3
Total	$	3	3.7	%	$	14	2.6	%

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2018.

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 September 30, 2018, Alabama Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, energy price risk management, and transmission.

The maximum potential collateral requirements under these contracts at September 30, 2018 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	1
At BBB- and/or Baa3	$	1
Below BBB- and/or Baa3	$	284

Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power (affiliate company of Alabama Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Alabama Power to access capital markets and would be likely to impact the cost at which it does so.

On September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and certain of its subsidiaries (including Alabama Power).

Also on September 28, 2018, Moody's revised its rating outlook for Alabama Power from negative to stable.

As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Alabama Power, may be negatively impacted. The modifications to Rate RSE and other commitments approved by the Alabama PSC are expected to help mitigate these potential adverse impacts to certain credit metrics and will help Alabama Power meet its goal of achieving an equity ratio of approximately 55% by the end of 2025. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Alabama Power – Rate RSE" herein for additional information.

Financing Activities

In June 2018, Alabama Power issued $500 million aggregate principal amount of Series 2018A 4.30% Senior Notes due July 15, 2048. The proceeds were used to repay outstanding commercial paper and for general corporate purposes, including Alabama Power's continuous construction program.

Subsequent to September 30, 2018, Alabama Power purchased and held $120 million aggregate principal amount of The Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Plant Barry Project), Series 2008. These bonds may be remarketed to the public in the future.

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.

80

GEORGIA POWER COMPANY

81

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	2,425		$	2,402		$	6,112		$	5,995
Wholesale revenues, non-affiliates	43			45			123			124
Wholesale revenues, affiliates	4			6			17			23
Other revenues	121			93			349			284
Total operating revenues	2,593			2,546			6,601			6,426
Operating Expenses:
Fuel	480			482			1,269			1,297
Purchased power, non-affiliates	106			119			338			310
Purchased power, affiliates	206			161			555			470
Other operations and maintenance	460			430			1,325			1,248
Depreciation and amortization	232			225			690			669
Taxes other than income taxes	118			112			332			311
Estimated loss on Plant Vogtle Units 3 and 4	—			—			1,060			—
Total operating expenses	1,602			1,529			5,569			4,305
Operating Income	991			1,017			1,032			2,121
Other Income and (Expense):
Interest expense, net of amounts capitalized	(95		)	(105		)	(303		)	(310		)
Other income (expense), net	30			22			104			95
Total other income and (expense)	(65		)	(83		)	(199		)	(215		)
Earnings Before Income Taxes	926			934			833			1,906
Income taxes	262			350			212			705
Net Income	664			584			621			1,201
Dividends on Preferred and Preference Stock	—			4			—			13
Net Income After Dividends on Preferred and Preference Stock	$	664		$	580		$	621		$	1,188

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2018		2017		2018		2017
	(in millions)				(in millions)
Net Income	$	664	$	584	$	621	$	1,201
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $1, and $1, respectively	1		1		3		2
Total other comprehensive income (loss)	1		1		3		2
Comprehensive Income	$	665	$	585	$	624	$	1,203

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 Nine Months Ended September 30,
	2018			2017
	(in millions)
Operating Activities:
Net income	$	621		$	1,201
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	854			821
Deferred income taxes	(185		)	328
Allowance for equity funds used during construction	(50		)	(29		)
Pension, postretirement, and other employee benefits	(46		)	(42		)
Settlement of asset retirement obligations	(82		)	(95		)
Estimated loss on Plant Vogtle Units 3 and 4	1,060			—
Other, net	9			(51		)
Changes in certain current assets and liabilities —
-Receivables	(205		)	(254		)
-Fossil fuel stock	70			(2		)
-Prepaid income taxes	231			(5		)
-Other current assets	(36		)	(24		)
-Accounts payable	109			(161		)
-Accrued taxes	26			(52		)
-Accrued compensation	(32		)	(60		)
-Retail fuel cost over recovery	—			(84		)
-Other current liabilities	(111		)	(11		)
Net cash provided from operating activities	2,233			1,480
Investing Activities:
Property additions	(2,276		)	(1,907		)
Nuclear decommissioning trust fund purchases	(638		)	(411		)
Nuclear decommissioning trust fund sales	633			406
Cost of removal, net of salvage	(71		)	(54		)
Change in construction payables, net of joint owner portion	72			180
Payments pursuant to LTSAs	(52		)	(59		)
Asset dispositions	138			63
Other investing activities	(19		)	(52		)
Net cash used for investing activities	(2,213		)	(1,834		)
Financing Activities:
Increase (decrease) in notes payable, net	102			(391		)
Proceeds —
Capital contributions from parent company	2,335			412
Senior notes	—			1,350
Short-term borrowings	—			700
Other long-term debt	—			370
Redemptions and repurchases —
Senior notes	(1,000		)	(450		)
Pollution control revenue bonds	(469		)	(65		)
Short-term borrowings	(150		)	(300		)
Other long-term debt	(100		)	—
Payment of common stock dividends	(1,043		)	(961		)
Premiums on redemption and repurchases of senior notes	(152		)	—
Other financing activities	(15		)	(48		)
Net cash provided from (used for) financing activities	(492		)	617
Net Change in Cash, Cash Equivalents, and Restricted Cash	(472		)	263
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	852			3
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	380		$	266
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $19 and $17 capitalized for 2018 and 2017, respectively)	$	315		$	284
Income taxes, net	141			369
Noncash transactions — Accrued property additions at end of period	670			470

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 BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2018			At December 31, 2017
	(in millions)
Current Assets:
Cash and cash equivalents	$	380		$	852
Receivables —
Customer accounts receivable	747			544
Unbilled revenues	245			255
Under recovered fuel clause revenues	105			165
Joint owner accounts receivable	208			262
Affiliated	39			24
Other accounts and notes receivable	96			76
Accumulated provision for uncollectible accounts	(3		)	(3		)
Fossil fuel stock	244			314
Materials and supplies	494			504
Prepaid expenses	77			216
Other regulatory assets, current	199			205
Other current assets	91			14
Total current assets	2,922			3,428
Property, Plant, and Equipment:
In service	35,671			34,861
Less: Accumulated provision for depreciation	12,029			11,704
Plant in service, net of depreciation	23,642			23,157
Nuclear fuel, at amortized cost	528			544
Construction work in progress	4,655			4,613
Total property, plant, and equipment	28,825			28,314
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	50			53
Nuclear decommissioning trusts, at fair value	933			929
Miscellaneous property and investments	61			59
Total other property and investments	1,044			1,041
Deferred Charges and Other Assets:
Deferred charges related to income taxes	519			516
Other regulatory assets, deferred	3,041			2,932
Other deferred charges and assets	510			548
Total deferred charges and other assets	4,070			3,996
Total Assets	$	36,861		$	36,779

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 BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2018			At December 31, 2017
	(in millions)
Current Liabilities:
Securities due within one year	$	511		$	857
Notes payable	102			150
Accounts payable —
Affiliated	515			493
Other	909			834
Customer deposits	275			270
Accrued taxes	345			344
Accrued interest	108			123
Accrued compensation	185			219
Asset retirement obligations, current	193			270
Other regulatory liabilities, current	151			191
Other current liabilities	180			198
Total current liabilities	3,474			3,949
Long-term Debt	9,863			11,073
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	2,999			3,175
Deferred credits related to income taxes	3,218			3,248
Accumulated deferred ITCs	264			248
Employee benefit obligations	650			659
Asset retirement obligations, deferred	2,401			2,368
Other deferred credits and liabilities	141			128
Total deferred credits and other liabilities	9,673			9,826
Total Liabilities	23,010			24,848
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — 9,261,500 shares	398			398
Paid-in capital	9,670			7,328
Retained earnings	3,792			4,215
Accumulated other comprehensive loss	(9		)	(10		)
Total common stockholder's equity	13,851			11,931
Total Liabilities and Stockholder's Equity	$	36,861		$	36,779

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

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2018 vs. THIRD QUARTER 2017

AND

YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017

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 to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. Georgia Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future. On April 3, 2018, the Georgia PSC approved a settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation (Tax Reform Settlement Agreement). The Tax Reform Settlement Agreement provides for a total of $330 million in customer refunds for 2018 and 2019 and the deferral of certain revenues and tax benefits to be addressed in Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. The Georgia PSC also approved an increase to Georgia Power's retail equity ratio to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate Plans" herein for additional information on the Tax Reform Settlement Agreement.

Georgia Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, the execution of major construction projects, and net income.

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). 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 cost forecast and estimated contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for a total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds). Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC has stated the $7.3 billion estimate included in the seventeenth VCM proceeding does not represent a cost cap, Georgia Power did not seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast (or any related financing costs) in the nineteenth VCM report filed with the Georgia PSC on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs included in the revised construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018.

86

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. On September 26, 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4. In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and certain of MEAG's wholly-owned subsidiaries, including MEAG Power SPVJ, LLC (MEAG SPVJ), to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners and (ii) a term sheet 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. Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain provisions of the Vogtle Owner Term Sheet.

In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In September 2018, the DOE extended the conditional commitment to March 31, 2019. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions.

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

See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" and ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on Plant Vogtle Units 3 and 4.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$84	14.5	$(567)	(47.7)

Georgia Power's net income after dividends on preferred and preference stock for the third quarter 2018 was $664 million compared to $580 million for the corresponding period in 2017. The increase was primarily due to lower federal income tax expense as a result of the Tax Reform Legislation and an increase in retail revenues associated with customer growth and warmer weather in the third quarter 2018 compared to the corresponding period in 2017. Partially offsetting the increase were revenues deferred as a regulatory liability for future customer bill credits related to the Tax Reform Legislation as well as higher non-fuel operations and maintenance expenses.

For year-to-date 2018, net income after dividends on preferred and preference stock was $621 million compared to $1.19 billion for the corresponding period in 2017. The decrease 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, revenues deferred as a regulatory liability for future customer bill credits related to the Tax Reform Legislation, and higher non-fuel operations and maintenance expenses. Partially offsetting the decrease were lower federal income tax expense as a result of the Tax Reform Legislation and an increase in retail revenues associated with colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 compared to the corresponding periods in 2017.

See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate Plans" herein for additional information on regulatory actions related to the Tax Reform Legislation. Also, see Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information on the estimated loss related to Georgia Power's construction of Plant Vogtle Units 3 and 4.

87

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$23	1.0	$117	2.0

In the third quarter 2018, retail revenues were $2.43 billion compared to $2.40 billion for the corresponding period in 2017. For year-to-date 2018, retail revenues were $6.11 billion compared to $6.00 billion for the corresponding period in 2017.

Details of the changes in retail revenues were as follows:

	Third Quarter 2018					Year-to-Date 2018
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	2,402				$	5,995
Estimated change resulting from –
Rates and pricing	(87		)	(3.6	)	(196		)	(3.2	)
Sales growth	44			1.9		70			1.2
Weather	34			1.4		139			2.3
Fuel cost recovery	32			1.3		104			1.7
Retail – current year	$	2,425		1.0	%	$	6,112		2.0	%

Revenues associated with changes in rates and pricing decreased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to revenues deferred as a regulatory liability for future customer bill credits related to the Tax Reform Legislation and decreases in revenues recognized under the NCCR tariff, also primarily related to the Tax Reform Legislation. Partially offsetting the decrease for year-to-date 2018 were higher contributions from variable demand-driven pricing from commercial and industrial customers. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate Plans" herein for additional information on regulatory actions related to the Tax Reform Legislation. Also, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" of Georgia Power in Item 7 of the Form 10-K and 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 increased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017. Weather-adjusted residential KWH sales increased 3.3% and 1.9% and weather-adjusted commercial KWH sales increased 2.1% and 1.8% for the third quarter and year-to-date 2018, respectively, largely due to customer growth. Weather-adjusted industrial KWH sales increased 2.5% and 1.2% for the third quarter and year-to-date 2018, respectively. The increases were primarily driven by increased demand in the paper sector as a result of increased export demand and for shipping supplies resulting from increased electronic commerce, the lumber sector as a result of increased construction activity, and the rubber sector as a result of increased demand by the tire industry. Additionally, customer usage for all customer classes increased in the third quarter and year-to-date 2018 due to the negative impacts of Hurricane Irma during the corresponding periods in 2017.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to increased energy sales driven by higher purchased power costs and warmer weather in the third quarter 2018. Additionally, the increase for year-to-date 2018 was due to colder weather in the first quarter 2018 and warmer weather in the second quarter 2018. 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

88

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 – Affiliates

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	(33.3)	$(6)	(26.1)

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.

For year-to-date 2018, wholesale revenues from sales to affiliates were $17 million compared to $23 million for the corresponding period in 2017. The decrease was due to a 54.3% decrease in KWH sales primarily due to the higher cost of Georgia Power-owned generation as compared to the market cost of available energy.

Other Revenues

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$28	30.1	$65	22.9

In the third quarter 2018, other revenues were $121 million compared to $93 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $349 million compared to $284 million for the corresponding period in 2017. The increases were primarily due to $24 million and $62 million of revenues in the third quarter and year-to-date 2018, respectively, primarily from unregulated sales of products and services that were reclassified as other revenues as a result of the adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). In prior periods, these revenues were included in other income (expense), net. See Note (A) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 606.

Fuel and Purchased Power Expenses

	Third Quarter 2018 vs. Third Quarter 2017					Year-to-Date 2018 vs. Year-to-Date 2017
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	(2	)	(0.4	)	$	(28	)	(2.2	)
Purchased power – non-affiliates	(13		)	(10.9	)	28			9.0
Purchased power – affiliates	45			28.0		85			18.1
Total fuel and purchased power expenses	$	30				$	85

In the third quarter 2018, total fuel and purchased power expenses were $792 million compared to $762 million in the corresponding period in 2017. The increase was primarily due to a $43 million net increase related to the volume of KWHs generated and purchased due to warmer weather, partially offset by a $13 million decrease related to the average cost of purchased power primarily due to lower natural gas prices.

For year-to-date 2018, total fuel and purchased power expenses were $2.16 billion compared to $2.08 billion in the corresponding period in 2017. The increase was primarily due to a $77 million increase related to the volume of KWHs purchased due to colder weather in the first quarter 2018 and warmer weather in the second and third quarters 2018 and a $10 million net increase in the average cost of fuel and purchased power.

89

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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

	Third Quarter 2018	Third Quarter 2017	Year-to-Date 2018	Year-to-Date 2017
Total generation (in billions of KWHs)	18	18	49	48
Total purchased power (in billions of KWHs)	8	7	22	20
Sources of generation (percent) —
Gas	44	41	43	41
Coal	32	35	30	33
Nuclear	22	23	25	24
Hydro	2	1	2	2
Cost of fuel, generated (in cents per net KWH)—
Gas	2.58	2.63	2.64	2.71
Coal	3.14	3.08	3.25	3.17
Nuclear	0.83	0.84	0.83	0.84
Average cost of fuel, generated (in cents per net KWH)	2.36	2.38	2.36	2.40
Average cost of purchased power (in cents per net KWH)(*)	4.52	4.68	4.70	4.63

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

Fuel

For year-to-date 2018, fuel expense was $1.27 billion compared to $1.30 billion in the corresponding period in 2017. The decrease was primarily due to an 8.0% decrease in the volume of KWHs generated by coal largely due to scheduled generation outages and a 2.6% decrease in the average cost of fuel per KWH generated by natural gas, partially offset by a 6.8% increase in the volume of KWHs generated by natural gas and a 2.5% increase in the average cost of fuel per KWH generated by coal.

Purchased Power – Non-Affiliates

In the third quarter 2018, purchased power expense from non-affiliates was $106 million compared to $119 million in the corresponding period in 2017. The decrease was primarily due to a 17.8% decrease in the volume of KWHs purchased primarily due to the higher market cost of available energy as compared to Southern Company system resources, partially offset by an 8.3% increase in the average cost per KWH purchased primarily due to higher energy prices.

For year-to-date 2018, purchased power expense from non-affiliates was $338 million compared to $310 million in the corresponding period in 2017. The increase was primarily due to a 10.2% increase in the average cost per KWH purchased primarily due to higher energy prices.

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

90

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Purchased Power – Affiliates

In the third quarter 2018, purchased power expense from affiliates was $206 million compared to $161 million in the corresponding period in 2017. The increase was primarily due to a 28.3% increase in the volume of KWHs purchased due to scheduled generation outages and warmer weather, partially offset by a 3.4% decrease in the average cost per KWH purchased primarily resulting from lower natural gas prices.

For year-to-date 2018, purchased power expense from affiliates was $555 million compared to $470 million in the corresponding period in 2017. The increase was primarily due to an 11.1% increase in the volume of KWHs purchased due to colder weather in the first quarter 2018 and scheduled generation outages and warmer weather in the second and third quarters 2018.

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

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$30	7.0	$77	6.2

In the third quarter 2018, other operations and maintenance expenses were $460 million compared to $430 million in the corresponding period in 2017. The increase was primarily due to $23 million of expenses from unregulated sales of products and services that were reclassified to other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. Also contributing to the increase was $11 million in transmission and distribution costs, primarily due to additional line maintenance and billing adjustments with integrated transmission system owners, partially offset by a decrease of $9 million in certain employee compensation and benefit costs.

For year-to-date 2018, other operations and maintenance expenses were $1.33 billion compared to $1.25 billion in the corresponding period in 2017. The increase was primarily due to $58 million of expenses from unregulated sales of products and services that were reclassified to other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. Also contributing to the increase were a $19 million decrease in gains from sales of integrated transmission system assets and increases of $11 million in demand-side management costs related to the timing of new programs, $8 million related to additional distribution line maintenance, and $8 million in billing adjustments with integrated transmission system owners, partially offset by decreases of $14 million in certain employee compensation and benefit costs and $10 million related to affiliate labor billing adjustments.

See Note (A) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 606.

Depreciation and Amortization

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$7	3.1	$21	3.1

In the third quarter 2018, depreciation and amortization was $232 million compared to $225 million in the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $690 million compared to $669 million in the corresponding period in 2017. The increases were primarily due to increases of $8 million and $23 million related to additional plant in service in the third quarter and year-to-date 2018, respectively.

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Taxes Other Than Income Taxes

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$6	5.4	$21	6.8

In the third quarter 2018, taxes other than income taxes were $118 million compared to $112 million in the corresponding period in 2017. For year-to-date 2018, taxes other than income taxes were $332 million compared to $311 million in the corresponding period in 2017. The increases were primarily due to increases in property taxes of $4 million and $11 million in the third quarter and year-to-date 2018, respectively, as a result of an increase in the assessed value of property and increases in municipal franchise fees of $3 million and $10 million in the third quarter and year-to-date 2018, respectively, largely related to higher retail revenues.

Estimated Loss on Plant Vogtle Units 3 and 4

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$—	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 (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(10)	(9.5)	$(7)	(2.3)

In the third quarter 2018, interest expense, net of amounts capitalized was $95 million compared to $105 million in the corresponding period in 2017. For year-to-date 2018, interest expense, net of amounts capitalized was $303 million compared to $310 million in the corresponding period in 2017. The decreases were primarily due to a decrease in outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information.

Other Income (Expense), Net

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$8	36.4	$9	9.5

In the third quarter 2018, other income (expense), net was $30 million compared to $22 million in the corresponding period in 2017. For year-to-date 2018, other income (expense), net was $104 million compared to $95 million in the corresponding period in 2017. The increases were primarily due to increases in AFUDC equity of $14 million and $21 million in the third quarter and year-to-date 2018, respectively, resulting from a higher AFUDC rate due to a higher equity ratio and lower short-term borrowings. These increases were partially offset by $3 million and $11 million in the third quarter and year-to-date 2017, respectively, of revenues and expenses, net from unregulated sales of products and services. In 2018, these revenues and expenses are included in other revenues and

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other operations and maintenance expenses, respectively, as a result of the adoption of ASC 606. See Note (A) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 606.

Income Taxes

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(88)	(25.1)	$(493)	(69.9)

In the third quarter 2018, income taxes were $262 million compared to $350 million in the corresponding period in 2017. For year-to-date 2018, income taxes were $212 million compared to $705 million in the corresponding period in 2017. The decreases were primarily due to a lower federal income tax rate as a result of the Tax Reform Legislation, partially offset by the recognition of a valuation allowance on certain state tax credit carryforwards. Also contributing to the decrease for year-to-date 2018 was the reduction in pre-tax earnings resulting from the estimated probable loss related to Plant Vogtle Units 3 and 4.

See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information on the estimated loss related to Georgia Power's construction of Plant Vogtle Units 3 and 4. Also, see Note (H) to the Condensed Financial Statements herein for additional information on the Tax Reform Legislation and the net state income tax valuation allowance.

Dividends on Preferred and Preference Stock

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(4)	(100.0)	$(13)	(100.0)

In the third quarter and year-to-date 2018, there were no dividends on preferred and preference stock compared to $4 million and $13 million, respectively, in the corresponding periods in 2017. The decreases were due to the redemption in October 2017 of all outstanding shares of Georgia Power's preferred and preference stock. See Note 6 to the financial statements of Georgia Power under "Outstanding Classes of Capital Stock" 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 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 limited projected demand growth over the next several years. Plant Vogtle Units 3 and 4 construction and rate recovery are also major factors. Future earnings will be driven primarily by customer growth. 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.

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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 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. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. A major portion of these costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, 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 fully 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 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 of Georgia Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Laws and Regulations

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.

On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.

Coal Combustion Residuals

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).

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

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groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. However, the Georgia Department of Natural Resources has not incorporated these amendments into its state CCR rule. Specific site impacts are being evaluated by Georgia Power.

On October 15, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a mandate that broadens the CCR Rule to regulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that the EPA will issue a series of rulemakings to address this court action. Georgia Power is evaluating the extent of potential impacts on legacy units but anticipates no significant impacts to its ongoing CCR strategy due to this mandate. The ultimate impact of these changes will not be known until the EPA rulemaking and any legal challenges are finalized.

Georgia Power continues to perform engineering studies related to its plans to close the ash ponds at all of its generating plants, including one jointly owned with Gulf Power, in compliance with federal and state CCR rules. Georgia Power also continues to refine its closure strategy and cost estimates for each ash pond and is preparing permit applications as required by the State of Georgia CCR rule. While Georgia Power believes its recorded liability for ash pond closures appropriately reflects its obligations under the current closure strategies it has elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase the ARO liability. It is not currently possible to quantify the impacts of any increase related to a change in closure strategies and/or ongoing engineering studies for the current closure strategies, and the timing of future cash outflows is indeterminable at this time; however, the impact on the ARO liability is expected to be material. As permit applications advance, engineering studies continue, and the timing of individual ash pond closures develops further during the fourth quarter 2018, Georgia Power will record any necessary changes to its ARO liability. Georgia Power expects to continue to periodically update these cost estimates, which could increase further, as additional information becomes available. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

Absent continued recovery of ARO costs through regulated rates, Georgia Power'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.

Nuclear Decommissioning

See Note 1 to the financial statements of Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

Georgia Power expects to complete updated decommissioning cost site studies for Plant Hatch and Plant Vogtle Units 1 and 2 in the fourth quarter 2018, which could result in additional changes to Georgia Power's ARO liability. The ultimate outcome of these studies cannot be determined at this time.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Georgia Power in Item 7 of the Form 10-K for additional information.

On August 31, 2018, the EPA published a proposed Clean Power Plan replacement rule known as the Affordable Clean Energy rule (ACE Rule), which would require states to develop unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of September 30, 2018, Georgia Power has ownership interests in20 fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to Georgia Power is currently unknown and will depend on changes between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal proceedings.

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Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, complete construction of Plant Vogtle Units 3 and 4, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time.

FERC Matters

Market-Based Rate Authority

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Georgia Power in Item 7 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies' (including Georgia Power's) and Southern Power's 2014 and 2017 triennial market power analyses.

On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies (including Georgia Power) and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies (including Georgia Power) and Southern Power made the compliance filing required by the order. These proceedings are concluded.

Open Access Transmission Tariff

On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies (including Georgia Power) claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Georgia Power's) open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Georgia Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material to Georgia Power's results of operations. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management 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 "Nuclear Construction" herein and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also 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 regarding fuel cost recovery.

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Rate Plans

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate Plans" of Georgia Power in Item 7 of the Form 10-K for additional information regarding Georgia Power's 2013 ARP and the Georgia PSC's 2018 order related to the Tax Reform Legislation.

On April 3, 2018, the Georgia PSC approved the Tax Reform Settlement Agreement. Pursuant to the Tax Reform Settlement Agreement, to reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power will refund to customers a total of $330 million through bill credits. Georgia Power issued bill credits of approximately $130 million in October 2018 and will issue bill credits of approximately $95 million in June 2019 and $105 million in February 2020. In addition, Georgia Power is deferring as a regulatory liability (i) the revenue equivalent of the tax expense reduction resulting from legislation lowering the Georgia state income tax rate from 6.00% to 5.75% in 2019 and (ii) the entire benefit of approximately $700 million in federal and state excess accumulated deferred income taxes. At September 30, 2018, the related regulatory liability balance totaled$655 million.The amortization of these regulatory liabilities is expected to be addressed in Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. If there is not a base rate case in 2019, customers will receive $185 million in annual bill credits beginning in 2020, with any additional federal and state income tax savings deferred as a regulatory liability, until Georgia Power's next base rate case.

To address the negative cash flow and credit metric impacts of the Tax Reform Legislation, the Georgia PSC also approved an increase in Georgia Power's retail equity ratio to the lower of (i) Georgia Power's actual common equity weight in its capital structure or (ii) 55%, until Georgia Power's next base rate case. At September 30, 2018, Georgia Power's actual retail common equity ratio (on a 13-month average basis) was approximately 53%. Benefits from reduced federal income tax rates in excess of the amounts refunded to customers will be retained by Georgia Power to cover the carrying costs of the incremental equity in 2018 and 2019.

Storm Damage Recovery

See Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.

Georgia Power is accruing$30 millionannually through December 31, 2019, as provided in the 2013 ARP, for incremental operations and maintenance costs of damage from major storms to its transmission and distribution facilities. As ofSeptember 30, 2018, the total balance in the regulatory asset related to storm damage was$311 million. During October 2018, Hurricane Michael caused significant damage to Georgia Power's transmission and distribution facilities. Georgia Power currently estimates the costs of repairing the damage will total approximately$125 million to $150 million, which will be charged to the storm damage reserve or capitalized. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. The ultimate outcome of this matter cannot be determined at this time.

Nuclear Construction

See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, VCM reports, and the NCCR tariff.

In 2009, the Georgia PSC certified construction of 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 Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired in July 2017 when Georgia Power, acting for itself and as

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agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement. Under the Vogtle Services Agreement, Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

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

In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor.

Cost and Schedule

In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. 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 September 30, 2018(b)	(4.3		)
Remaining estimate to complete(a)	$	4.1

(a) Excludes financing costs expected to be capitalized through AFUDC of approximately $350 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 $3.2 billion, of which $1.8 billion had been incurred through September 30, 2018.

The table above reflects the $0.7 billion increase to the base capital cost forecast reported in the second quarter 2018 and is based on the cost reforecast performed prior to the nineteenth VCM filing, which primarily resulted from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.

Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle

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Units 3 and 4 is not subject to a cost cap, Georgia Power did not seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs) in the nineteenth VCM report that was filed with the Georgia PSC on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018, which includes the total increase in the base capital cost forecast and construction contingency estimate.

As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule continue to increase significantly through the remainder of 2018 and into 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers 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 resolution of Inspections, Tests, Analyses, and Acceptance Criteria (ITAAC) and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Joint Owner Contracts

In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective August 31, 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.

As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs as described above, the holders of at least 90% of the ownership

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interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. On September 26, 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.

Amendments to the Vogtle Joint Ownership Agreements

In connection with the vote to continue construction, Georgia Power entered into (i) the Vogtle Owner Term Sheet with the other Vogtle Owners and MEAG's wholly-owned subsidiaries MEAG SPVJ, MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners, and (ii) a term sheet (MEAG Term Sheet and, together with the Vogtle Owner Term Sheet, Term Sheets) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 (Project J) under certain circumstances. Pursuant to the Vogtle Owner Term Sheet, the Vogtle Joint Ownership Agreements will be modified as follows: (i) each Vogtle Owner will pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which forms the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million of additional construction costs; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests.

If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion. In this event, Georgia Power will have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Vogtle Owner. If Georgia Power accepts the offer to purchase a portion of another Vogtle Owner's ownership interest in Plant Vogtle Units 3 and 4, the ownership interest(s) to be conveyed from the tendering Vogtle Owner(s) to Georgia Power would be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Vogtle Owner(s) and by Georgia Power as of the commercial operation date of Plant Vogtle Unit 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Vogtle Owner in accordance with the second and third items described in the paragraph above would be treated as payments made by the applicable Vogtle Owner.

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

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

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Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain of the above provisions of the Vogtle Owner Term Sheet.

Under the Vogtle Owner Term Sheet, the provisions of the Vogtle Joint Ownership Agreements requiring that Vogtle Owners holding 90% of the ownership interests in Plant Vogtle Units 3 and 4 vote to continue construction following certain adverse events (Project Adverse Events) will be modified. Pursuant to the Vogtle Joint Ownership Agreements and the Vogtle Owner Term Sheet, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain Project Adverse Events occur, including: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Vogtle Owner Term Sheet provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule. Under the Vogtle Owner Term Sheet, Georgia Power may cancel the project at any time in its sole discretion.

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

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

Purchase of PTCs During Commercial Operation

In addition, under the terms of the Vogtle Owner Term Sheet, Georgia Power agreed to purchase additional PTCs from OPC, Dalton, MEAG SPVM, MEAG SPVP, and MEAG SPVJ (to the extent any MEAG SPVJ PTC rights remain after any purchases required under the MEAG Term Sheet as described below) at varying purchase prices dependent upon the actual cost to complete construction of Plant Vogtle Units 3 and 4 as compared to the EAC included in the nineteenth VCM report. The purchases will be at the option of the applicable Vogtle Owner and will occur during the month after such PTCs are earned.

Potential Funding to MEAG Project J

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

At the option of MEAG, as an alternative or supplement to Georgia Power's purchase of PTCs as described above, Georgia Power has agreed to provide up to $250 million in funding to MEAG for Project J in the form of advances

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(either advances under the Vogtle Joint Ownership Agreements or the purchase of MEAG Project J bonds, at the discretion of Georgia Power), subject to any required approvals of the Georgia PSC and the DOE.

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

Under the terms of the MEAG Term Sheet, Georgia Power may decline to provide any funding in the form of advances, including in the event of a failure to receive any required Georgia PSC or DOE approvals, and cancel the project in lieu of providing such funding.

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. As of September 30, 2018, Georgia Power had recovered approximately $1.8 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. Georgia Power expects to file on November 9, 2018 to increase the NCCR tariff by approximately $90 million annually, effective January 1, 2019, pending Georgia PSC approval.

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) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying 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,

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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 $25 million in 2017 and are estimated to have negative earnings impacts of approximately $100 million in 2018 and an aggregate of $680 million from 2019 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.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. On March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's final decision and denial of Georgia Watch's motion for reconsideration. Georgia Power believes the two appeals have no merit; however, an adverse outcome in either 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.

The Georgia PSC has approved eighteen VCM reports covering the periods through December 31, 2017, including total construction capital costs incurred through that date of $4.9 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds). On August 31, 2018, Georgia Power filed its nineteenth VCM report with the Georgia PSC, which requested approval of $578 million of construction capital costs incurred from January 1, 2018 through June 30, 2018.

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

See RISK FACTORS of Georgia Power in Item 1A herein and 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

As of September 30, 2018, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In September 2018, the DOE extended the conditional commitment to March 31, 2019. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements of Georgia Power under "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 (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and conditions to borrowing.

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

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Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Georgia Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.

Other Matters

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

The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) 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 Note (B) 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.

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 Note 1 to the financial statements of Georgia Power 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.

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

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

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In its order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

In the second quarter 2018, Georgia Power revised its base cost forecast and estimated contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for a total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds). Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC has stated the $7.3 billion estimate included in the seventeenth VCM proceeding does not represent a cost cap, Georgia Power did not seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast in the nineteenth VCM report filed with the Georgia PSC on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs included in the revised construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018.

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

As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule continue to increase significantly through the remainder of 2018 and into 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers 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 resolution of ITAAC and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

The ultimate outcome of these matters cannot be determined at this time. Any extension of the in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4 is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

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Given the significant complexity involved in estimating the future costs to complete construction and start-up of Plant Vogtle Units 3 and 4 and the significant management judgment necessary to assess the related uncertainties surrounding future rate recovery of any projected cost increases, as well as the potential impact on Georgia Power's results of operations and cash flows, Georgia Power considers these items to be critical accounting estimates. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information.

Recently Issued Accounting Standards

See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Georgia Power in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Georgia Power's recently adopted accounting standards.

In 2016, the FASB issued ASU No. 2016-02, which requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Georgia Power will adopt the new standard effective January 1, 2019.

Georgia Power has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Georgia Power expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Georgia Power expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Georgia Power also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.

Georgia Power is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Georgia Power has substantially completed its lease inventory and determined its most significant leases involve PPAs and real estate. While Georgia Power has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in recording lease liabilities and right-of-use assets on Georgia Power's balance sheet each totaling approximately $1.8 billion, with no material impact on Georgia Power's statement of income.

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 September 30, 2018. 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 $2.23 billion for the first nine months of 2018 compared to $1.48 billion for the corresponding period in 2017. The increase was primarily due to the timing of vendor and property tax payments, a decrease in current income taxes related to the Tax Reform Legislation, income tax refunds

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received, increased fuel cost recovery, and the timing of fossil fuel stock purchases, partially offset by payments of customer refunds primarily related to the Guarantee Settlement Agreement. Net cash used for investing activities totaled $2.21 billion for the first nine months of 2018 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities, including $0.9 billion related to the construction of Plant Vogtle Units 3 and 4. Net cash used for financing activities totaled $492 million for the first nine months of 2018 primarily due to payments of common stock dividends, the redemption and repurchase of senior notes, and pollution control revenue bond purchases, partially offset by capital contributions from 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 nine months of 2018 include an increase of $2.3 billion in paid-in capital primarily due to capital contributions received from Southern Company, a decrease of $1.6 billion in long-term debt (including securities due within one year) primarily due to the redemption and repurchase of senior notes and the purchase of pollution control revenue bonds, and an increase of $0.5 billion in property, plant, and equipment to comply with environmental standards and the construction of generation, transmission, and distribution facilities, net of the $1.1 billion charge related to the construction of Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

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 $511 million will be required through September 30, 2019 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.

Georgia Power's construction program is currently estimated to total approximately $3.5 billion for 2018, $3.6 billion for 2019, $2.8 billion for 2020, $2.7 billion for 2021, and $2.4 billion for 2022. These amounts include expenditures of approximately $1.4 billion, $1.4 billion, $0.9 billion, $1.0 billion, and $0.6 billion for the construction of Plant Vogtle Units 3 and 4 in 2018, 2019, 2020, 2021, and 2022, respectively. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $0.5 billion, $0.1 billion, $0.2 billion, $0.2 billion, and $0.2 billion for 2018, 2019, 2020, 2021, and 2022, respectively. These estimated expenditures do not include any potential compliance costs associated with pending regulation of CO₂ emissions from fossil fuel-fired electric generating units.

Georgia Power also anticipates costs associated with closure and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in Georgia Power's ARO liabilities. These costs, which are expected to change as Georgia Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $0.2 billion per year for 2018 through 2020 and $0.3 billion per year for 2021 and 2022. For information regarding expected changes to these cost estimates during the fourth quarter 2018, see FUTURE EARNINGS POTENTIAL – "Environmental Matters– Environmental Laws and Regulations – Coal Combustion Residuals" and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein. Also see Note 1 to the financial statements of Georgia Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information on AROs.

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 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 and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "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 the Loan Guarantee Agreement with the DOE, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. As of September 30, 2018, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. In July 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.

In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on March 31, 2019, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements of Georgia Power under "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 regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

At September 30, 2018, Georgia Power's current liabilities exceeded current assets by $552 million primarily due to long-term debt that is due within one year of $511 million. 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. Georgia Power intends to utilize operating cash flows, external security issuances, borrowings from financial institutions, and equity contributions from Southern

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Company to fund its short-term capital needs. Georgia Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.

At September 30, 2018, Georgia Power had approximately $380 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks was $1.75 billion at September 30, 2018, of which $1.74 billion was unused. This credit arrangement expires in 2022.

This bank credit arrangement contains a covenant that limits debt levels and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross-acceleration provision to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2018, Georgia Power was in compliance with this covenant. This bank credit arrangement does not contain a material adverse change clause at the time of borrowing.

Subject to applicable market conditions, Georgia Power expects to renew or replace this credit arrangement, as needed, prior to expiration. In connection therewith, Georgia Power may extend the maturity date and/or increase or decrease the lending commitments thereunder.

See Note 6 to the financial statements of Georgia Power 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 credit with banks is allocated to provide liquidity support to Georgia Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2018 was approximately $550 million. In addition, at September 30, 2018, Georgia Power had $345 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.

Details of short-term borrowings were as follows:

	Short-term Debt at September 30, 2018				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	$	102	2.4	%	$	260	2.3	%	$	480

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2018.

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 September 30, 2018, Georgia Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 September 30, 2018 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	87
Below BBB- and/or Baa3	$	1,025

Included in these amounts are certain agreements that could require collateral in the event that Georgia Power or Alabama Power (affiliate company of Georgia Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Georgia Power to access capital markets and would be likely to impact the cost at which it does so.

On February 28, 2018, Fitch downgraded the senior unsecured long-term debt rating of Georgia Power to A from A+ with a negative outlook. On August 9, 2018, Fitch downgraded the senior unsecured long-term debt rating of Georgia Power to A- from A. On September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and certain of its subsidiaries (including Georgia Power).

On August 8, 2018, Moody's downgraded the senior unsecured debt rating of Georgia Power to Baa1 from A3. On September 28, 2018, Moody's revised its rating outlook for Georgia Power from negative to stable.

As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Georgia Power, may be negatively impacted. The Tax Reform Settlement Agreement approved by the Georgia PSC on April 3, 2018 is expected to help mitigate these potential adverse impacts to certain credit metrics by allowing a higher retail equity ratio until the conclusion of Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Rate Plans" herein for additional information.

Financing Activities

In January 2018, Georgia Power repaid its outstanding $150 million and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively.

In April 2018, Georgia Power redeemed all $250 million aggregate principal amount of its Series 2008B 5.40% Senior Notes due June 1, 2018.

In May 2018, through cash tender offers, Georgia Power repurchased and retired $89 million of the $250 million aggregate principal amount outstanding of its Series 2007A 5.65% Senior Notes due March 1, 2037, $326 million of the $500 million aggregate principal amount outstanding of its Series 2009A 5.95% Senior Notes due February 1, 2039, and $335 million of the $600 million aggregate principal amount outstanding of its Series 2010B 5.40% Senior Notes due June 1, 2040, for an aggregate purchase price, excluding accrued and unpaid interest, of $902 million.

During 2018, Georgia Power purchased and held the following pollution control revenue bonds, which may be reoffered to the public at a later date:

• $104.6 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

• $173 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009

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

• $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

• $71.735 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2013

In 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.

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GULF POWER COMPANY

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GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	341		$	375		$	932		$	972
Wholesale revenues, non-affiliates	15			14			41			44
Wholesale revenues, affiliates	40			28			83			75
Other revenues	18			20			50			53
Total operating revenues	414			437			1,106			1,144
Operating Expenses:
Fuel	132			127			305			323
Purchased power	44			38			135			116
Other operations and maintenance	82			84			248			260
Depreciation and amortization	48			42			142			95
Taxes other than income taxes	33			33			91			88
Loss on Plant Scherer Unit 3	—			—			—			33
Total operating expenses	339			324			921			915
Operating Income	75			113			185			229
Other Income and (Expense):
Interest expense, net of amounts capitalized	(13		)	(13		)	(39		)	(37		)
Other income (expense), net	(3		)	3			—			7
Total other income and (expense)	(16		)	(10		)	(39		)	(30		)
Earnings Before Income Taxes	59			103			146			199
Income taxes (benefit)	(4		)	40			(1		)	78
Net Income	63			63			147			121
Dividends on Preference Stock	—			—			—			4
Net Income After Dividends on Preference Stock	$	63		$	63		$	147		$	117

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2018		2017		2018		2017
	(in millions)				(in millions)
Net Income	$	63	$	63	$	147	$	121
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $-, $-, and $(1), respectively	—		—		—		(1		)
Total other comprehensive income (loss)	—		—		—		(1		)
Comprehensive Income	$	63	$	63	$	147	$	120

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

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GULF POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2018			2017
	(in millions)
Operating Activities:
Net income	$	147		$	121
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	147			100
Deferred income taxes	(45		)	57
Loss on Plant Scherer Unit 3	—			33
Other, net	(10		)	(5		)
Changes in certain current assets and liabilities —
-Receivables	(5		)	(65		)
-Other current assets	9			18
-Accrued taxes	35			21
-Accrued compensation	(9		)	(10		)
-Over recovered regulatory clause revenues	39			(8		)
-Other current liabilities	10			10
Net cash provided from operating activities	318			272
Investing Activities:
Property additions	(207		)	(142		)
Cost of removal, net of salvage	(18		)	(16		)
Change in construction payables	5			(9		)
Other investing activities	(18		)	(6		)
Net cash used for investing activities	(238		)	(173		)
Financing Activities:
Increase (decrease) in notes payable, net	5			(268		)
Proceeds —
Common stock issued to parent	—			175
Capital contributions from parent company	40			7
Senior notes	—			300
Redemptions —
Preference stock	—			(150		)
Senior notes	—			(85		)
Payment of common stock dividends	(115		)	(94		)
Other financing activities	(1		)	(3		)
Net cash used for financing activities	(71		)	(118		)
Net Change in Cash, Cash Equivalents, and Restricted Cash	9			(19		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	28			56
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	37		$	37
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $- and $- capitalized for 2018 and 2017, respectively)	$	26		$	24
Income taxes, net	28			19
Noncash transactions — Accrued property additions at end of period	31			25

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

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GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2018			At December 31, 2017
	(in millions)
Current Assets:
Cash and cash equivalents	$	37		$	28
Receivables —
Customer accounts receivable	100			76
Unbilled revenues	69			67
Under recovered regulatory clause revenues	—			27
Affiliated	20			14
Other	5			7
Accumulated provision for uncollectible accounts	(1		)	(1		)
Fossil fuel stock	58			63
Materials and supplies	61			57
Other regulatory assets, current	47			56
Other current assets	13			21
Total current assets	409			415
Property, Plant, and Equipment:
In service	5,313			5,196
Less: Accumulated provision for depreciation	1,540			1,461
Plant in service, net of depreciation	3,773			3,735
Construction work in progress	152			91
Total property, plant, and equipment	3,925			3,826
Deferred Charges and Other Assets:
Deferred charges related to income taxes	30			31
Other regulatory assets, deferred	495			502
Other deferred charges and assets	46			23
Total deferred charges and other assets	571			556
Total Assets	$	4,905		$	4,797

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

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GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2018			At December 31, 2017
	(in millions)
Current Liabilities:
Notes payable	$	50		$	45
Accounts payable —
Affiliated	64			52
Other	67			75
Customer deposits	35			35
Accrued taxes	45			10
Accrued interest	20			9
Accrued compensation	30			39
Deferred capacity expense, current	22			22
Asset retirement obligations, current	43			37
Other regulatory liabilities, current	69			—
Other current liabilities	20			27
Total current liabilities	465			351
Long-term Debt	1,285			1,285
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	542			537
Deferred credits related to income taxes	380			458
Employee benefit obligations	96			102
Deferred capacity expense	81			97
Asset retirement obligations, deferred	121			105
Other cost of removal obligations	218			221
Other regulatory liabilities, deferred	51			43
Other deferred credits and liabilities	62			67
Total deferred credits and other liabilities	1,551			1,630
Total Liabilities	3,301			3,266
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — 7,392,717 shares	678			678
Paid-in capital	636			594
Retained earnings	291			259
Accumulated other comprehensive loss	(1		)	—
Total common stockholder's equity	1,604			1,531
Total Liabilities and Stockholder's Equity	$	4,905		$	4,797

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

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2018 vs. THIRD QUARTER 2017

AND

YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017

OVERVIEW

Gulf Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located in northwest Florida and to wholesale customers in the Southeast.

On May 20, 2018, Southern Company entered into a stock purchase agreement with NextEra Energy to sell Gulf Power for an aggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $1.3 billion), subject to certain adjustments. The completion of the sale is expected to occur in the first quarter 2019 and is subject to the satisfaction or waiver of certain closing conditions. The ultimate outcome of this matter cannot be determined at this time. See Note (J) to the Condensed Financial Statements under "Southern Company's Sale of Gulf Power" herein for additional information.

Many factors affect the opportunities, challenges, and risks of Gulf 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, reliability, restoration following major storms, fuel, and capital expenditures. Gulf 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 Gulf Power for the foreseeable future.

As a continuation of a settlement agreement approved by the Florida PSC in April 2017 (2017 Gulf Power Rate Case Settlement Agreement), on March 26, 2018, the Florida PSC approved a stipulation and settlement agreement among Gulf Power and three intervenors addressing the retail revenue requirement effects of the Tax Reform Legislation (Gulf Power Tax Reform Settlement Agreement).

The Gulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates implemented April 1, 2018 and also provided for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through a reduced fuel cost recovery rate over the remainder of 2018. Through September 30, 2018, approximately $53 million of this refund has been reflected in customer bills. As a result of the Gulf Power Tax Reform Settlement Agreement, the Florida PSC also approved an increase in Gulf Power's maximum equity ratio from 52.5% to 53.5% for all retail regulatory purposes.

As part of the Gulf Power Tax Reform Settlement Agreement, a limited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was initiated on April 30, 2018. On October 30, 2018, the Florida PSC approved a $9.6 million annual reduction in base rate revenues effective January 2019, which concluded this proceeding. Through September 30, 2018, Gulf Power has deferred $7 million of related 2018 tax benefits as a regulatory liability to be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.

On October 10, 2018, Hurricane Michael made landfall on the Gulf Coast of Florida causing substantial damage in Gulf Power's service territory. Gulf Power currently estimates the costs of repairing the damages to its transmission and distribution lines and uninsured facilities will total approximately $350 million to $400 million, which primarily will be charged to the property damage reserve or capitalized. At September 30, 2018, Gulf Power had a balance of approximately $48 million in its property damage reserve. In accordance with the 2017 Gulf Power Rate Case Settlement Agreement, Gulf Power can petition the Florida PSC to seek recovery of the costs associated with

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Hurricane Michael, along with replenishing the property damage reserve to approximately $40 million. The ultimate outcome of this matter cannot be determined at this time. See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Storm Damage Cost Recovery" herein for additional information.

Gulf Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$30	25.6

Gulf Power's net income after dividends on preference stock for the third quarter 2018 and the corresponding period in 2017 was $63 million. Net income reflects lower federal income tax expense as a result of the Tax Reform Legislation, substantially offset by a reduction in retail revenues related to the Gulf Power Tax Reform Settlement Agreement.

Gulf Power's net income after dividends on preference stock for year-to-date 2018 was $147 million compared to $117 million for the corresponding period in 2017. The increase was primarily due to higher retail base revenues effective July 2017 and the first quarter 2017 write-down of $32.5 million ($20 million after tax) of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with the 2017 Gulf Power Rate Case Settlement Agreement, partially offset by depreciation credits recognized in 2017. In addition, the increase in net income reflects lower federal income tax expense as a result of the Tax Reform Legislation, partially offset by a reduction in retail revenues related to the Gulf Power Tax Reform Settlement Agreement.

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information regarding the 2017 Gulf Power Rate Case Settlement Agreement.

Retail Revenues

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(34)	(9.1)	$(40)	(4.1)

In the third quarter 2018, retail revenues were $341 million compared to $375 million for the corresponding period in 2017. For year-to-date 2018, retail revenues were $932 million compared to $972 million for the corresponding period in 2017.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:

	Third Quarter 2018					Year-to-Date 2018
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	375				$	972
Estimated change resulting from –
Rates and pricing	(35		)	(9.3	)	(51		)	(5.2	)
Sales growth (decline)	(2		)	(0.6	)	2			0.2
Weather	6			1.6		16			1.6
Fuel and other cost recovery	(3		)	(0.8	)	(7		)	(0.7	)
Retail – current year	$	341		(9.1	)%	$	932		(4.1	)%

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under "Revenues" and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's retail base rate case and cost recovery clauses, including Gulf Power's fuel cost recovery, purchased power capacity recovery, environmental cost recovery, and energy conservation cost recovery clauses.

Revenues associated with changes in rates and pricing decreased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to a decrease in revenues effective January 1, 2018 due to the Gulf Power Tax Reform Settlement Agreement. In addition, the year-to-date 2018 amounts were partially offset by an increase in retail base rates effective July 2017 in accordance with the 2017 Gulf Power Rate Case Settlement Agreement.

Revenues attributable to changes in sales decreased in the third quarter 2018 when compared to the corresponding period in 2017. For the third quarter 2018, weather-adjusted KWH sales to residential customers decreased 3.9% due to lower customer usage, primarily resulting from efficiency improvements, partially offset by customer growth. Weather-adjusted KWH sales to commercial customers decreased 2.5% primarily due to lower energy usage resulting from energy efficiency improvements in appliances and lighting. KWH sales to industrial customers increased 4.8% for the third quarter 2018 primarily due to decreased customer cogeneration levels and other changes in customers' operations.

Revenues attributable to changes in sales increased for year-to-date 2018 when compared to the corresponding period in 2017. For year-to-date 2018, weather-adjusted KWH sales to residential customers were essentially flat due to lower customer usage, primarily resulting from efficiency improvements, offset by customer growth. Weather-adjusted KWH sales to commercial customers decreased 0.7% primarily due to lower energy usage resulting from energy efficiency improvements in appliances and lighting. KWH sales to industrial customers increased 1.3% year-to-date 2018 primarily due to changes in customer cogeneration levels.

Fuel and other cost recovery revenues decreased in the third quarter 2018 when compared to the corresponding period in 2017, primarily due to lower recoverable costs under the fuel cost recovery clause. Fuel and other cost recovery revenues decreased year-to-date 2018 when compared to the corresponding period in 2017, primarily due to lower recoverable costs under the purchased power capacity and fuel cost recovery clauses. Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, the difference between projected and actual costs and revenues related to energy conservation and environmental compliance, and a credit for certain wholesale revenues as a result of the 2017 Gulf Power Rate Case Settlement Agreement.

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" and " – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information regarding cost recovery clauses and the 2017 Gulf Power Rate Case Settlement Agreement, respectively. Also see FUTURE EARNINGS

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

POTENTIAL – "Retail Regulatory Matters – Retail Base Rate Case" herein for additional information regarding the Gulf Power Tax Reform Settlement Agreement.

Wholesale Revenues – Affiliates

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$12	42.9	$8	10.7

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 the revenue related to these energy sales generally offsets the cost of energy sold.

In the third quarter 2018, wholesale revenues from sales to affiliates were $40 million compared to $28 million for the corresponding period in 2017. The increase was primarily due to a 31.6% increase in KWH sales primarily resulting from increased generation to serve territorial load driven by warmer weather in the third quarter 2018 and a 7.9% increase in the price of energy sold to affiliates attributable to increased sales during peak load hours.

For year-to-date 2018, wholesale revenues from sales to affiliates were $83 million compared to $75 million for the corresponding period in 2017. The increase was primarily due to a 24.5% increase in the price of energy sold due to dispatching higher-priced generating resources driven by the colder weather in January 2018 and warmer weather in the third quarter 2018. Partially offsetting this increase was an 11.3% decrease in KWH sales primarily resulting from lower availability due to planned outages at Gulf Power generating units in the first half of 2018.

Fuel and Purchased Power Expenses

	Third Quarter 2018 vs. Third Quarter 2017			Year-to-Date 2018 vs. Year-to-Date 2017
	(change in millions)		(% change)	(change in millions)			(% change)
Fuel	$	5	3.9	$	(18	)	(5.6	)
Purchased power	6		15.8	19			16.4
Total fuel and purchased power expenses	$	11		$	1

In the third quarter 2018, total fuel and purchased power expenses were $176 million compared to $165 million for the corresponding period in 2017. The increase was primarily the result of a $21 million increase related to the volume of KWHs generated and purchased, partially offset by a $10 million decrease related to the lower average cost of fuel and purchased power due to lower natural gas prices.

For year-to-date 2018, total fuel and purchased power expenses were $440 million compared to $439 million for the corresponding period in 2017. The increase was primarily the result of a $31 million increase related to volume of KWHs generated and purchased, partially offset by a $30 million decrease related to the lower average cost of fuel and purchased power resulting from lower natural gas prices.

Fuel and purchased power transactions do not have a significant impact on earnings since energy and capacity expenses are generally offset by energy and capacity revenues through Gulf Power's fuel and purchased power capacity cost recovery clauses and long-term wholesale contracts. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" and " – Purchased Power Capacity Recovery" in Item 8 of the Form 10-K for additional information.

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

	Third Quarter 2018	Third Quarter 2017	Year-to-Date 2018	Year-to-Date 2017
Total generation (in millions of KWHs)	2,992	2,780	7,002	7,000
Total purchased power(in millions of KWHs)	2,016	1,686	4,997	4,362
Sources of generation (percent) –
Coal	61	59	53	55
Gas	39	41	47	45
Cost of fuel, generated (in cents per net KWH) –
Coal	3.06	3.04	3.12	3.15
Gas	3.40	3.71	3.25	3.60
Average cost of fuel, generated(in cents per net KWH)	3.19	3.31	3.18	3.35
Average cost of purchased power (in cents per net KWH)(*)	3.99	4.32	4.33	4.70

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

Fuel

In the third quarter 2018, fuel expense was $132 million compared to $127 million for the corresponding period in 2017. The increase was primarily due to a 7.6% increase in the volume of KWHs generated primarily to serve higher territorial load driven by warmer weather, partially offset by a 3.6% decrease in the average cost of fuel resulting from lower natural gas prices.

For year-to-date 2018, fuel expense was $305 million compared to $323 million for the corresponding period in 2017. The decrease was primarily due to a 5.1% decrease in the average cost of fuel resulting from lower natural gas prices.

Purchased Power

In the third quarter 2018, purchased power expense was $44 million compared to $38 million for the corresponding period in 2017. The increase was primarily due to a 19.6% increase in the volume of KWHs purchased due to higher territorial load driven by warmer weather, partially offset by a 7.6% decrease in the average cost of purchased power due to lower natural gas prices.

For year-to-date 2018, purchased power expense was $135 million compared to $116 million for the corresponding period in 2017. The increase was primarily due to a 14.6% increase in the volume of KWHs purchased primarily due to higher territorial load driven by colder weather in January 2018 and warmer weather in the third quarter 2018, partially offset by a 7.9% decrease in the average cost of purchased power due to lower natural gas prices.

Energy purchases from non-affiliates and 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. Affiliate purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.

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Other Operations and Maintenance Expenses

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	(2.4)	$(12)	(4.6)

For year-to-date 2018, other operations and maintenance expenses were $248 million compared to $260 million for the corresponding period in 2017. The decrease was primarily due to decreases of $11 million in planned and routine generation maintenance expenses, including environmental expenditures, $3 million in energy service expenses, and $6 million in employee compensation and benefits, partially offset by a $9 million increase to the property damage reserve accrual. See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the Form 10-K for additional information.

Expenses from energy services did not have a significant impact on earnings since they were generally offset by

associated revenues. Environmental compliance expenses did not have a significant impact on earnings since they were offset by environmental revenues through Gulf Power's environmental cost recovery clause. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery" in Item 8 of the Form 10-K for additional information.

Depreciation and Amortization

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$6	14.3	$47	49.5

In the third quarter 2018, depreciation and amortization was $48 million compared to $42 million for the corresponding period in 2017. The increase was primarily due to an increase in depreciation rates as authorized by the 2017 Gulf Power Rate Case Settlement Agreement.

For year-to-date 2018, depreciation and amortization was $142 million compared to $95 million for the corresponding period in 2017. The increase was primarily due to an increase in depreciation rates as authorized by the 2017 Gulf Power Rate Case Settlement Agreement and depreciation credits of $34 million recognized in year-to-date 2017 as authorized in a settlement agreement approved by the Florida PSC in 2013. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.

Loss on Plant Scherer Unit 3

In the first quarter 2017, Gulf Power recorded a $32.5 million write-down related to its ownership of Plant Scherer Unit 3 in accordance with the 2017 Gulf Power Rate Case Settlement Agreement. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.

Income Taxes (Benefit)

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(44)	(110.0)	$(79)	(101.3)

In the third quarter 2018, income tax benefit was $4 million compared to tax expense of $40 million for the corresponding period in 2017. For year-to-date 2018, income tax benefit was $1 million compared to income tax expense of $78 million for the corresponding period in 2017. The changes were primarily due to the reduction in the

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federal income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation as well as lower pre-tax earnings.

See Note (H) to the Condensed Financial Statements under "Effective Tax Rate" herein for additional information. Also see Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for more information regarding the 2017 Gulf Power Rate Case Settlement Agreement.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Gulf Power's future earnings potential. The level of Gulf Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Gulf Power's business of providing electric service. These factors include Gulf 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 limited projected demand growth over the next several years. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies due to changes in the minimum allowable equipment efficiencies along with the continuation of changes in customer behavior, 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, 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 Gulf 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 Gulf Power in Item 7 of the Form 10-K.

On May 20, 2018, Southern Company entered into a stock purchase agreement with NextEra Energy to sell all of the capital stock of Gulf Power for an aggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $1.3 billion), subject to (i) customary adjustments for indebtedness and working capital and (ii) reduction by the amount (if any) by which Gulf Power fails to meet a specified capital expenditure target. The completion of the sale is expected to occur in the first quarter 2019 and is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) approval by the FERC and the Federal Communications Commission, (ii) the entry into certain ancillary agreements, including transmission-related agreements and a transition services agreement, among the parties and their affiliates, and (iii) other customary closing conditions. See Note (J) to the Condensed Financial Statements under "Southern Company's Sale of Gulf Power" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

Environmental Matters

Gulf 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. Gulf Power maintains comprehensive environmental compliance and GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. A major portion of these costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed below will depend on various factors, such as state adoption and

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implementation of requirements, the availability and cost of any deployed technology, and the outcome of pending and/or future legal challenges.

New or revised environmental laws and regulations could affect many areas of Gulf 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 fully recovered in rates on a timely basis or through long-term wholesale agreements. The State of Florida has statutory provisions that allow a utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Gulf Power's current long-term wholesale agreements contain provisions that permit charging the customer with costs incurred as a result of changes in environmental laws and 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 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," "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery," and "Other Matters" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information, including a discussion on the State of Florida's statutory provisions on environmental cost recovery.

Environmental Laws and Regulations

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.

On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.

Coal Combustion Residuals

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).

The EPA published certain amendments to the CCR Rule, which became effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. Specific site impacts are being evaluated by Gulf Power.

On October 15, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a mandate that broadens the CCR Rule to regulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that the EPA will issue a series of rulemakings to address this court action. Gulf Power is evaluating the extent of potential impacts on legacy units but anticipates no significant impacts to its ongoing CCR strategy due to this mandate. The ultimate impact of these changes will not be known until the EPA rulemaking and any legal challenges are finalized.

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Georgia Power continues to perform engineering studies related to its plans to close the ash ponds at all of its generating plants, including Plant Scherer Unit 3, which is jointly owned with Gulf Power, in compliance with federal and state CCR rules. Georgia Power also continues to refine its closure strategy and cost estimates for each ash pond and is preparing permit applications as required by the State of Georgia CCR rule. While Gulf Power believes its recorded liability for ash pond closures appropriately reflects its obligations under the current closure strategy elected for Plant Scherer Unit 3, changes to such strategy and cost estimate would likely result in additional closure costs which would increase Gulf Power's ARO liability. It is not currently possible to quantify the impacts of any increase related to a change in closure strategy and/or ongoing engineering studies for the current closure strategy, and the timing of future cash outflows is indeterminable at this time; however, the impact on the ARO liability is expected to be material. As permit applications advance, engineering studies continue, and the timing of the ash pond closure for Plant Scherer Unit 3 develops further during the fourth quarter 2018, Gulf Power will record any necessary changes to its ARO liability related to its share of Plant Scherer Unit 3. Gulf Power expects to continue to periodically update these cost estimates, which could increase further, as additional information becomes available. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

Absent continued recovery of ARO costs through regulated rates, Gulf Power'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.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Gulf Power in Item 7 of the Form 10-K for additional information.

On August 31, 2018, the EPA published a proposed Clean Power Plan replacement rule known as the Affordable Clean Energy rule (ACE Rule), which would require states to develop unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of September 30, 2018, Gulf Power has ownership interests inseven fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to Gulf Power is currently unknown and will depend on changes between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal proceedings.

Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time.

FERC Matters

Market-Based Rate Authority

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Gulf Power in Item 7 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies' (including Gulf Power's) and Southern Power's 2014 and 2017 triennial market power analyses.

On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies (including Gulf Power) and Southern Power satisfy the FERC's standards for market-based

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rates. On May 9, 2018, the traditional electric operating companies (including Gulf Power) and Southern Power made the compliance filing required by the order. These proceedings are concluded.

Open Access Transmission Tariff

On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies (including Gulf Power) claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Gulf Power's) open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Gulf Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material to Gulf Power's results of operations. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Gulf Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. Gulf Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation and demand side management programs, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through base rates. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information. The recovery balance of each regulatory clause for Gulf Power is reported in Note (B) to the Condensed Financial Statements herein.

Storm Damage Cost Recovery

See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the Form 10-K for information on how Gulf Power maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generating facilities and other property.

On October 10, 2018, Hurricane Michael made landfall on the Gulf Coast of Florida causing substantial damage in Gulf Power's service territory. Gulf Power currently estimates the costs of repairing the damages to its transmission and distribution lines and uninsured facilities will total approximately $350 million to $400 million, which primarily will be charged to the property damage reserve or capitalized. At September 30, 2018, Gulf Power had a balance of approximately $48 million in its property damage reserve. In accordance with the 2017 Gulf Power Rate Case Settlement Agreement, Gulf Power can petition the Florida PSC to seek recovery of the costs associated with Hurricane Michael, along with replenishing the property damage reserve to approximately $40 million. Any recovery from customers would begin, on an interim basis, 60 days following the filing of the cost recovery petition. The ultimate outcome of this matter cannot be determined at this time.

Retail Base Rate Case

As a continuation of the 2017 Gulf Power Rate Case Settlement Agreement, on March 26, 2018, the Florida PSC approved the Gulf Power Tax Reform Settlement Agreement.

The Gulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates implemented April 1, 2018 and also provided for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to

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normalization) deferred tax liabilities through a reduced fuel cost recovery rate over the remainder of 2018. Through September 30, 2018, approximately $53 million of this refund has been reflected in customer bills. As a result of the Gulf Power Tax Reform Settlement Agreement, the Florida PSC also approved an increase in Gulf Power's maximum equity ratio from 52.5% to 53.5% for all retail regulatory purposes.

As part of the Gulf Power Tax Reform Settlement Agreement, a limited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was initiated on April 30, 2018. On October 30, 2018, the Florida PSC approved a $9.6 million annual reduction in base rate revenues effective January 2019, which concluded this proceeding. Through September 30, 2018, Gulf Power has deferred $7 million of related 2018 tax benefits as a regulatory liability to be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.

Cost Recovery Clauses

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Cost Recovery Clauses" herein for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC.

On November 5, 2018, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2019. The net effect of the approved changes is a $38 million decrease in annual revenues effective in January 2019, the majority of which will be offset by related expense decreases.

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Gulf Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.

Other Matters

Gulf Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. Gulf 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 natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) 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 Gulf Power's financial statements. See Note (B) 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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ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Gulf Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Gulf Power 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 Gulf 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 Gulf Power in Item 7 of the Form 10-K for a complete discussion of Gulf Power's critical accounting policies and estimates.

Recently Issued Accounting Standards

See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Gulf Power in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Gulf Power's recently adopted accounting standards.

In 2016, the FASB issued ASU No. 2016-02, which requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Gulf Power will adopt the new standard effective January 1, 2019.

Gulf Power has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Gulf Power expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Gulf Power expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Gulf Power also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.

Gulf Power is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Gulf Power has substantially completed its lease inventory and determined its most significant leases involve PPAs and real estate. While Gulf Power has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in recording lease liabilities and right-of-use assets on Gulf Power's balance sheet each totaling approximately $200 million, with no material impact on Gulf Power's statement of income.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Gulf Power in Item 7 of the Form 10-K for additional information. Gulf Power's financial condition remained stable at September 30, 2018. Gulf 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.

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Net cash provided from operating activities totaled $318 million for the first nine months of 2018 compared to $272 million for the corresponding period in 2017. The $46 million increase was primarily due to increased fuel cost recovery. Net cash used for investing activities totaled $238 million in the first nine months of 2018 primarily due to property additions. Net cash used for financing activities totaled $71 million for the first nine months of 2018 primarily due to the payment of common stock dividends, partially offset by capital contributions from 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 nine months of 2018 include an increase of $99 million in property, plant, and equipment primarily due to additions at generation and distribution facilities; an increase of $69 million in other regulatory liabilities, current primarily due to over recovered cost recovery balances; and a decrease of $78 million in deferred credits related to income taxes primarily as a result of the Gulf Power Tax Reform Settlement Agreement. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Retail Base Rate Case" herein for additional information regarding the Gulf Power Tax Reform Settlement Agreement.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power's capital requirements and contractual obligations. There are no scheduled maturities of long-term debt through September 30, 2019. See "Financing Activities" 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 generating units, to meet regulatory requirements; changes in the expected environmental compliance programs; changes in FERC rules and regulations; Florida PSC approvals; 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

Gulf Power plans to obtain the funds required 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 regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Gulf Power in Item 7 of the Form 10-K for additional information.

At September 30, 2018, Gulf Power's current liabilities exceeded current assets by $56 million. Gulf Power's current liabilities may 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.

Gulf Power intends to utilize operating cash flows, external security issuances, and borrowings from financial institutions to fund its short-term capital needs. Gulf Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet short-term liquidity needs, including funding needs related to Hurricane Michael. See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Storm Damage Cost Recovery" herein for additional information.

129

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At September 30, 2018, Gulf Power had approximately $37 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2018 were as follows:

Expires										Executable Term Loans		Expires Within One Year
2018		2019		2020		Total		Unused		One Year		Term Out		No Term Out
(in millions)
$	20	$	25	$	235	$	280	$	280	$	45	$	45	$	—

See Note 6 to the financial statements of Gulf Power 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 contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) of Gulf Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Gulf Power defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2018, Gulf Power was in compliance with all such covenants. A portion ($40 million) of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

Subject to applicable market conditions, Gulf Power expects to renew or replace its bank credit arrangements, as needed, prior to expiration. In connection therewith, Gulf Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

A portion of the $280 million unused credit arrangements with banks is allocated to provide liquidity support to Gulf 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 September 30, 2018 was approximately $82 million. In addition, at September 30, 2018, Gulf Power had approximately $58 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.

Gulf 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 Gulf Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Gulf Power are loaned directly to Gulf 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 on the balance sheets.

Details of short-term borrowings were as follows:

	Short-term Debt at September 30, 2018				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	$	50	2.5	%	$	59	2.3	%	$	136

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2018.

Gulf Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank loans, and operating cash flows.

130

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Credit Rating Risk

At September 30, 2018, Gulf 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 transportation and storage, and energy price risk management.

The maximum potential collateral requirements under these contracts at September 30, 2018 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	117
Below BBB- and/or Baa3	$	423

Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or Georgia Power (affiliate companies of Gulf 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 Gulf Power to access capital markets and would be likely to impact the cost at which it does so.

On May 21, 2018, S&P revised its rating outlook for Gulf Power from negative to stable.

As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Gulf Power, may be negatively impacted. The Gulf Power Tax Reform Settlement Agreement is expected to help mitigate these potential adverse impacts to Gulf Power's credit metrics by allowing a maximum equity ratio of 53.5% for all retail regulatory purposes. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power" herein for additional information.

Financing Activities

Gulf Power did not issue or redeem any securities during the nine months ended September 30, 2018.

In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm recovery, Gulf 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.

131

MISSISSIPPI POWER COMPANY

132

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2018			2017		2018			2017
	(in millions)					(in millions)
Operating Revenues:
Retail revenues	$	254		$	243	$	660		$	665
Wholesale revenues, non-affiliates	65			72		184			196
Wholesale revenues, affiliates	28			21		81			40
Other revenues	11			5		31			14
Total operating revenues	358			341		956			915
Operating Expenses:
Fuel	116			120		312			301
Purchased power	11			6		27			20
Other operations and maintenance	80			68		222			213
Depreciation and amortization	42			39		126			120
Taxes other than income taxes	28			25		83			77
Estimated loss on Kemper IGCC	1			34		45			3,155
Total operating expenses	278			292		815			3,886
Operating Income (Loss)	80			49		141			(2,971		)
Other Income and (Expense):
Allowance for equity funds used during construction	—			1		—			72
Interest expense, net of amounts capitalized	(19		)	13		(59		)	(23		)
Other income (expense), net	—			1		28			4
Total other income and (expense)	(19		)	15		(31		)	53
Earnings (Loss) Before Income Taxes	61			64		110			(2,918		)
Income taxes (benefit)	14			24		23			(885		)
Net Income (Loss)	47			40		87			(2,033		)
Dividends on Preferred Stock	—			—		1			1
Net Income (Loss) After Dividends on Preferred Stock	$	47		$	40	$	86		$	(2,034	)

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2018		2017			2018			2017
	(in millions)					(in millions)
Net Income (Loss)	$	47	$	40		$	87		$	(2,033	)
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $-, $(1), and $-, respectively	—		(1		)	(1		)	—
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $-, and $-, respectively	—		—			1			1
Total other comprehensive income (loss)	—		(1		)	—			1
Comprehensive Income (Loss)	$	47	$	39		$	87		$	(2,032	)

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

133

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2018			2017
	(in millions)
Operating Activities:
Net income (loss)	$	87		$	(2,033	)
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	129			144
Deferred income taxes	420			(1,159		)
Allowance for equity funds used during construction	—			(72		)
Estimated loss on Kemper IGCC	21			3,148
Other, net	5			(26		)
Changes in certain current assets and liabilities —
-Receivables	(46		)	438
-Fossil fuel stock	(2		)	21
-Other current assets	(5		)	(9		)
-Accounts payable	(3		)	(21		)
-Accrued taxes	57			20
-Accrued compensation	(9		)	(12		)
-Over recovered regulatory clause revenues	20			(47		)
-Other current liabilities	(18		)	(31		)
Net cash provided from operating activities	656			361
Investing Activities:
Property additions	(117		)	(411		)
Construction payables	(9		)	(47		)
Payments pursuant to LTSAs	(28		)	(10		)
Other investing activities	(16		)	(15		)
Net cash used for investing activities	(170		)	(483		)
Financing Activities:
Decrease in notes payable, net	(4		)	(23		)
Proceeds —
Senior notes	600			—
Short-term borrowings	300			113
Capital contributions from parent company	(2		)	1,002
Long-term debt to parent company	—			40
Redemptions —
Other long-term debt	(900		)	(300		)
Short-term borrowings	(300		)	(109		)
Pollution control revenue bonds	(43		)	—
Long-term debt to parent company	—			(591		)
Other financing activities	(6		)	(3		)
Net cash provided from (used for) financing activities	(355		)	129
Net Change in Cash, Cash Equivalents, and Restricted Cash	131			7
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	248			224
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	379		$	231
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $57 and $73, net of $- and $28 capitalized for 2018 and 2017, respectively)	$	57		$	45
Income taxes, net	(483		)	(209		)
Noncash transactions — Accrued property additions at end of period	23			32

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

134

MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2018		At December 31, 2017
	(in millions)
Current Assets:
Cash and cash equivalents	$	379	$	248
Receivables —
Customer accounts receivable	49		36
Unbilled revenues	43		41
Income taxes receivable, current	3		4
Affiliated	35		16
Other accounts and notes receivable	47		12
Fossil fuel stock	19		17
Materials and supplies, current	52		44
Other regulatory assets, current	110		125
Other current assets	4		9
Total current assets	741		552
Property, Plant, and Equipment:
In service	4,819		4,773
Less: Accumulated provision for depreciation	1,389		1,325
Plant in service, net of depreciation	3,430		3,448
Construction work in progress	106		84
Total property, plant, and equipment	3,536		3,532
Other Property and Investments	24		30
Deferred Charges and Other Assets:
Deferred charges related to income taxes	34		35
Other regulatory assets, deferred	466		437
Accumulated deferred income taxes	—		247
Other deferred charges and assets	16		33
Total deferred charges and other assets	516		752
Total Assets	$	4,817	$	4,866

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

135

MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2018			At December 31, 2017
	(in millions)
Current Liabilities:
Securities due within one year	$	204		$	989
Notes payable	—			4
Accounts payable —
Affiliated	55			59
Other	90			96
Accrued taxes —
Accrued income taxes	75			40
Other accrued taxes	74			101
Accrued interest	21			16
Accrued compensation	30			39
Accrued plant closure costs	30			35
Asset retirement obligations, current	41			37
Other current liabilities	56			47
Total current liabilities	676			1,463
Long-term Debt	1,532			1,097
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	193			—
Deferred credits related to income taxes	420			372
Employee benefit obligations	111			116
Asset retirement obligations, deferred	136			137
Other cost of removal obligations	181			178
Other regulatory liabilities, deferred	75			79
Other deferred credits and liabilities	17			33
Total deferred credits and other liabilities	1,133			915
Total Liabilities	3,341			3,475
Redeemable Preferred Stock	33			33
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 1,130,000 shares
Outstanding — 1,121,000 shares	38			38
Paid-in capital	4,528			4,529
Accumulated deficit	(3,119		)	(3,205		)
Accumulated other comprehensive loss	(4		)	(4		)
Total common stockholder's equity	1,443			1,358
Total Liabilities and Stockholder's Equity	$	4,817		$	4,866

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

136

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2018 vs. THIRD QUARTER 2017

AND

YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017

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 to operate in a constructive regulatory environment that provides timely recovery of prudently-incurred costs. These costs include those related to reliability, fuel, and stringent environmental standards, as well as ongoing capital and operations and maintenance expenditures and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.

On July 27, 2018, Mississippi Power and the Mississippi Public Utilities Staff (MPUS) entered into a settlement agreement with respect to the 2018 PEP filing and all unresolved PEP filings for prior years (PEP Settlement Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement, which result in approximately $21.6 million in additional revenue annually, became effective with the first billing cycle of September 2018.

On August 3, 2018, Mississippi Power and the MPUS entered into a settlement agreement to increase rates approximately $17 million annually with respect to the 2018 ECO Plan filing (ECO Settlement Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the ECO Settlement Agreement became effective with the first billing cycle of September 2018.

The PEP and ECO Plan rates are expected to continue through the conclusion of the next base rate proceeding which is scheduled to be filed in the fourth quarter 2019 (2019 Base Rate Case).

On May 8, 2018, the Mississippi PSC issued an order to begin an operations review of Mississippi Power, which began in August 2018, with the final report expected by February 28, 2019. Mississippi Power expects that the review will include, but not be limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time.

See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power" herein for additional information.

On October 2, 2018, the Mississippi PSC approved the executed agreements between Mississippi Power and its largest retail customer, Chevron Products Company (Chevron), for Mississippi Power to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The new agreements are not expected to have a material impact on earnings. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "General" of Mississippi Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information.

As of September 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the third quarter 2018 and $45 million ($34 million after tax) for year-to-date 2018, primarily resulting from the abandonment and related closure activities 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 to cost up to $20 million pre-tax (excluding salvage, net of dismantlement costs), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $2 million for the remainder of 2018, $8 million in

137

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.

On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP), as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costs related to the Kemper County energy facility (Kemper Settlement Docket). Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being thetwo-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adverse impact on customer rates.

For additional information on the Kemper County energy facility, see Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility" and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein.

In March 2018, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $100 million was repaid in the third quarter 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.

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 after dividends on preferred stock.

RESULTS OF OPERATIONS

Net Income (Loss)

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$7	17.5	$2,120	N/M

N/M - Not meaningful

Mississippi Power's net income after dividends on preferred stock for the third quarter 2018 was $47 million compared to $40 million for the corresponding period in 2017. The increase in net income was primarily due to an increase in retail revenues as a result of PEP and ECO Plan rate increases that became effective with the first billing cycle of September 2018 and lower pre-tax charges associated with the Kemper IGCC, partially offset by an increase in operations and maintenance expenses and interest expense, net of amounts capitalized.

Mississippi Power's net income after dividends on preferred stock for year-to-date 2018 was $86 million compared to a loss of $2.03 billion for the corresponding period in 2017. The increase in net income is primarily attributable

138

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

to lower pre-tax charges associated with the Kemper IGCC, partially offset by the cessation of AFUDC equity related to the Kemper IGCC in the second quarter 2017 and higher interest expense, net of amounts capitalized.

See Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein for additional information regarding the Kemper IGCC.

Retail Revenues

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$11	4.5	$(5)	(0.8)

In the third quarter 2018, retail revenues were $254 million compared to $243 million for the corresponding period in 2017. For year-to-date 2018, retail revenues were $660 million compared to $665 million for the corresponding period in 2017.

Details of the changes in retail revenues were as follows:

	Third Quarter 2018					Year-to-Date 2018
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	243				$	665
Estimated change resulting from –
Rates and pricing	11			4.5	%	(3		)	(0.5	)%
Sales growth	3			1.3		1			0.2
Weather	2			0.8		12			1.8
Fuel and other cost recovery	(5		)	(2.1	)	(15		)	(2.3	)
Retail – current year	$	254		4.5	%	$	660		(0.8	)%

Revenues associated with changes in rates and pricing increased in the third quarter 2018 when compared to the corresponding period in 2017 primarily due to the PEP and ECO Plan rate changes that became effective for the first billing cycle of September 2018 resulting in retail revenue increases of $4 million and $9 million, respectively. In addition, as a result of the PEP Settlement Agreement, Mississippi Power recognized revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing, partially offset by the recognition of regulatory liabilities of $5 million and $2 million related to the equity ratio provisions of the PEP and ECO Settlement Agreements, respectively.

Revenues associated with changes in rates and pricing decreased year-to-date 2018 when compared to the corresponding period in 2017 primarily due to a decrease in annual retail revenues of $12 million for lower base rates related to the Kemper County energy facility that became effective for the first billing cycle of April 2018 and recognition in 2018 of regulatory liabilities of $5 million and $2 million related to the equity ratio provisions of the PEP and ECO Settlement Agreements, respectively, partially offset by higher retail revenues of $5 million for PEP and ECO Plan rates that became effective with the first billing cycle of September 2018, recognition of $5 million previously reserved in connection with the 2012 PEP lookback filing as a result of the PEP Settlement Agreement, and the recognition in the third quarter 2017 of a $7 million regulatory liability.

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" and " – Environmental Compliance Overview Plan" and "Kemper County Energy Facility – Rate Recovery" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.

Revenues attributable to changes in sales increased for the third quarter and year-to-date 2018 compared to the corresponding periods in 2017. Weather-adjusted residential and commercial KWH sales increased 2.7% and 1.0%,

139

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

respectively, in the third quarter 2018 due to increased customer usage and slight customer growth. Weather-adjusted residential KWH sales increased 1.1% year-to-date 2018 due to increased customer usage. Weather-adjusted commercial KWH sales remained relatively flat year-to-date 2018. Industrial KWH sales increased 2.0% and 0.4% for the third quarter and year-to-date 2018, respectively, primarily due to increased usage by several large industrial customers.

Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2018 when compared to the corresponding periods in 2017 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.

Wholesale Revenues – Non-Affiliates

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(7)	(9.7)	$(12)	(6.1)

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.

In the third quarter 2018, wholesale revenues from sales to non-affiliates were $65 million compared to $72 million for the corresponding period in 2017. For year-to-date 2018, wholesale revenues from sales to non-affiliates were $184 million compared to $196 million for the corresponding period in 2017. These decreases primarily resulted from a decrease in revenue under the Shared Services Agreement (SSA) between Mississippi Power and Cooperative Energy of $6 million and $16 million in the third quarter and year-to-date 2018, respectively, as a result of transmission revenue now being recovered under the Open Access Transmission Tariff (OATT) and included in other revenues on the statements of operations. The year-to-date 2018 decrease was partially offset by an increase in sales due to colder weather in January 2018 and warmer weather during the second and third quarters 2018.

Wholesale Revenues – Affiliates

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$7	33.3	$41	N/M

N/M - Not meaningful

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.

140

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the third quarter 2018, wholesale revenues from sales to affiliates were $28 million compared to $21 million for the corresponding period in 2017. For year-to-date 2018, wholesale revenues from sales to affiliates were $81 million compared to $40 million for the corresponding period in 2017. These increases were primarily due to increases in KWH sales due to increased availability of Mississippi Power's lower cost generation resources to serve the Southern Company system's territorial load in 2018 as compared to 2017.

Other Revenues

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$6	N/M	$17	N/M

N/M - Not meaningful

In the third quarter 2018, other revenues were $11 million compared to $5 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $31 million compared to $14 million for the corresponding period in 2017. These increases were primarily due to increases in transmission revenue related to SSA customers now being recovered under the OATT of $6 million and $16 million in the third quarter and year-to-date 2018, respectively.

Fuel and Purchased Power Expenses

	Third Quarter 2018 vs. Third Quarter 2017				Year-to-Date 2018 vs. Year-to-Date 2017
	(change in millions)			(% change)	(change in millions)		(% change)
Fuel	$	(4	)	(3.3)	$	11	3.7
Purchased power	5			83.3	7		35.0
Total fuel and purchased power expenses	$	1			$	18

In the third quarter 2018, total fuel and purchased power expenses were $127 million compared to $126 million for the corresponding period in 2017. The increase was primarily due to an $11 million increase in the volume of KWHs generated and purchased, partially offset by a $10 million decrease in the cost of natural gas and purchased power.

For year-to-date 2018, total fuel and purchased power expenses were $339 million compared to $321 million for the corresponding period in 2017. The increase was primarily due to a $39 million increase in the volume of KWHs generated and purchased, partially offset by a $20 million decrease in the cost of natural gas and purchased power.

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

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

	Third Quarter 2018	Third Quarter 2017	Year-to-Date 2018	Year-to-Date 2017
Total generation (in millions of KWHs)	4,581	4,453	12,665	11,542
Total purchased power (in millions of KWHs)(*)	348	164	781	527
Sources of generation (percent) –
Coal	8	8	7	8
Gas	92	92	93	92
Cost of fuel, generated (in cents per net KWH)–
Coal	3.51	3.80	3.50	3.60
Gas	2.58	2.77	2.57	2.72
Average cost of fuel, generated (in cents per net KWH)	2.66	2.86	2.63	2.80
Average cost of purchased power (in cents per net KWH)(*)	3.18	3.74	3.47	3.78

(*) Year-to-date 2017 includes energy produced during the test period for the Kemper IGCC and accounted for in accordance with FERC guidance.

Fuel

In the third quarter 2018, fuel expense was $116 million compared to $120 million for the corresponding period in 2017. The decrease was primarily due to a 6.7% decrease in the cost of natural gas, partially offset by a 3.2% increase in the volume of KWHs generated due to warmer weather in the third quarter 2018.

For year-to-date 2018, fuel expense was $312 million compared to $301 million for the corresponding period in 2017. The increase was primarily due to a 10.3% increase in the volume of KWHs generated due to colder weather in January 2018 and warmer weather during the second and third quarters 2018, partially offset by a 5.7% decrease in the cost of natural gas.

Purchased Power

In the third quarter 2018, purchased power expense was $11 million compared to $6 million for the corresponding period in 2017. The increase was primarily due to a $7 million increase in the volume of KWHs purchased, partially offset by a $2 million decrease in the cost of purchased power.

For year-to-date 2018, purchased power expense was $27 million compared to $20 million for the corresponding period in 2017. The increase was primarily due to a $9 million increase in the volume of KWHs purchased, partially offset by a $2 million decrease in the cost of purchased power.

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

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$12	17.6	$9	4.2

In the third quarter 2018, other operations and maintenance expenses were $80 million compared to $68 million for the corresponding period in 2017. For year-to-date 2018, other operations and maintenance expenses were $222 million compared to $213 million for the corresponding period in 2017. The increases were primarily due to costs

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related to an employee attrition plan. The year-to-date 2018 increase also reflects a $4 million increase primarily related to additional overhead line maintenance and vegetation management, offset by a $7 million decrease in expenses related to the combined cycle and associated common facilities portion of the Kemper County energy facility.

Depreciation and Amortization

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$3	7.7	$6	5.0

In the third quarter 2018, depreciation and amortization was $42 million compared to $39 million for the corresponding period in 2017. The increase was primarily related to a $3 million change in net amortization associated with ECO Plan regulatory assets.

For year-to-date 2018, depreciation and amortization was $126 million compared to $120 million for the corresponding period in 2017. The increase was primarily related to $5 million of depreciation for additional plant in service and $1 million related to changes in net amortization associated with regulatory assets and liabilities.

See Note 1 to the financial statements of Mississippi Power under "Depreciation, Depletion, and Amortization" in Item 8 of the Form 10-K for additional information.

Taxes Other Than Income Taxes

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$3	12.0	$6	7.8

In the third quarter 2018, taxes other than income taxes were $28 million compared to $25 million for the corresponding period in 2017. For year-to-date 2018, taxes other than income taxes were $83 million compared to $77 million for the corresponding period in 2017. These increases were primarily related to increases in ad valorem taxes related to an increase in the assessed value of property.

The retail portion of ad valorem taxes is recoverable under Mississippi Power's ad valorem tax cost recovery clause and, therefore, does not affect net income.

Estimated Loss on Kemper IGCC

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(33)	(97.1)	$(3,110)	(98.6)

Estimated losses on the Kemper IGCC were $1 million for the third quarter 2018 and $45 million for year-to-date 2018, resulting from the abandonment and related closure activities for the mine and gasifier-related assets as compared to $34 million and $3.2 billion for the corresponding periods in 2017 related to revisions to the estimated construction costs for, and subsequent suspension in June 2017 of, the Kemper IGCC.

See Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein for additional information.

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Allowance for Equity Funds Used During Construction

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(100.0)	$(72)	(100.0)

For year-to-date 2018, AFUDC equity was immaterial compared to $72 million for the corresponding period in 2017. The decrease resulted from suspension of the Kemper IGCC construction in June 2017.

See Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein for additional information.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$32	N/M	$36	N/M

N/M - Not meaningful

In the third quarter 2018, interest expense, net of amounts capitalized was $19 million compared to an interest benefit of $13 million for the corresponding period in 2017. For year-to-date 2018, interest expense, net of amounts capitalized was $59 million compared to $23 million for the corresponding period in 2017. The increases primarily reflect a $33 million net reduction in interest recorded in the third quarter 2017 following a settlement with the IRS related to research and experimental deductions. The year-to-date 2018 increase also reflects a reduction in AFUDC debt of $24 million related to the Kemper IGCC project suspension in June 2017, offset by decreases of $9 million in interest expense as a result of lower average outstanding debt, $8 million related to uncertain tax positions, and $7 million due to the completion of Kemper IGCC carrying cost amortization in 2017.

See Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein for additional information.

Other Income (Expense)

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(100.0)	$24	N/M

N/M - Not meaningful

For year-to-date 2018, other income (expense), net was $28 million compared to $4 million for the corresponding period in 2017. The increase was primarily due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018. See Note (B) to the Condensed Financial Statements under "General Litigation Matters – Mississippi Power" herein for additional information.

Income Taxes (Benefit)

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(10)	(41.7)	$908	102.6

In the third quarter 2018, income taxes were $14 million compared to $24 million for the corresponding period in 2017. This change was primarily due to the reduction in the federal corporate income tax rate as a result of the Tax Reform Legislation, partially offset by higher pre-tax earnings due to lower estimated losses on the Kemper IGCC.

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For year-to-date 2018, income taxes were $23 million compared to an income tax benefit of $885 million for the corresponding period in 2017. This change was primarily due to higher pre-tax earnings due to lower estimated losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion and the related state valuation allowance. This change was partially offset by the reduction in the federal corporate income tax rate as a result of the Tax Reform Legislation.

See Note (H) to the Condensed Financial Statements 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 limited projected demand growth over the next several years. Mississippi Power is scheduled to file the 2019 Base Rate Case in the fourth quarter 2019. Another factor is Mississippi Power's ability to prevail against legal challenges associated with the Kemper County energy facility. Future earnings will be driven primarily by customer growth. 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.

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. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. A major portion of these costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, 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 fully 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 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.

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See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Laws and Regulations

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.

On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.

Coal Combustion Residuals

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).

The EPA published certain amendments to the CCR Rule, which became effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. Specific site impacts are being evaluated by Mississippi Power.

On October 15, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a mandate that broadens the CCR Rule to regulate previously-excluded inactive surface impoundments (legacy units) located at retired generation facilities and challenges both the ability of unlined impoundments to continue operating and the classification of clay lined units. It is anticipated that the EPA will issue a series of rulemakings to address this court action. Mississippi Power is evaluating the extent of potential impacts on legacy units but anticipates no significant impacts to its ongoing CCR strategy due to this mandate. The ultimate impact of these changes will not be known until the EPA rulemaking and any legal challenges are finalized.

During the nine months ended September 30, 2018, Mississippi Power recorded increases of approximately $21 million to its AROs related to the CCR Rule. Approximately $11 million of the revised cost estimates as of September 30, 2018 are based on information from feasibility studies performed on an ash pond at Plant Greene County, which is co-owned with Alabama Power. These studies indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close the ash pond under the planned closure-in-place methodology. As the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material.

As further analysis is performed and closure details are developed with respect to ash pond closures, Mississippi Power expects to periodically update its ARO cost estimates. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

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 these matters cannot be determined at this time.

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Global Climate Issues

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

On August 31, 2018, the EPA published a proposed Clean Power Plan replacement rule known as the Affordable Clean Energy rule (ACE Rule), which would require states to develop unit-specific emission rate standards based on heat-rate efficiency improvements for existing fossil fuel-fired steam units. As proposed, combustion turbines, including natural gas combined cycles, are not affected sources. As of September 30, 2018, Mississippi Power has ownership interests insix fossil fuel-fired steam units to which the proposed ACE Rule is applicable. The ultimate impact of this rule to Mississippi Power is currently unknown and will depend on changes between the proposal and the final rule, subsequent state plan developments and requirements, and any associated legal proceedings.

Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time.

FERC Matters

Municipal and Rural Association Tariff

See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Municipal and Rural Associations Tariff" in Item 8 of the Form 10-K for additional information.

Mississippi Power expects to make an MRA filing in the fourth quarter 2018. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At September 30, 2018, the amount of over-recovered wholesale MRA fuel costs included in other regulatory liabilities, current on the condensed balance sheet was approximately $7 million compared to an immaterial amount at December 31, 2017. Under-recovered wholesale MB fuel costs included in the balance sheets were immaterial at September 30, 2018 and December 31, 2017.

See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.

Market-Based Rate Authority

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Market-Based Rate Authority" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies' (including Mississippi Power's) and Southern Power's 2014 and 2017 triennial market power analyses.

On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies (including Mississippi Power) and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies (including Mississippi Power) and Southern Power made the compliance filing required by the order. These proceedings are concluded.

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Cooperative Energy Power Supply Agreement

See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Cooperative Energy Power Supply Agreement" in Item 8 of the Form 10-K for additional information regarding Cooperative Energy's network integration transmission service agreement (NITSA) with SCS.

On March 23, 2018, the FERC accepted the amendment to the NITSA between Cooperative Energy and SCS, effective April 1, 2018.

Open Access Transmission Tariff

On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies (including Mississippi Power) claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Mississippi Power's) open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Mississippi Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material to Mississippi Power's results of operations. The ultimate outcome of this matter cannot be determined at this time.

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.

On May 8, 2018, the Mississippi PSC issued an order to begin an operations review of Mississippi Power, which began in August 2018, with the final report expected by February 28, 2019. Mississippi Power expects that the review will include, but not be limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time.

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" and "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power" herein for additional information.

Performance Evaluation Plan

On February 7, 2018, Mississippi Power submitted its revised 2018 projected PEP filing to the Mississippi PSC, which reflected the impacts of the Tax Reform Legislation, requesting an increase in annual retail revenues of $26 million based on a performance-adjusted ROE of 9.33% and an increased equity ratio of 55%.

On March 22, 2018, Mississippi Power submitted its annual PEP lookback filing for 2017, which reflected no surcharge or refund.

On July 27, 2018, Mississippi Power and the MPUS entered into the PEP Settlement Agreement, which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement became effective with the first billing cycle of September 2018. The PEP Settlement Agreement provides for an increase of

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approximately $21.6 million in annual base retail revenues, which excludes certain compensation costs contested by the MPUS, as well as approximately $2 million which was subsequently approved for recovery through the 2018 Energy Efficiency Cost Rider as discussed below. Under the PEP Settlement Agreement, Mississippi Power is deferring the contested compensation costs for 2018 and 2019 as a regulatory asset, which totaled $3 million as of September 30, 2018 and is included in other regulatory assets, deferred on the condensed balance sheet. The Mississippi PSC is currently expected to rule on the appropriate treatment for such costs in connection with the 2019 Base Rate Case. The ultimate outcome of this matter cannot be determined at this time.

Pursuant to the PEP Settlement Agreement, Mississippi Power's performance-adjusted allowed ROE is 9.31% and its allowed equity ratio remains at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power retained $44 million of excess accumulated deferred income taxes resulting from the Tax Reform Legislation, which had been proposed to be amortized beginning in 2018, until the conclusion of the 2019 Base Rate Case. Further, Mississippi Power will seek equity contributions sufficient to restore its equity ratio (which was 45% at September 30, 2018) to 50% by December 31, 2018. In the event Mississippi Power's actual average equity ratio for 2018 is more than 1% higher or lower than the 50% target, Mississippi Power will defer the corresponding difference in its revenue requirement as a regulatory asset or liability for resolution in the 2019 Base Rate Case. As of September 30, 2018, Mississippi Power has recorded $5 million in other regulatory liabilities, deferred on the condensed balance sheet related to the estimated December 31, 2018 average equity ratio differential from target applicable to PEP.

Pursuant to the PEP Settlement Agreement, PEP proceedings are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolved all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power recognized revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.

Energy Efficiency

On May 8, 2018, the Mississippi PSC issued an order approving Mississippi Power's revised annual projected Energy Efficiency Cost Rider 2018 compliance filing, which increased annual retail revenues by approximately $3 million effective with the first billing cycle for June 2018.

Ad Valorem Tax Adjustment

On May 8, 2018, the Mississippi PSC also approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2018, which included an annual rate increase of 0.8%, or $7 million, in annual retail revenues effective with the first billing cycle for June 2018, primarily due to increased assessments.

Environmental Compliance Overview Plan

On August 3, 2018, Mississippi Power and the MPUS entered into the ECO Settlement Agreement, which provides for an increase of approximately $17 million in annual base retail revenues and was approved by the Mississippi PSC on August 7, 2018. Rates under the ECO Settlement Agreement became effective with the first billing cycle of September 2018 and will continue in effect until modified by the Mississippi PSC. These revenues are expected to be sufficient to recover the costs included in Mississippi Power's request for 2018, as well as the remaining deferred amounts that were originally expected to be recovered in 2019. In accordance with the ECO Settlement Agreement, ECO Plan proceedings are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not required to make any ECO Plan filings for 2018, 2019, and 2020, with any necessary true-ups to be reflected in the 2019 Base Rate Case. The ECO Settlement Agreement contains the same terms as the PEP Settlement Agreement described herein with respect to allowed ROE and equity ratio. As of September 30, 2018, Mississippi Power has recorded $2 million in other regulatory liabilities, deferred on the condensed balance sheet related to the estimated December 31, 2018 average equity ratio differential from target applicable to the ECO Plan.

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Fuel Cost Recovery

At September 30, 2018, the amount of over-recovered retail fuel costs included on Mississippi Power's condensed balance sheet in customer accounts receivable was approximately $13 million compared to $6 million under recovered at December 31, 2017.

During the fourth quarter 2018, Mississippi Power expects to file its annual rate adjustment under the retail fuel cost recovery clause. The ultimate outcome of this matter cannot be determined at this time.

Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on Mississippi Power's revenues or net income, but will affect cash flow.

Kemper County Energy Facility

For additional information on the Kemper County energy facility, see Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K.

As the mining permit holder for the Kemper County energy facility, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. Mine reclamation began in the first quarter 2018. See Note 1 to the financial statements of Mississippi Power under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.

As of September 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the third quarter 2018 and $45 million ($34 million after tax) for year-to-date 2018, primarily resulting from the abandonment and related closure activities 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 to cost up to $20 million pre-tax (excluding salvage, net of dismantlement costs), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $2 million for the remainder of 2018, $8 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.

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

Reserve Margin Plan

On August 6, 2018, Mississippi Power filed its proposed RMP, as required by the Mississippi PSC's order in the Kemper Settlement Docket. Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being thetwo-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adverse impact on customer rates.

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Mississippi Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY –

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"Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.

Other Matters

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

The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) 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 Note (B) 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.

On May 14, 2018, Mississippi Power's claim for lost revenue resulting from the Deepwater Horizon oil spill in the Gulf of Mexico in 2010 was settled. The settlement proceeds of $18 million, net of expenses and income tax, are included in Mississippi Power's earnings for the nine months ended September 30, 2018.

To mitigate customer rate impacts associated with rising costs and declining sales, Mississippi Power management approved an employee attrition plan on July 13, 2018. In the third quarter 2018, Mississippi Power recorded $14 million in expenses related to this plan.

On October 2, 2018, the Mississippi PSC approved the executed agreements between Mississippi Power and its largest retail customer, Chevron, for Mississippi Power to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The new agreements are not expected to have a material impact on earnings.

Litigation

In 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled to include, among other things, Southern Company as a defendant. The individual plaintiff alleged that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches unjustly enriched Mississippi Power and Southern Company. The plaintiffs sought unspecified actual damages and punitive damages; asked the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; asked the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and sought attorney's fees, costs, and interest. The plaintiffs also sought an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. In June 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. In July 2017, the plaintiffs filed notice of an appeal. On July 13, 2018, Mississippi Power and Southern Company reached a settlement agreement with the plaintiffs and the plaintiffs' appeal was dismissed with prejudice. The settlement had no material impact on Mississippi Power's financial statements.

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On May 18, 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in September 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. 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. Mississippi Power will vigorously defend itself in this matter, the ultimate outcome of which 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 Note 1 to the financial statements of Mississippi Power 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.

Kemper County Energy Facility Closure Costs

As of September 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the third quarter 2018 and $45 million ($34 million after tax) for year-to-date 2018, primarily resulting from the abandonment and related closure activities 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 to cost up to $20 million pre-tax (excluding salvage, net of dismantlement costs), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $2 million for the remainder of 2018, $8 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.

See Notes 1 and 3 to the financial statements of Mississippi Power under "Variable Interest Entities" and "Kemper County Energy Facility," respectively, in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein for additional information.

Recently Issued Accounting Standards

See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Mississippi Power's recently adopted accounting standards.

In 2016, the FASB issued ASU No. 2016-02, which requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and Mississippi Power will adopt the new standard effective January 1, 2019.

Mississippi Power has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the

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adoption date of January 1, 2019, without restating prior periods. Mississippi Power expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Mississippi Power expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Mississippi Power also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.

Mississippi Power is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Mississippi Power has substantially completed its lease inventory and determined its most significant leases involve equipment and railcar leases. While Mississippi Power has not yet determined the ultimate impact, adoption of ASU 2016-02 is not expected to have a material impact on Mississippi Power's balance sheet or statement of income.

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, 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, to expand and improve transmission and distribution facilities, and for restoration following major storms.

In March 2018, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $100 million was repaid in the third quarter 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.

Net cash provided from operating activities totaled $656 million for the first nine months of 2018, an increase of $295 million as compared to the corresponding period in 2017. The increase in net cash provided from operating activities is primarily related to increased income tax refunds in 2018 primarily related to the tax abandonment of the Kemper IGCC, partially offset by an increase in ad valorem taxes and the timing of collections of receivables. Net cash used for investing activities totaled $170 million for the first nine months of 2018 primarily due to gross property additions related to steam production, distribution, and transmission. Net cash used for financing activities totaled $355 million for the first nine months of 2018 primarily due to redemptions of long-term debt and short-term borrowings, partially offset by the issuance of senior notes and short-term borrowings. 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 nine months of 2018 include increases of $435 million in long-term debt primarily due to the issuance of senior notes and $131 million in cash and cash equivalents primarily due to tax refunds, a net change of $440 million in accumulated deferred income taxes primarily due to the tax abandonment of the Kemper IGCC, and a decrease of $785 million in securities due within one year due to the repayment of a $900 million unsecured term loan.

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

description of Mississippi Power's capital requirements and contractual obligations. Subsequent to September 30, 2018, Mississippi Power completed the redemption of $30 million aggregate principal amount of its Series G 5.40% Senior Notes due July 1, 2035 and $125 million aggregate principal amount of its Series 2009A 5.55% Senior Notes due March 1, 2019. There are no additional scheduled maturities or announced redemptions of long-term debt through September 30, 2019. Approximately $50 million of revenue bonds will be required to be remarketed over the next 12 months. See "Sources of Capital" herein for additional information.

Mississippi Power's purchase commitments related to LTSAs have changed to approximately $43 million for 2018, $28 million for 2019, $28 million for 2020, $29 million for 2021, $49 million for 2022, and $257 million for 2023 and thereafter due to an increase in estimated expenditures covered under the LTSA for the Kemper County energy facility.

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 required for construction and other purposes from operating cash flows, lines of credit, bank term loans, external security issuances, commercial paper (to the extent it is eligible to participate), monetization of income tax deductions associated with the abandonment of the gasifier portion of the Kemper County energy facility, and equity contributions from Southern Company. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" in Item 7 of the Form 10-K for additional information.

Mississippi Power's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.

At September 30, 2018, Mississippi Power had approximately $379 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2018 were as follows:

Expires						Executable Term Loans		Expires Within One Year
2019		Total		Unused		One Year		Term Out		No Term Out
(in millions)
$	100	$	100	$	100	$	—	$	—	$	—

See Note 6 to the financial statements of Mississippi Power 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 contain cross acceleration 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 September 30, 2018, Mississippi Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Subject to applicable market conditions, Mississippi Power expects to seek to renew or replace its credit arrangements as needed, prior to expiration. In connection therewith, Mississippi Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

A portion of the $100 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's revenue bonds. The amount of variable rate revenue bonds outstanding requiring liquidity support as of September 30, 2018 was approximately $40 million. In addition, at September 30, 2018, Mississippi Power had approximately $50 million of revenue bonds outstanding that were required to be remarketed within the next 12 months.

Short-term borrowings are included in notes payable in the balance sheets. 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)
Short-term bank debt	$	50	3.3	%	$	100

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2018. No short-term debt was outstanding at September 30, 2018.

Credit Rating Risk

At September 30, 2018, Mississippi Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

On October 2, 2018, the Mississippi PSC approved the executed agreements between Mississippi Power and its largest retail customer, Chevron, for Mississippi Power to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The agreements grant Chevron a security interest in the co-generation assets, with a net book value of approximately $93 million, located at the refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of Mississippi Power's credit rating to below investment grade by two of the three rating agencies.

There are certain contracts that have required or could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission. At September 30, 2018, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $202 million.

Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or Georgia Power (affiliate companies of Mississippi Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Mississippi Power to access capital markets, and would be likely to impact the cost at which it does so.

On February 26, 2018, Moody's revised its rating outlook for Mississippi Power from stable to positive. On August 8, 2018, Moody's upgraded Mississippi Power's senior unsecured rating to Baa3 from Ba1 and maintained the positive rating outlook.

On February 28, 2018, Fitch removed Mississippi Power from rating watch negative and revised its rating outlook from stable to positive.

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On March 14, 2018, S&P upgraded the senior unsecured long-term debt rating of Mississippi Power to A- from BBB+. The outlook remained negative.

As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Mississippi Power, may be negatively impacted. The PEP Settlement Agreement is expected to help mitigate these potential adverse impacts by allowing Mississippi Power to retain the excess deferred taxes resulting from the Tax Reform Legislation until the conclusion of the 2019 Base Rate Case. In addition, Mississippi Power has committed to seek equity contributions sufficient to restore its equity ratio to the 50% target. See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power" herein for additional information.

Financing Activities

In March 2018, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $100 million was repaid in the third quarter 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.

In July 2018, Mississippi Power purchased and held approximately $43 million aggregate principal amount of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002. Mississippi Power may reoffer these bonds to the public at a later date.

Subsequent to September 30, 2018, Mississippi Power completed the redemption of all 334,210 outstanding shares of its preferred stock (as well as related depositary shares), with an aggregate par value of approximately $33.4 million; all $30 million aggregate principal amount outstanding of its Series G 5.40% Senior Notes due July 1, 2035; and all $125 million aggregate principal amount outstanding of its Series 2009A 5.55% Senior Notes due March 1, 2019.

In 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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SOUTHERN POWER COMPANY

AND SUBSIDIARY COMPANIES

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	496		$	510		$	1,363		$	1,293
Wholesale revenues, affiliates	134			105			326			295
Other revenues	5			3			10			9
Total operating revenues	635			618			1,699			1,597
Operating Expenses:
Fuel	190			189			511			460
Purchased power	37			43			137			113
Other operations and maintenance	94			83			278			272
Depreciation and amortization	130			131			370			379
Taxes other than income taxes	12			13			36			37
Asset impairment	36			—			155			—
Total operating expenses	499			459			1,487			1,261
Operating Income	136			159			212			336
Other Income and (Expense):
Interest expense, net of amounts capitalized	(45		)	(47		)	(138		)	(144		)
Other income (expense), net	17			3			22			3
Total other income and (expense)	(28		)	(44		)	(116		)	(141		)
Earnings Before Income Taxes	108			115			96			195
Income taxes (benefit)	(38		)	(39		)	(210		)	(129		)
Net Income	146			154			306			324
Net income attributable to noncontrolling interests	54			30			71			48
Net Income Attributable to Southern Power	$	92		$	124		$	235		$	276

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Net Income	$	146		$	154		$	306		$	324
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(4), $15, $(7), and $35, respectively	(11		)	25			(19		)	58
Reclassification adjustment for amounts included in net income, net of tax of $4, $(12), $16, and $(42), respectively	11			(20		)	46			(68		)
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)	—			5			28			(10		)
Comprehensive Income	146			159			334			314
Comprehensive income attributable to noncontrolling interests	54			30			71			48
Comprehensive Income Attributable to Southern Power	$	92		$	129		$	263		$	266

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 Nine Months Ended September 30,
	2018			2017
	(in millions)
Operating Activities:
Net income	$	306		$	324
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	394			404
Deferred income taxes	(337		)	240
Amortization of investment tax credits	(43		)	(42		)
Income taxes receivable, non-current	(12		)	(42		)
Asset impairment	155			—
Other, net	10			(4		)
Changes in certain current assets and liabilities —
-Receivables	(41		)	(77		)
-Prepaid income taxes	5			24
-Other current assets	1			14
-Accounts payable	(27		)	(31		)
-Accrued taxes	256			79
-Other current liabilities	(1		)	5
Net cash provided from operating activities	666			894
Investing Activities:
Business acquisitions	(64		)	(1,016		)
Property additions	(226		)	(218		)
Change in construction payables	3			(166		)
Payments pursuant to LTSAs	(57		)	(99		)
Other investing activities	20			7
Net cash used for investing activities	(324		)	(1,492		)
Financing Activities:
Decrease in notes payable, net	(68		)	(89		)
Proceeds —
Short-term borrowings	200			—
Other long-term debt	—			43
Redemptions —
Senior notes	(350		)	—
Other long-term debt	(420		)	(4		)
Return of capital	(650		)	—
Distributions to noncontrolling interests	(86		)	(89		)
Capital contributions from noncontrolling interests	1,333			79
Payment of common stock dividends	(234		)	(238		)
Other financing activities	(15		)	(27		)
Net cash used for financing activities	(290		)	(325		)
Net Change in Cash, Cash Equivalents, and Restricted Cash	52			(923		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	140			1,112
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	192		$	189
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $14 and $7 capitalized for 2018 and 2017, respectively)	$	138		$	144
Income taxes, net	(102		)	(343		)
Noncash transactions — Accrued property additions at end of period	37			16

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

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2018		At December 31, 2017
	(in millions)
Current Assets:
Cash and cash equivalents	$	192	$	129
Receivables —
Customer accounts receivable	150		117
Affiliated	71		50
Other	62		98
Materials and supplies	214		278
Prepaid income taxes	44		50
Assets held for sale, current	18		1
Other current assets	29		35
Total current assets	780		758
Property, Plant, and Equipment:
In service	13,603		13,755
Less: Accumulated provision for depreciation	2,087		1,910
Plant in service, net of depreciation	11,516		11,845
Construction work in progress	586		511
Total property, plant, and equipment	12,102		12,356
Other Property and Investments:
Intangible assets, net of amortization of $66 and $47 at September 30, 2018 and December 31, 2017, respectively	391		411
Total other property and investments	391		411
Deferred Charges and Other Assets:
Prepaid LTSAs	106		118
Accumulated deferred income taxes	1,281		925
Income taxes receivable, non-current	84		72
Assets held for sale	185		—
Other deferred charges and assets	426		566
Total deferred charges and other assets	2,082		1,681
Total Assets	$	15,355	$	15,206

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

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At September 30, 2018		At December 31, 2017
	(in millions)
Current Liabilities:
Securities due within one year	$	—	$	770
Notes payable	237		105
Accounts payable —
Affiliated	86		102
Other	88		103
Accrued income taxes	233		—
Liabilities held for sale, current	4		—
Other current liabilities	165		152
Total current liabilities	813		1,232
Long-term Debt	5,029		5,071
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	111		199
Accumulated deferred ITCs	1,842		1,884
Other deferred credits and liabilities	259		322
Total deferred credits and other liabilities	2,212		2,405
Total Liabilities	8,054		8,708
Common Stockholder's Equity:
Common stock, par value $0.01 per share —
Authorized — 1,000,000 shares
Outstanding — 1,000 shares	—		—
Paid-in capital	2,604		3,662
Retained earnings	1,478		1,478
Accumulated other comprehensive income (loss)	31		(2		)
Total common stockholder's equity	4,113		5,138
Noncontrolling interests	3,188		1,360
Total stockholders' equity	7,301		6,498
Total Liabilities and Stockholders' Equity	$	15,355	$	15,206

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2018 vs. THIRD QUARTER 2017

AND

YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017

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 has committed to the construction or acquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities.

In May 2018, Southern Power completed the sale of a 33% equity interest in SPSH, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, for an aggregate purchase price of approximately $1.2 billion. In addition, Southern Power entered into an agreement to sell all of its equity interests in Plant Oleander and Plant Stanton Unit A (together, the Florida Plants), for an aggregate purchase price of $195 million. The sale is expected to occur in the first quarter 2019. On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. The transaction is subject to Public Utility Commission of Texas approval and is expected to close by the end of 2018. On November 5, 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of $650 million. The transaction is subject to the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act) and FERC and state commission approvals and is expected to close mid-2019. See FUTURE EARNINGS POTENTIAL and Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information. The ultimate outcome of these matters cannot be determined at this time.

During the nine months ended September 30, 2018, Southern Power acquired and placed in service the 20-MW Gaskell West 1 solar facility, placed in service the 148-MW Cactus Flats wind facility, acquired and began construction of the 100-MW Wild Horse Mountain and the 200-MW Reading wind facilities, and continued construction of the expansion of the 385-MW Mankato natural gas facility. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.

At September 30, 2018, Southern Power's average investment coverage ratio for its generating assets (including the Florida and Mankato Plants), 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 discussed herein) as the investment amount, was 93% through 2022 and 91% through 2027, with an average remaining contract duration of approximately 15 years. See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein for additional information.

See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for information regarding Southern Power's revised capital expenditure forecasts for 2018 through 2022.

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

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(32)	(25.8)	$(41)	(14.9)

Net income attributable to Southern Power for the third quarter 2018 was $92 million compared to $124 million for the corresponding period in 2017. The decrease was primarily due to a $36 million asset impairment charge ($27 million after tax) on wind turbine equipment held for development projects and $23 million from a reduction in income tax benefits primarily from ITCs related to solar facilities placed in service, partially offset by $11 million in state income tax benefits arising from the reorganization of legal entities that own and operate certain of Southern Power's wind facilities.

Net income attributable to Southern Power for year-to-date 2018 was $235 million compared to $276 million for the corresponding period in 2017. The decrease was primarily due to a $119 million asset impairment charge as a result of the pending sale of the Florida Plants in the second quarter 2018 and a $36 million asset impairment charge on wind turbine equipment held for development projects (together $116 million after tax) and $25 million from a reduction in income tax benefits primarily from ITCs related to solar facilities placed in service, partially offset by approximately $65 million in state income tax benefits arising from reorganizations of legal entities that own and operate certain of Southern Power's solar and wind facilities.

Operating Revenues

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$17	2.8	$102	6.4

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

Natural Gas and Biomass Capacity and Energy Revenue

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

Solar and Wind Energy Revenue

Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have 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 sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors.

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

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

	Third Quarter 2018		Third Quarter 2017		Year-to-Date 2018		Year-to-Date 2017
	(in millions)
PPA capacity revenues	$	168	$	169	$	450	$	466
PPA energy revenues	336		299		892		765
Total PPA revenues	504		468		1,342		1,231
Non-PPA revenues	126		147		347		357
Other revenues	5		3		10		9
Total operating revenues	$	635	$	618	$	1,699	$	1,597

In the third quarter 2018, total operating revenues were $635 million, reflecting a $17 million, or 3%, increase from the corresponding period in 2017. The increase in operating revenues was primarily due to the following:

• PPA energy revenues increased $37 million, or 12%, primarily due to increases of $20 million from new natural gas PPAs from existing facilities, $9 million from renewable facilities primarily due to an increase in the volume of KWHs sold, and $8 million in fuel costs that are contractually recovered through existing PPAs.

• Non-PPA revenues decreased $21 million, or 14%, primarily due to the volume of KWHs sold from uncovered natural gas capacity through short-term sales.

For year-to-date 2018, total operating revenues were $1.7 billion, reflecting an $102 million, or 6%, increase from the corresponding period in 2017. The increase in operating revenues was primarily due to the following:

• PPA capacity revenues decreased $16 million, or 3%, primarily due to the contractual expiration of an affiliate natural gas PPA.

• PPA energy revenues increased $127 million, or 17%, primarily due to increases of $56 million from new natural gas PPAs from existing facilities, $45 million in fuel costs that are contractually recovered through existing PPAs, and $27 million from renewable facilities primarily due to an increase in the volume of KWHs sold.

• Non-PPA revenues decreased $10 million, or 3%, primarily due to the volume of KWHs sold from uncovered natural gas capacity through short-term sales.

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Fuel and Purchased Power Expenses

Fuel costs constitute the largest expense for Southern Power. In addition, Southern Power purchases a portion of its electricity needs from the wholesale market including the power pool. Details of Southern Power's generation and purchased power were as follows:

	Third Quarter 2018	Third Quarter 2017	Year-to-Date 2018	Year-to-Date 2017
	(in billions of KWHs)
Generation	13.3	12.5	35.3	33.2
Purchased power	0.9	1.2	3.1	3.4
Total generation and purchased power	14.2	13.7	38.4	36.6
Total generation and purchased power, excluding solar, wind, and tolling agreements	8.2	7.2	22.2	17.8

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:

	Third Quarter 2018 vs. Third Quarter 2017				Year-to-Date 2018 vs. Year-to-Date 2017
	(change in millions)			(% change)	(change in millions)		(% change)
Fuel	$	1		0.5	$	51	11.1
Purchased power	(6		)	(14.0)	24		21.2
Total fuel and purchased power expenses	$	(5	)		$	75

In the third quarter 2018, total fuel and purchased power expenses decreased $5 million, or 2%, compared to the corresponding period in 2017. Fuel expense increased $1 million primarily due to a $43 million increase in the volume of KWHs generated, excluding solar, wind, and tolling agreements, partially offset by a $42 million decrease in the average cost of natural gas per KWH generated. Purchased power expense decreased $6 million due to a $9 million decrease in the volume of KWHs purchased, partially offset by a $3 million increase in the average cost of purchased power.

For year-to-date 2018, total fuel and purchased power expenses increased $75 million, or 13%, compared to the corresponding period in 2017. Fuel expense increased $51 million primarily due to a $152 million increase in the volume of KWHs generated, excluding solar, wind, and tolling agreements, partially offset by a $101 million decrease in the average cost of natural gas per KWH generated. Purchased power expense increased $24 million primarily due to a $33 million increase in the average cost of purchased power primarily in first quarter 2018, partially offset by a $9 million decrease in the volume of KWHs purchased.

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Asset Impairment

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$36	N/M	$155	N/M

N/M - Not meaningful

In the second quarter 2018, a $119 million asset impairment charge was recorded in contemplation of the sale of the Florida Plants. In addition, in the third quarter 2018, a $36 million asset impairment charge was recorded on wind turbine equipment held for development projects. See Note (J) under "Southern Power – Sale of Florida Plants" and " – Development Projects" to the Condensed Financial Statements herein for additional information.

Other Income (Expense), Net

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$14	N/M	$19	N/M

N/M - Not meaningful

In the third quarter 2018, other income (expense), net was $17 million compared to $3 million for the corresponding period in 2017. For year-to-date 2018, other income (expense) was $22 million compared to $3 million for the corresponding period in 2017. These increases were primarily due to a $14 million gain from a joint-development wind project, which is attributable to Southern Power's partner in the project and fully offset within noncontrolling interests.

Income Taxes (Benefit)

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$1	2.6	$(81)	(62.8)

In the third quarter 2018, income tax benefit was $38 million compared to $39 million for the corresponding period in 2017. For year-to-date 2018, income tax benefit was $210 million compared to $129 million for the corresponding period in 2017. These changes were primarily due to lower pre-tax earnings, primarily resulting from asset impairment charges, and income tax benefits related to certain changes in state apportionment rates arising from reorganizations of Southern Power's legal entities that own and operate certain of its solar and wind facilities, partially offset by a decrease in income tax benefits from solar ITCs, primarily as a result of a decrease in the number of facilities placed in service in 2018 as compared to 2017. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Legal Entity Reorganizations" and Note (H) to the Condensed Financial Statements herein for additional information.

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Net Income Attributable to Noncontrolling Interests

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$24	80.0	$23	47.9

In the third quarter 2018, net income attributable to noncontrolling interests was $54 million compared to $30 million for the corresponding period in 2017. The increase was due to $14 million of other income allocations attributable to a joint-development wind project and $10 million of net income allocations primarily due to the sale of a 33% equity interest in SPSH in 2018.

For year-to-date 2018, net income attributable to noncontrolling interests was $71 million compared to $48 million for the corresponding period in 2017. The increase was primarily due to $21 million of net income allocations due to the sale of a 33% equity interest in SPSH in 2018 and $14 million of other income allocations attributable to a joint-development wind project, partially offset by a reduction of $10 million of net income allocations primarily due to the tax equity partnership for Gaskell West 1.

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

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. 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 successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its strategy.

In May 2018, Southern Power completed the sale of a 33% equity interest in SPSH, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, to Global Atlantic Financial Group Limited (Global Atlantic) for approximately $1.2 billion. Accordingly, Global Atlantic will receive 33% of all cash distributions paid by SPSH. Southern Power continues to consolidate the assets and liabilities of SPSH with Global Atlantic's share of partnership earnings reflected in net income attributable to noncontrolling interests in the Condensed Consolidated Statements of Income.

Also in May 2018, Southern Power entered into an equity interest purchase agreement with NextEra Energy to sell all of its equity interests in the Florida Plants for an aggregate purchase price of $195 million, subject to customary working capital and timing adjustments. The ultimate purchase price will decrease $110,000 per day for each day after December 31, 2018 through the closing of the transaction. Conversely, the ultimate purchase price will increase $110,000 per day for each day the closing occurs prior to December 31, 2018. The sale is expected to occur in the first quarter 2019. Pre-tax net income for the Florida Plants was $18 million and $11 million for the three months ended September 30, 2018 and 2017, respectively, and $40 million and $28 million for the nine months ended September 30, 2018 and 2017, respectively. The ultimate outcome of this matter cannot be determined at this time.

On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in Class A tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. The transaction is subject to Public Utility Commission of Texas approval and is expected to close by the end of 2018. Upon closing, the tax equity partners will have a claim to certain cash distributions and an allocation of tax attributes. See "Income Tax Matters – Legal Entity Reorganizations" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

On November 5, 2018, Southern Power entered into an agreement with Northern States Power to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of $650 million, subject to customary working capital and timing adjustments. The ultimate purchase

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price will decrease $66,667 per day for each day after June 1, 2019, if the expansion has not achieved commercial operation, but such decrease will not exceed $15 million. This transaction is subject to the expiration or termination of the waiting period under the HSR Act and FERC and state commission approvals and is expected to close mid-2019. The ultimate outcome of this matter cannot be determined at this time.

Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, as well as renewable portfolio standards, which may impact future earnings. Other factors that could influence future earnings include weather, transmission constraints, cost of generation from units within the power pool, and operational limitations. 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.

At September 30, 2018, Southern Power's average investment coverage ratio for its generating assets (including the Florida and Mankato Plants), 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 and acquisitions discussed herein) as the investment amount, was 93% through 2022 and 91% through 2027, with an average remaining contract duration of approximately 15 years.

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.

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.

On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.

FERC Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Power in Item 7 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies'and Southern Power's 2014 and 2017 triennial market power analyses.

On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companiesand Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companiesand Southern Power made the compliance filing required by the order. These proceedings are concluded.

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Acquisitions

During the nine months ended September 30, 2018, one of Southern Power's wholly-owned subsidiaries acquired and completed construction of the Gaskell West 1 solar facility. Acquisition-related costs were expensed as incurred and were not material. See Note (J) to the Condensed Financial Statements under "Southern Power" herein and 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 additional information.

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Percentage Ownership		Actual COD	PPA Counterparties	PPA Contract Period
Gaskell West 1	Solar	20	Kern County, CA	100% of Class B	(*)	March 2018	Southern California Edison	20 years

(*) Southern Power owns 100% of the class B membership interests under a tax equity partnership agreement.

The Gaskell West 1 facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service during March 2018.

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.

Construction Projects in Progress and/or Completed

During the nine months ended September 30, 2018, Southern Power started, continued, or completed construction of the projects set forth in the table below. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $575 million and $640 million for the Mankato, Wild Horse Mountain, and Reading facilities. At September 30, 2018, construction costs included in CWIP related to these projects totaled $246 million. 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
Cactus Flats(a)	Wind	148	Concho County, TX	July 2018	General Motors, LLC and General Mills Operations, LLC	12 years and 15 years
Mankato	Natural Gas	385	Mankato, MN	First half 2019	Northern States Power Company	20 years
Wild Horse 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 July 2017, Southern Power purchased 100% of the Cactus Flats facility and commenced construction. In July 2018, the facility was placed in service and, in August 2018, Southern Power closed on a tax equity partnership agreement and owns 100% of the class B membership interests.

(b) In May 2018, Southern Power purchased 100% of the Wild Horse Mountain facility and commenced construction. Southern Power may enter into a tax equity partnership agreement, in which case it would then own 100% of the class B membership interests.

(c) In August 2018, Southern Power purchased 100% of the membership interests from the joint development arrangement with Renewable Energy Systems Americas, Inc. and commenced construction. Southern Power may enter into a tax equity partnership agreement, in which case it would then own 100% of the class B membership interests.

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Development Projects

During 2017, as part of its renewable development strategy, Southern Power purchased wind turbine equipment from Siemens Gamesa Renewable Energy Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction projects. Any wind projects using this equipment and reaching commercial operation by the end of 2021 are expected to qualify for 80% PTCs.

During 2016, Southern Power entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct wind projects. In addition, in 2016, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Any wind projects using this equipment and reaching commercial operation by the end of 2020 are expected to qualify for 100% PTCs.

In response to the previously disclosed decrease of planned expenditures for plant acquisitions and placeholder growth, Southern Power continues to refine the deployment of the wind turbine equipment to potential joint development and construction projects as well as the amount of MW capacity to be constructed. During the third quarter 2018, as a result of a review of various options for probable dispositions of wind turbine equipment not already deployed to development or construction projects, Southern Power recorded a $36 million asset impairment charge on the equipment.

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

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation.

Legal Entity Reorganizations

In April 2018, Southern Power completed the final stage of a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization resulted in net state tax benefits related to certain changes in apportionment rates totaling approximately $54 million, which were recorded in the first half of 2018.

In September 2018, Southern Power also completed a legal reorganization of eight operating wind facilities under a new holding company, SP Wind, which resulted in net state tax benefits totaling approximately $11 million related to certain changes in apportionment rates.

Other Matters

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

The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) 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.

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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 Note 1 to the financial statements of Southern Power 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 MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Power in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Southern Power's recently adopted accounting standards.

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

Southern Power has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Southern Power expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Southern Power expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption. Southern Power also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lessee lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes, while lessor lease and non-lease components will be accounted for separately.

Southern Power is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Southern Power has substantially completed its lease inventory and determined its most significant leases as a lessee involve real estate. While Southern Power has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in recording lease liabilities and right-of-use assets on Southern Power's balance sheet each totaling approximately $0.5 billion, with no material impact on Southern Power's statement of income.

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 September 30, 2018. 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 third-party tax equity partnerships as one of the financing sources to fund its renewable growth strategy where the tax partner takes significantly all of the federal tax benefits. These tax equity partnerships are consolidated in Southern Power's financial statements using a hypothetical liquidation at book value (HLBV) methodology to allocate partnership gains and losses to Southern Power. During the first nine months of 2018, Southern Power obtained third-party tax equity funding for the Gaskell West 1 solar project and the Cactus Flats wind project of approximately $26 million and $122 million, respectively. See Note (A) to the Condensed Financial Statements under "Hypothetical Liquidation at Book Value" herein for additional information on the HLBV methodology.

In May 2018, Southern Power received approximately $1.2 billion from the sale of a 33% equity interest in SPSH, a limited partnership indirectly owning substantially all of Southern Power's solar facilities. The proceeds were used to repay $770 million of existing indebtedness, to return capital of $250 million to Southern Company, and for other general corporate purposes, including working capital.

On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. The transaction is subject to Public Utility Commission of Texas approval and is expected to close by the end of 2018. Southern Power intends to use the proceeds to return capital of approximately $1.0 billion to Southern Company. The ultimate outcome of this matter cannot be determined at this time.

Net cash provided from operating activities totaled $666 million for the first nine months of 2018 compared to $894 million for the first nine months of 2017. The decrease in net cash provided from operating activities was primarily due to lower income tax refunds primarily due to taxable gains arising from the sale of a 33% equity interest in SPSH. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" of Southern Power in Item 7 of the Form 10-K for additional information. Net cash used for investing activities totaled $324 million for the first nine months of 2018 primarily due to the construction of generating facilities and payments for renewable acquisitions. Net cash used for financing activities totaled $290 million for the first nine months of 2018 primarily due to debt repayments, returns of capital and payments of common stock dividends to Southern Company, and distributions to noncontrolling interests, partially offset by proceeds from the sale of a 33% equity interest in SPSH. 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 nine months of 2018 include a $1.8 billion increase in noncontrolling interests primarily due to the sale of SPSH, a $1.1 billion reduction in paid in capital, which includes $410 million related to the sale of SPSH and $250 million and $400 million of capital returned to Southern Company in the second and third quarters 2018, respectively, a $770 million decrease in securities due within one year due to repayments of debt in the second quarter 2018, and a $356 million increase in accumulated deferred income tax assets primarily due to the sale of SPSH.

See FUTURE EARNINGS POTENTIAL – "Acquisitions," "Construction Projects," and "Income Tax Matters – Legal Entity Reorganizations" 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. There are no scheduled maturities of long-term debt through September 30, 2019.

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. Subsequent to the Tax Reform Legislation, planned expenditures for plant acquisitions and placeholder growth are now expected to average approximately $0.5 billion per year for 2018 through 2022 and may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Southern Power's capital expenditures for committed construction, capital improvements, and work to be performed

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

under LTSAs remain unchanged and total approximately $0.9 billion for the five years ending 2022. Actual construction costs may vary from these estimates because of numerous factors such as: changes in business conditions; changes in the expected environmental compliance program; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in FERC rules and regulations; changes in load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "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.

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), bank term loans, the debt capital markets, and operating cash flows.

As of September 30, 2018, Southern Power had cash and cash equivalents of approximately $192 million.

Southern Power's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities, for general corporate purposes, and to finance 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 Debt at September 30, 2018				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	$	37	2.5	%	$	44	2.3	%	$	185
Short-term loans	200		2.8	%	200		2.7	%	200
Total	$	237	2.8	%	$	244	2.6	%

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2018.

At September 30, 2018, Southern Power had a committed credit facility (Facility) of $750 million, of which $22 million has been used for letters of credit and $728 million remains unused. The Facility expires in 2022. 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 6 to the financial statements of Southern Power 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, as well as Southern Power's term loan agreements, contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 65% and contains a cross-default provision that is restricted only to indebtedness of Southern Power. For purposes of this definition, debt excludes any project debt

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 2019 for standby letters of credit. At September 30, 2018, $98 million has been used for letters of credit, primarily as credit support for PPA requirements, and $22 million remains unused.

In addition, at September 30, 2018, Southern Power had $103 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.

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 September 30, 2018 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	37
At BBB- and/or Baa3	$	378
At BB+ and/or Ba1(*)	$	932

(*) 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 Alabama Power or Georgia Power (affiliate companies of Southern Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Power to access capital markets and would be likely to impact the cost at which it does so.

In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade.

On September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and certain of its subsidiaries (including Southern Power).

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 Power, may be negatively impacted. Absent actions by Southern Power to mitigate the resulting impacts, which, among other alternatives, could include adjusting Southern Power's capital structure, Southern Power's credit ratings could be negatively affected.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities

In May 2018, Southern Power entered into two short-term floating rate bank loans, each for an aggregate principal amount of $100 million, which bear interest based on one-month LIBOR.

In the second quarter 2018, Southern Power repaid $420 million aggregate principal amount of long-term floating rate bank loans and $350 million aggregate principal amount of Series 2015A 1.50% Senior Notes due June 1, 2018.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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AND SUBSIDIARY COMPANIES

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Operating Revenues:
Natural gas revenues (includes revenue taxes of $9, $9, $83, and $75, respectively)	$	487		$	532		$	2,829		$	2,737
Alternative revenue programs	5			—			(23		)	9
Other revenues	—			33			55			95
Total operating revenues	492			565			2,861			2,841
Operating Expenses:
Cost of natural gas	104			134			1,053			1,085
Cost of other sales	—			7			12			20
Other operations and maintenance	216			206			730			675
Depreciation and amortization	119			125			374			370
Taxes other than income taxes	32			26			157			140
Gain on dispositions, net	(353		)	—			(317		)	—
Goodwill impairment	—			—			42			—
Total operating expenses	118			498			2,051			2,290
Operating Income	374			67			810			551
Other Income and (Expense):
Earnings from equity method investments	34			32			108			100
Interest expense, net of amounts capitalized	(52		)	(51		)	(170		)	(145		)
Other income (expense), net	6			19			21			30
Total other income and (expense)	(12		)	—			(41		)	(15		)
Earnings Before Income Taxes	362			67			769			536
Income taxes	316			52			475			233
Net Income	$	46		$	15		$	294		$	303

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2018		2017		2018		2017
	(in millions)				(in millions)
Net Income	$	46	$	15	$	294	$	303
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $-, $1, and $(2), respectively	—		—		2		(3		)
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $1, and $-, respectively	—		—		2		—
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $2, $-, $2, and $(1), respectively	6		—		5		—
Total other comprehensive income (loss)	6		—		9		(3		)
Comprehensive Income	$	52	$	15	$	303	$	300

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 Nine Months Ended September 30,
	2018			2017
	(in millions)
Operating Activities:
Net income	$	294		$	303
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	374			370
Deferred income taxes	(83		)	265
Mark-to-market adjustments	23			(32		)
Gain on dispositions, net	(317		)	—
Goodwill impairment	42			—
Other, net	(41		)	(46		)
Changes in certain current assets and liabilities —
-Receivables	445			531
-Natural gas for sale	87			—
-Prepaid income taxes	(23		)	(7		)
-Other current assets	21			(42		)
-Accounts payable	(59		)	(169		)
-Accrued taxes	(64		)	(24		)
-Accrued compensation	2			(11		)
-Other current liabilities	35			8
Net cash provided from operating activities	736			1,146
Investing Activities:
Property additions	(1,029		)	(1,093		)
Cost of removal, net of salvage	(67		)	(45		)
Change in construction payables, net	(14		)	49
Investment in unconsolidated subsidiaries	(90		)	(128		)
Dispositions	2,631			—
Other investing activities	18			28
Net cash provided from (used for) investing activities	1,449			(1,189		)
Financing Activities:
Decrease in notes payable, net	(1,382		)	(323		)
Proceeds —
First mortgage bonds	100			200
Capital contributions from parent company	35			79
Senior notes	—			450
Redemptions — Gas facility revenue bonds	(200		)	—
Return of capital	(400		)	—
Payment of common stock dividends	(351		)	(332		)
Other financing activities	(3		)	(29		)
Net cash provided from (used for) financing activities	(2,201		)	45
Net Change in Cash, Cash Equivalents, and Restricted Cash	(16		)	2
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	78			24
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	62		$	26
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $5 and $9 capitalized for 2018 and 2017, respectively)	$	175		$	146
Income taxes, net	682			17
Noncash transactions — Accrued property additions at end of period	121			112

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 September 30, 2018			At December 31, 2017
	(in millions)
Current Assets:
Cash and cash equivalents	$	56		$	73
Receivables —
Energy marketing receivables	498			607
Customer accounts receivable	180			400
Unbilled revenues	58			285
Affiliated	23			12
Other accounts and notes receivable	110			91
Accumulated provision for uncollectible accounts	(18		)	(28		)
Natural gas for sale	486			595
Prepaid expenses	62			53
Assets from risk management activities, net of collateral	87			135
Other regulatory assets, current	72			94
Other current assets	88			78
Total current assets	1,702			2,395
Property, Plant, and Equipment:
In service	14,771			15,833
Less: Accumulated depreciation	4,351			4,596
Plant in service, net of depreciation	10,420			11,237
Construction work in progress	660			491
Total property, plant, and equipment	11,080			11,728
Other Property and Investments:
Goodwill	5,015			5,967
Equity investments in unconsolidated subsidiaries	1,529			1,477
Other intangible assets, net of amortization of $133 and $120 at September 30, 2018 and December 31, 2017, respectively	113			280
Miscellaneous property and investments	20			21
Total other property and investments	6,677			7,745
Deferred Charges and Other Assets:
Other regulatory assets, deferred	721			901
Other deferred charges and assets	218			218
Total deferred charges and other assets	939			1,119
Total Assets	$	20,398		$	22,987

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 September 30, 2018			At December 31, 2017
	(in millions)
Current Liabilities:
Securities due within one year	$	515		$	157
Notes payable	136			1,518
Energy marketing trade payables	521			546
Accounts payable —
Affiliated	37			21
Other	346			425
Customer deposits	136			128
Accrued taxes —
Accrued income taxes	—			40
Other accrued taxes	61			78
Accrued interest	66			51
Accrued compensation	71			74
Liabilities from risk management activities, net of collateral	28			69
Other regulatory liabilities, current	132			135
Other current liabilities	122			159
Total current liabilities	2,171			3,401
Long-term Debt	5,393			5,891
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	944			1,089
Deferred credits related to income taxes	930			1,063
Employee benefit obligations	412			415
Other cost of removal obligations	1,577			1,646
Accrued environmental remediation, deferred	269			342
Other deferred credits and liabilities	79			118
Total deferred credits and other liabilities	4,211			4,673
Total Liabilities	11,775			13,965
Common Stockholder's Equity:
Common stock, par value $0.01 per share —
Authorized — 100 million shares
Outstanding — 100 shares	—			—
Paid in capital	8,863			9,214
Accumulated deficit	(273		)	(212		)
Accumulated other comprehensive income	33			20
Total common stockholder's equity	8,623			9,022
Total Liabilities and Stockholder's Equity	$	20,398		$	22,987

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2018 vs. THIRD QUARTER 2017

AND

YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017

OVERVIEW

Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas. Subsequent to the dispositions of Elizabethtown Gas, Elkton Gas, and Florida City Gas discussed below, Southern Company Gas has natural gas distribution utilities in four states – Illinois, Georgia, Virginia, and Tennessee. Southern Company Gas and its subsidiaries are also involved in several other complementary businesses.

Southern Company Gas has four reportable segments – gas distribution operations, gas marketing services, wholesale gas services, and gas midstream operations – and one non-reportable segment – all other. For additional information on these segments, see Note (L) to the Condensed Financial Statements herein and "BUSINESS – The Southern Company System – Southern Company Gas" in Item 1 of the Form 10-K.

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, reliability, 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.

On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $365 million, which includes the final working capital adjustment. This disposition resulted in an estimated net loss of $73 million, which includes $39 million of income tax expense, the calculation of which is expected to be finalized in the fourth quarter 2018. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded during the first quarter 2018.

On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion and an additional $40 million for working capital, subject to a final working capital adjustment expected in the fourth quarter 2018. This disposition resulted in an estimated pre-tax gain of approximately $230 million and an after-tax gain of approximately $18 million, the calculations of which are expected to be finalized in the fourth quarter 2018.

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 Energyfor a total cash purchase price of $530 million (less $3 million of indebtedness assumed at closing for customer deposits) and an additional $60 million for cash and other working capital, which includes the final working capital adjustment. This disposition resulted in an estimated pre-tax gain of approximately $121 million and an after-tax gain of approximately $20 million, the calculations of which are expected to be finalized in the fourth quarter 2018.

The after-tax impacts of these dispositions included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Operating Metrics

Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Operating Metrics" of Southern Company Gas in Item 7 of the Form 10-K.

Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. With the exception of Nicor Gas, Southern Company Gas has various regulatory mechanisms, such as weather normalization and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its utilities' respective service territory. However, the utility customers in Illinois and the 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 reduce negative earnings impact in the event of warmer-than-normal weather, while retaining most of the earnings upside for these businesses.

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

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

Heating Season is the period from November through March when natural gas usage and operating revenues are generally higher as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Occasionally in the summer, wholesale gas services' operating revenues are impacted due to peak usage by power generators in response to summer energy demands. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing Southern Company Gas' annual results. 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

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$31	206.7	$(9)	(3.0)

Southern Company Gas' net income for the third quarter 2018 was $46 million compared to $15 million for the corresponding period in 2017. The increase was primarily due to the gains resulting from the sales of Elizabethtown Gas, Elkton Gas, and Florida City Gas and higher commercial activity at wholesale gas services, partially offset by derivative losses at wholesale gas services, disposition-related costs, and a 2017 gain from the settlement of contractor litigation claims. Third quarter 2017 also included a deferred tax expense related to the enactment of the State of Illinois income tax legislation and new income tax apportionment factors in several states.

For year-to-date 2018, net income was $294 million compared to $303 million for the corresponding period in 2017. The decrease was primarily due to the net loss resulting from the Southern Company Gas Dispositions and a goodwill impairment charge recorded during the first quarter 2018 in contemplation of the sale of Pivotal Home

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Solutions, derivative losses at wholesale gas services, disposition-related costs, and lower gains from the settlement of contractor litigation claims in 2018 compared to the corresponding period in 2017, partially offset by higher commercial activity at wholesale gas services, additional revenues from infrastructure investments recovered through replacement programs less the associated increase in depreciation as well as base rate changes at gas distribution operations, and the lower federal income tax rate and the flowback of excess deferred taxes as a result of the Tax Reform Legislation. Year-to-date 2017 also included a deferred tax expense related to the enactment of the State of Illinois income tax legislation and new income tax apportionment factors in several states.

For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company Gas in Item 7 of the Form 10-K and Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein.

Natural Gas Revenues, including Alternative Revenue Programs

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(40)	(7.5)	$60	2.2

In the third quarter 2018, natural gas revenues, including alternative revenue programs, were $492 million compared to $532 million for the corresponding period in 2017. For year-to-date 2018, natural gas revenues, including alternative revenue programs, were $2.8 billion compared to $2.7 billion for the corresponding period in 2017.

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

	Third Quarter 2018					Year-to-Date 2018
	(in millions)			(% change)		(in millions)			(% change)
Natural gas revenues – prior year	$	532				$	2,746
Estimated change resulting from –
Infrastructure replacement programs and base rate changes	—			—		53			1.9
Gas costs and other cost recovery	(16		)	(3.0	)	(24		)	(0.9	)
Weather	1			0.2		17			0.6
Wholesale gas services	17			3.2		46			1.7
Dispositions(*)	(43		)	(8.1	)	(30		)	(1.1	)
Other	1			0.2		(2		)	—
Natural gas revenues – current year	$	492		(7.5	)%	$	2,806		2.2	%

(*) Includes Pivotal Utility Holdings' disposition of Elizabethtown Gas and Elkton Gas as well as NUI Corporation's disposition of Pivotal Utility Holdings, which primarily consisted of Florida City Gas. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

Revenues from infrastructure replacement programs and base rate changes increased for year-to-date 2018 due to gas distribution operations' continued investments recovered through infrastructure replacement programs and base rate increases as a result of rate cases, partially offset by revenue reductions for the impacts of the Tax Reform Legislation. See Note (B) to the Condensed Financial Statements herein under "Regulatory Matters – Southern Company Gas" for additional information.

Revenues associated with gas costs and other cost recovery in the third quarter 2018 decreased due to reduced natural gas prices during the third quarter 2018 compared to the corresponding period in 2017 and decreased volumes of natural gas sold in the third quarter 2018 as a result of fewer customers served following the dispositions. Revenues associated with gas costs and other cost recovery for year-to-date 2018 decreased due to reduced natural gas prices during 2018 compared to the corresponding period in 2017, partially offset by increased

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volumes of natural gas sold in 2018 as a result of colder weather. See "Cost of Natural Gas" herein for additional information.

Revenues increased due to colder weather in 2018 compared to the corresponding periods in 2017 that affected the utility customers in Illinois and the gas marketing services customers in Georgia and Illinois. See the weather discussion herein for additional information.

Revenues from wholesale gas services increased primarily due to increased commercial activity, partially offset by derivative losses. See "Wholesale Gas Services" herein for additional information.

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.

During Heating Season, natural gas usage and operating revenues are generally higher. Weather typically does not have a significant net income impact other than during the Heating Season. The following table presents the Heating Degree Days information for Illinois and Georgia, the primary locations where Southern Company Gas' operations are impacted by weather.

	Year-to-Date			2018 vs. 2017		2018 vs. normal
	Normal(*)	2018	2017	colder		colder (warmer)
Illinois	3,758	3,858	3,146	22.6	%	2.7	%
Georgia	1,578	1,542	1,008	53.0	%	(2.3	)%

(*) Normal represents the 10-year average from January 1, 2008 through September 30, 2017 for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, based on information obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center.

Southern Company Gas hedged its exposure to warmer-than-normal weather in Illinois for gas distribution operations and in Illinois and Georgia for gas marketing services, which limited the negative income impacts reflected in the chart below.

	Gas Distribution Operations					Gas Marketing Services
	Year-to-Date					Year-to-Date
	2018		2017			2018			2017
	(in millions)					(in millions)
Pre-tax	$	2	$	(6	)	$	(1	)	$	(10	)
After tax	2		(3		)	(1		)	(6		)

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The following table provides the number of customers served by Southern Company Gas at September 30, 2018 and 2017:

	September 30,
	2018		2017		2018 vs. 2017
	(in thousands, except market share %)				(% change)
Gas distribution operations(a)	4,177		4,555		(8.3	)%
Gas marketing services(b)
Energy customers(c)	685		756		(9.4	)%
Market share of energy customers in Georgia	29.2	%	28.8	%

(a) Includes total customers of approximately 404,000 at September 30, 2017 related to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold in July 2018. See Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Elizabethtown Gas and Elkton Gas" and " – Sale of Florida City Gas" herein for additional information.

(b) On June 4, 2018, Southern Company Gas completed the sale of Pivotal Home Solutions, which served approximately 1.2 million contracts prior to disposition. See Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Pivotal Home Solutions" herein for additional information.

(c) The decrease at September 30, 2018 is primarily due to approximately 70,000 fewer customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2018. At September 30, 2017, there were approximately 140,000 customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2017.

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

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(33)	N/M	$(40)	(42.1)

N/M - Not meaningful

In the third quarter 2018, there were no other revenues compared to $33 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $55 million compared to $95 million for the corresponding period in 2017. Other revenues related to Pivotal Home Solutions, which was sold on June 4, 2018. See Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Pivotal Home Solutions" herein for additional information.

Cost of Natural Gas

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(30)	(22.4)	$(32)	(2.9)

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 75% and 83% of total cost of natural gas for the third quarter and year-to-date 2018, respectively. For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Cost of Natural Gas and Other Sales" of Southern Company Gas in Item 7 of the Form 10-K and "Natural Gas Revenues" herein.

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In the third quarter 2018, cost of natural gas was $104 million compared to $134 million for the corresponding period in 2017. The decrease reflects $14 million related to the Southern Company Gas Dispositions, which resulted in a decrease in the volume of natural gas sold in the third quarter 2018 as a result of fewer gas distribution operations customers, and a 3.2% decrease in natural gas prices during the third quarter 2018 compared to the corresponding period in 2017.

For year-to-date 2018, cost of natural gas was $1.05 billion compared to $1.09 billion for the corresponding period in 2017. The decrease reflects $8 million related to the Southern Company Gas Dispositions, which resulted in a decrease in the volume of natural gas sold in 2018 as a result of fewer gas distribution operations customers, as well as an 8.4% decrease in natural gas prices during 2018, partially offset by an increase in the volume of natural gas sold in 2018 as a result of colder weather compared to the corresponding period in 2017.

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

	Third Quarter		2018 vs. 2017		Year-to-Date		2018 vs. 2017
	2018	2017			2018	2017
Gas distribution operations(mmBtu in millions)
Firm	69	73	(5.5	)%	503	438	14.8	%
Interruptible	22	22	—	%	71	71	—	%
Total	91	95	(4.2	)%	574	509	12.8	%
Gas marketing services(mmBtu in millions)
Firm:
Georgia	3	4	(25.0	)%	25	20	25.0	%
Illinois	1	1	—	%	9	8	12.5	%
Ohio	1	2	(50.0	)%	12	6	100.0	%
Other	1	1	—	%	3	4	(25.0	)%
Interruptible large commercial and industrial	3	3	—	%	10	10	—	%
Total	9	11	(18.2	)%	59	48	22.9	%
Wholesale gas services (mmBtu in millions/day)
Daily physical sales	6.8	6.3	7.9	%	6.7	6.4	4.7	%

Cost of Other Sales

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(7)	N/M	$(8)	(40.0)

N/M - Not meaningful

In the third quarter 2018, there was no cost of other sales compared to $7 million for the corresponding period in 2017. For year-to-date 2018, cost of other sales was $12 million compared to $20 million for the corresponding period in 2017. Cost of other sales related to Pivotal Home Solutions, which was sold on June 4, 2018. See Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Pivotal Home Solutions" herein for additional information.

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Other Operations and Maintenance Expenses

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$10	4.9	$55	8.1

In the third quarter 2018, other operations and maintenance expenses were $216 million compared to $206 million for the corresponding period in 2017. The increase was primarily due to $21 million of disposition-related costs and a $12 million increase in compensation and benefit costs, partially offset by a $24 million decrease related to the Southern Company Gas Dispositions and a $7 million decrease in bad debt expense at gas distribution operations.

For year-to-date 2018, other operations and maintenance expenses were $730 million compared to $675 million for the corresponding period in 2017. The increase was primarily due to $29 million of disposition-related costs, a $48 million increase in compensation and benefit costs, including a $12 million one-time increase for the adoption of a new paid time off policy to align with the Southern Company system, and an $11 million reserve for a settlement of class action litigation to facilitate the sale of Pivotal Home Solutions. These increases were partially offset by an $11 million decrease related to the Southern Company Gas Dispositions and a $15 million decrease in bad debt expense at gas distribution operations. See Notes (B) and (J) to the Condensed Financial Statements under "General Litigation Matters – Southern Company Gas" and "Southern Company Gas," respectively, herein for additional information. 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 on the new paid time off policy.

Depreciation and Amortization

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(6)	(4.8)	$4	1.1

In the third quarter 2018, depreciation and amortization was $119 million compared to $125 million for the corresponding period in 2017. The decrease was primarily due to a $15 million decrease related to the Southern Company Gas Dispositions, partially offset by continued infrastructure investments recovered through replacement programs at gas distribution operations and lower amortization of intangible assets as a result of fair value adjustments in acquisition accounting at gas marketing services.

For year-to-date 2018, depreciation and amortization was $374 million compared to $370 million for the corresponding period in 2017. The increase was primarily due to continued infrastructure investments recovered through replacement programs at gas distribution operations, partially offset by a $20 million decrease related to the Southern Company Gas Dispositions and lower amortization of intangible assets as a result of fair value adjustments in acquisition accounting at gas marketing services.

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

Taxes Other Than Income Taxes

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$6	23.1	$17	12.1

In the third quarter 2018, taxes other than income taxes were $32 million compared to $26 million for the corresponding period in 2017. This increase primarily reflects a $5 million credit in 2017 to establish a regulatory asset related to Nicor Gas' invested capital tax.

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For year-to-date 2018, taxes other than income taxes were $157 million compared to $140 million for the corresponding period in 2017. This increase primarily reflects an $8 million increase in revenue tax expenses as a result of higher revenues, a $5 million credit in 2017 to establish a regulatory asset related to Nicor Gas' invested capital tax, and a $2 million increase in payroll taxes related to benefits under the new paid time off policy.

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 on the new paid time off policy. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on the Southern Company Gas Dispositions.

Gain on Dispositions, Net

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$353	N/M	$317	N/M

N/M - Not meaningful

In the third quarter 2018, gain on dispositions, net of $353 million reflects the July 1, 2018 sales of the assets of Elizabethtown Gas and Elkton Gas, the July 29, 2018 sale of Pivotal Utility Holdings, and the final working capital adjustment for the sale of Pivotal Home Solutions. The year-to-date 2018 amount also reflects a $36 million pre-tax loss on the June 4, 2018 sale of Pivotal Home Solutions recorded during the second quarter 2018. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

Goodwill Impairment

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$—	N/M	$42	N/M

N/M - Not meaningful

For year-to-date 2018, a goodwill impairment charge of $42 million was recorded during the first quarter 2018 in contemplation of the sale of Pivotal Home Solutions. See Notes (A) and (J) to the Condensed Financial Statements under "Goodwill and Other Intangible Assets" and "Southern Company Gas – Sale of Pivotal Home Solutions," respectively, herein for additional information.

Earnings from Equity Method Investments

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$2	6.3	$8	8.0

In the third quarter 2018, earnings from equity method investments were $34 million compared to $32 million for the corresponding period in 2017. For year-to-date 2018, earnings from equity method investments were $108 million compared to $100 million for the corresponding period in 2017. These increases were primarily due to higher earnings from Southern Company Gas' equity method investment in SNG. See Note (K) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

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Interest Expense, Net of Amounts Capitalized

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$1	2.0	$25	17.2

For year-to-date 2018, interest expense, net of amounts capitalized was $170 million compared to $145 million for the corresponding period in 2017. This increase was primarily due to $20 million of additional interest expense on new debt issuances and additional commercial paper borrowings, and a $5 million reduction in capitalized interest due to the Dalton Pipeline being placed in service in August 2017.

Other Income (Expense), Net

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(13)	(68.4)	$(9)	(30.0)

In the third quarter 2018, other income (expense), net was $6 million compared to $19 million for the corresponding period in 2017. This decrease was primarily due to a $14 million gain from the settlement of contractor litigation claims in 2017.

For year-to-date 2018, other income (expense), net was $21 million compared to $30 million for the corresponding period in 2017. This decrease was primarily due to $9 million lower gains from the settlement of contractor litigation claims in 2018 compared to the corresponding period in 2017.

See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas – Atlanta Gas Light's Pipeline Replacement Program" herein for additional information.

Income Taxes

Third Quarter 2018 vs. Third Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$264	N/M	$242	N/M

N/M - Not meaningful

In the third quarter 2018, income taxes were $316 million compared to $52 million for the corresponding period in 2017. For year-to-date 2018, income taxes were $475 million compared to $233 million for the corresponding period in 2017. These increases were primarily due to tax expense resulting from the Southern Company Gas Dispositions, including tax expense on the goodwill for which a deferred tax liability had not been previously provided, partially offset by a lower federal income tax rate and the flowback of excess deferred taxes as a result of the Tax Reform Legislation. In addition, third quarter and year-to-date 2017 included a $23 million deferred tax expense related to the enactment of the State of Illinois income tax legislation and new income tax apportionment factors in several states.

See Notes (H) and (J) to the Condensed Financial Statements under "Effective Tax Rate" and "Southern Company Gas," respectively, 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 gain on dispositions, net, 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 customer growth at gas distribution operations since

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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 marketing services, wholesale gas services, and gas midstream operations allows it to focus on a direct measure of adjusted operating margin 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.

	Third Quarter 2018			Third Quarter 2017			Year-to-Date 2018			Year-to-Date 2017
	(in millions)
Operating Income	$	374		$	67		$	810		$	551
Other operating expenses(a)	14			357			986			1,185
Revenue taxes(b)	(8		)	(8		)	(81		)	(74		)
Adjusted Operating Margin	$	380		$	416		$	1,715		$	1,662

(a) Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, goodwill impairment, and gain on dispositions, net.

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

Segment Information

Adjusted operating margin, operating expenses, and net income for each segment is illustrated in the tables below. See Note (L) to the Condensed Financial Statements herein for additional information.

	Third Quarter 2018									Third Quarter 2017
	Adjusted Operating Margin(a)			Operating Expenses(a)(b)			Net Income (Loss)(b)			Adjusted Operating Margin(a)			Operating Expenses(a)			Net Income (Loss)
	(in millions)									(in millions)
Gas distribution operations	$	355		$	(80	)	$	74		$	379		$	272		$	52
Gas marketing services	19			28			(8		)	51			48			1
Wholesale gas services	(8		)	14			(18		)	(25		)	11			(23		)
Gas midstream operations	15			15			16			12			13			14
All other	1			31			(18		)	2			8			(29		)
Intercompany eliminations	(2		)	(2		)	—			(3		)	(3		)	—
Consolidated	$	380		$	6		$	46		$	416		$	349		$	15

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

(b) Operating expenses for gas distribution operations and gas marketing services include the gain on dispositions, net. Net income for gas distribution operations and gas marketing services includes the gain on dispositions, net and the associated income tax expense. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

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	Year-to-Date 2018									Year-to-Date 2017
	Adjusted Operating Margin(a)			Operating Expenses(a)(b)(c)			Net Income (Loss)(c)			Adjusted Operating Margin(a)			Operating Expenses(a)			Net Income (Loss)
	(in millions)									(in millions)
Gas distribution operations	$	1,341		$	540		$	290		$	1,329		$	870		$	223
Gas marketing services	194			209			(71		)	213			149			36
Wholesale gas services	139			50			65			93			40			28
Gas midstream operations	44			44			54			28			38			38
All other	3			68			(44		)	7			22			(22		)
Intercompany eliminations	(6		)	(6		)	—			(8		)	(8		)	—
Consolidated	$	1,715		$	905		$	294		$	1,662		$	1,111		$	303

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

(b) Operating expenses for gas marketing services include a goodwill impairment charge of $42 million recorded during the first quarter 2018 in contemplation of the sale of Pivotal Home Solutions. See Note (A) to the Condensed Financial Statements under "Goodwill and Other Intangible Assets" and Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Pivotal Home Solutions" herein for additional information.

(c) Operating expenses for gas distribution operations and gas marketing services include the gain on dispositions, net. Net income for gas distribution operations and gas marketing services includes the gain on dispositions, net and the associated income tax expense. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein 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, maintenance, taxes, and overhead costs, and to earn a reasonable return on its investments.

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

On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy. See Note (J) under "Southern Company Gas" herein for additional information.

Third Quarter 2018 vs. Third Quarter 2017

In the third quarter 2018, net income increased $22 million, or 42.3%, compared to the corresponding period in 2017. This increase primarily relates to a $352 million decrease in operating expenses, partially offset by a $24 million decrease in adjusted operating margin, an $18 million decrease in total other income (expense), net, and a $288 million increase in income tax expense.

Excluding a $381 million decrease attributable to the utilities sold during 2018, including the related gain, operating expenses increased $29 million, which primarily reflects additional depreciation due to additional assets placed in service and increased compensation and benefit costs, partially offset by a decrease in bad debt expense. Excluding

191

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

a $29 million decrease in adjusted operating margin attributable to the utilities sold during 2018, adjusted operating margin increased $5 million, which primarily reflects additional revenue from continued infrastructure investments recovered through replacement programs and base rates, partially offset by lower rates and revenue deferrals for regulatory liabilities associated with Tax Reform Legislation impacts. The decrease in other income (expense), net primarily reflects a $14 million gain from the settlement of contractor litigation claims in 2017 and $7 million of additional interest expense primarily from the issuance of first mortgage bonds at Nicor Gas. Excluding a $314 million decrease attributable to the utilities sold in 2018, income tax expense decreased $26 million, primarily due to a lower federal income tax rate and the flowback of excess deferred taxes as a result of the Tax Reform Legislation.

Year-to-Date 2018 vs. Year-to-Date 2017

For year-to-date 2018, net income increased $67 million, or 30.0%, compared to the corresponding period in 2017. This increase primarily relates to a $12 millionincrease in adjusted operating margin and a $330 milliondecrease in operating expenses, partially offset by a $23 million decrease in total other income (expense), net, and a $252 million increase in income tax expense.

Excluding a $21 million decrease attributable to the utilities sold during 2018, adjusted operating margin increased $33 million, which primarily reflects additional revenue from continued infrastructure investments recovered through replacement programs and base rates and colder weather in 2018, partially offset by lower rates and revenue deferrals for regulatory liabilities associated with Tax Reform Legislation impacts. Excluding a $378 million decrease attributable to the utilities sold during 2018, including the related gain, operating expenses increased $48 million, which primarily reflects $27 million of additional depreciation primarily due to additional assets placed in service and increased compensation and benefit costs, partially offset by a decrease in bad debt expense. The decrease in other income (expense), net primarily reflects $16 million of additional interest expense primarily from the issuance of first mortgage bonds at Nicor Gas and commercial paper borrowings and $9 million lower gains from the settlement of contractor litigation claims during 2018 compared to the corresponding period in 2017, partially offset by an increase in interest income. Excluding a $307 million decrease attributable to the utilities sold in 2018, income tax expense decreased $55 million, primarily due to a lower federal income tax rate and the flowback of excess deferred taxes as a result of the Tax Reform Legislation.

Gas Marketing Services

Gas marketing services consists of several businesses that provide energy-related products to natural gas markets. 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 (J) under "Southern Company Gas" herein for additional information.

Third Quarter 2018 vs. Third Quarter 2017

In the third quarter 2018, net income decreased $9 million compared to the corresponding period in 2017. This decrease primarily relates to a $32 million decrease in adjusted operating margin, partially offset by a $20 million decrease in operating expenses and a $4 million decrease in income tax expense.

Excluding a $26 million decrease attributable to Pivotal Home Solutions, adjusted operating margin decreased $6 million, which primarily reflects a $5 million decrease due to the timing of revenue recognition for fixed and guaranteed bill revenue as a result of adopting a new revenue recognition standard. The decrease in operating expenses primarily reflects a $19 million decrease attributable to Pivotal Home Solutions. The decrease in income tax expense was driven by a higher pretax loss, partially offset by a lower federal income tax rate.

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Year-to-Date 2018 vs. Year-to-Date 2017

For year-to-date 2018, net income decreased $107 million compared to the corresponding period in 2017. This decrease primarily relates to a $19 million decrease in adjusted operating margin, a $60 million increase in operating expenses, and a $28 million increase in income tax expense.

Excluding a $33 million decrease attributable to Pivotal Home Solutions, adjusted operating margin increased $14 million, which primarily reflects colder weather in 2018. Excluding a $62 million increase attributable to Pivotal Home Solutions that includes the loss on disposition and the goodwill impairment charge, operating expense decreased $2 million primarily due to a decrease in depreciation and amortization primarily due to lower amortization of intangible assets as a result of fair value adjustments recorded during acquisition accounting, partially offset by higher bad debt expenses and compensation and benefit costs. The increase in income tax expense was driven by higher pretax earnings, partially offset by a lower federal income tax rate.

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.

Third Quarter 2018 vs. Third Quarter 2017

In the third quarter 2018, net loss decreased $5 million, or 21.7%, compared to the corresponding period in 2017. This increase primarily relates to a $17 millionincrease in adjusted operating margin, partially offset by a $3 millionincrease in operating expenses and an $8 million decrease in income tax benefit. Details of the increase in adjusted operating margin are provided in the table below. The increase in operating expenses primarily reflects higher compensation and benefit expense. The decrease in income tax benefit was driven by a lower pretax loss, partially offset by a lower federal income tax rate.

Year-to-Date 2018 vs. Year-to-Date 2017

For year-to-date 2018, net income increased $37 million, or 132.1%, compared to the corresponding period in 2017. This increase primarily relates to a $46 millionincrease in adjusted operating margin and a $2 million decrease in income tax expense, partially offset by a $10 millionincrease in operating expenses. Details of the increase in adjusted operating margin are provided in the table below. The increase in operating expenses primarily reflects higher compensation and benefit expense. The decrease in income tax expense was driven by a lower federal income tax rate.

	Third Quarter 2018			Third Quarter 2017			Year-to-Date 2018			Year-to-Date 2017
	(in millions)
Commercial activity recognized	$	33		$	3		$	212		$	80
Gain (loss) on storage derivatives	(3		)	4			(2		)	13
Gain (loss) on transportation and forward commodity derivatives	(33		)	(22		)	(70		)	14
Purchase accounting adjustments to fair value inventory and contracts	(5		)	(10		)	(1		)	(14		)
Adjusted operating margin	$	(8	)	$	(25	)	$	139		$	93

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Change in Commercial Activity

The increase in commercial activity in the third quarter and year-to-date 2018 compared to the corresponding periods in 2017 was primarily due to natural gas price volatility that was generated by favorable weather and a corresponding increase in power generation volumes coupled with decreased natural gas supply.

Change in Storage and Transportation Derivatives

Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the U.S. The volatility of natural gas commodity prices has a significant impact on Southern Company Gas' customer rates, long-term competitive position against other energy sources, and the ability of wholesale gas services to capture value from locational and seasonal spreads. Forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions in 2018 resulted in storage derivative losses. Transportation and forward commodity derivative losses in 2018 are primarily the result of widening transportation spreads due to favorable weather, which impacted forward prices at natural gas receipt and delivery points, primarily in the Northeast and Midwest regions.

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 September 30, 2018. A portion of wholesale gas services' storage inventory and transportation capacity is economically hedged with futures contracts, which results in the realization of substantially fixed net operating revenues.

	Storage withdrawal schedule
	Total storage(a)	Expected net operating gains(b)		Physical transportation transactions – expected net operating gains(c)
	(in mmBtu in millions)	(in millions)		(in millions)
2018	10.2	$	4	$	5
2019 and thereafter	26.1	9		65
Total at September 30, 2018	36.3	$	13	$	70

(a) At September 30, 2018, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $2.51 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 periods associated with the transportation derivative gains and (losses) during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative gains and losses that were previously recognized.

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 Midstream Operations

Gas midstream operations consists primarily of gas pipeline investments, with storage and fuels also aggregated into this segment. Gas pipeline investments include SNG, Horizon Pipeline, Atlantic Coast Pipeline, PennEast Pipeline, Dalton Pipeline, and Magnolia Enterprise Holdings, Inc. See Note (K) to the Condensed Financial Statements herein and Note 4 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K for additional information.

Third Quarter 2018 vs. Third Quarter 2017

In the third quarter 2018, net income increased $2 million, or 14.3%, compared to the corresponding period in 2017. This increase primarily relates to a $3 millionincrease in adjusted operating margin primarily due to the Dalton Pipeline being placed in service in August 2017 and a $2 million net increase in earnings from equity method investments in SNG and PennEast Pipeline, partially offset by a $2 million increase in interest expense primarily due to a reduction in capitalized interest after the Dalton Pipeline was placed in service.

Year-to-Date 2018 vs. Year-to-Date 2017

For year-to-date 2018, net income increased $16 million, or 42.1%, compared to the corresponding period in 2017. This increase primarily relates to a $16 millionincrease in adjusted operating margin primarily due to the Dalton Pipeline being placed in service in August 2017, partially offset by a reduction in storage revenues. The increase in net income also relates to an $8 million net increase in earnings from equity method investments primarily at SNG, partially offset by a $7 million increase in interest expense primarily due to a reduction in capitalized interest after the Dalton Pipeline was placed in service.

All Other

All other includes Southern Company Gas' investment in Triton, AGL Services Company, and Southern Company Gas Capital, as well as various corporate operating expenses that are not allocated to the reportable segments and interest income (expense) associated with affiliate financing arrangements.

Third Quarter 2018 vs. Third Quarter 2017

In the third quarter 2018, net loss decreased $11 million compared to the corresponding period in 2017. This decrease includes a $27 million decrease in income tax expense primarily related to the 2017 enactment of the State of Illinois income tax legislation and new income tax apportionment factors in several states and a $4 million decrease in interest expense, net of amounts capitalized primarily due to decreased interest expense on lower commercial paper borrowings, partially offset by $21 million of disposition-related costs and a lower federal income tax rate in 2018.

Year-to-Date 2018 vs. Year-to-Date 2017

For year-to-date 2018, net loss increased $22 million compared to the corresponding period in 2017. This increase primarily reflects a $46 millionincrease in operating expenses and a $2 million increase in interest expense, net of amounts capitalized, partially offset by a $27 million decrease in income tax expense. The increase in operating expenses primarily reflects $29 million of disposition-related costs and a $12 million increase in compensation expense resulting from the adoption of the new paid time off policy. 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 on the new paid time off policy. The decrease in income tax expense was primarily related to the 2017 enactment of the State of Illinois income tax legislation and new income tax apportionment factors in several states, partially offset by a lower federal income tax rate in 2018.

Segment Reconciliations

Reconciliations of operating income to adjusted operating margin for the third quarter2018 and 2017 are reflected in the following tables. See Note (L) to the Condensed Financial Statements herein for additional information.

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	Third Quarter 2018
	Gas Distribution Operations			Gas Marketing Services			Wholesale Gas Services			Gas Midstream Operations		All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	435		$	(9	)	$	(22	)	$	—	$	(30	)	$	—		$	374
Other operating expenses(a)	(72		)	28			14			15		31			(2		)	14
Revenue tax expense(b)	(8		)	—			—			—		—			—			(8		)
Adjusted Operating Margin	$	355		$	19		$	(8	)	$	15	$	1		$	(2	)	$	380

	Third Quarter 2017
	Gas Distribution Operations			Gas Marketing Services		Wholesale Gas Services			Gas Midstream Operations			All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	107		$	3	$	(36	)	$	(1	)	$	(6	)	$	—		$	67
Other operating expenses(a)	280			48		11			13			8			(3		)	357
Revenue tax expense(b)	(8		)	—		—			—			—			—			(8		)
Adjusted Operating Margin	$	379		$	51	$	(25	)	$	12		$	2		$	(3	)	$	416

	Year-to-Date 2018
	Gas Distribution Operations			Gas Marketing Services			Wholesale Gas Services		Gas Midstream Operations		All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	801		$	(15	)	$	89	$	—	$	(65	)	$	—		$	810
Other operating expenses(a)	621			209			50		44		68			(6		)	986
Revenue tax expense(b)	(81		)	—			—		—		—			—			(81		)
Adjusted Operating Margin	$	1,341		$	194		$	139	$	44	$	3		$	(6	)	$	1,715

	Year-to-Date 2017
	Gas Distribution Operations			Gas Marketing Services		Wholesale Gas Services		Gas Midstream Operations			All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	459		$	64	$	53	$	(10	)	$	(15	)	$	—		$	551
Other operating expenses(a)	944			149		40		38			22			(8		)	1,185
Revenue tax expense(b)	(74		)	—		—		—			—			—			(74		)
Adjusted Operating Margin	$	1,329		$	213	$	93	$	28		$	7		$	(8	)	$	1,662

(a) Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, goodwill impairment, and gain on dispositions, net.

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Company Gas' future earnings potential. 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 marketing services, wholesale gas services, and gas midstream operations 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, 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. 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.

On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC. Prior to its disposition, 2018 net income attributable to Pivotal Home Solutions, exclusive of the loss on the disposition and the related goodwill impairment charge, was immaterial. Southern Company Gas and American Water Enterprises LLC entered into a transition services agreement whereby Southern Company Gas provided certain administrative and operational services through November 4, 2018.

On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. Prior to these dispositions, 2018 net income attributable to Elizabethtown Gas and Elkton Gas was $45 million. Southern Company Gas and South Jersey Industries, Inc. entered into transition services agreements whereby Southern Company Gas will provide certain administrative and operational services through no later than January 31, 2020.

On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy. Prior to its disposition, 2018 net income attributable to Florida City Gas was $29 million. Southern Company Gas and NextEra Energy entered into a transition services agreement whereby Southern Company Gas will provide certain administrative and operational services through no later than July 29, 2020.

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 year-to-date 2018 net income is not necessarily indicative of the results to be expected for any other period.

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See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on these dispositions. See OVERVIEW – "Seasonality of Results" for additional information on seasonality.

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 financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for natural gas.

Environmental Remediation

Subsequent to the disposition of Elizabethtown Gas, Southern Company Gas is subject to environmental remediation liabilities associated with 40 former manufactured gas plant sites in four different states. Accrued environmental remediation costs decreased at September 30, 2018 primarily due to the disposition of $85 million that related to Elizabethtown Gas.

See Note (B) under "Environmental Matters–Environmental Remediation" to the Condensed Financial Statements 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 of Southern Company Gas under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

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 for additional information.

The Atlantic Coast Pipeline has experienced challenges to its permits since construction began earlier in 2018 and continues to work with the appropriate agencies to obtain the necessary permits. The PennEast Pipeline continues to work with state and federal agencies to obtain the required permits to begin construction. Any material permitting delays may impact forecasted capital expenditures and in-service dates. The ultimate outcome of these matters cannot be determined at this time.

Regulatory Matters

See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information regarding Southern Company Gas' regulatory matters.

Riders

On April 19, 2018, the Illinois Commission approved Nicor Gas' variable income tax adjustment rider. This rider provides for refund or recovery of changes in income tax expense that result from income tax rates that differ from those used in Nicor Gas' last rate case. Customer refunds, via bill credits, began on July 1, 2018 related to the impacts of the Tax Reform Legislation from January 25, 2018 through May 4, 2018. The impact of the Tax Reform Legislation subsequent to May 4, 2018 was addressed in Nicor Gas' approved rehearing request discussed herein under "Settled Base Rate Cases."

Natural Gas Cost Recovery

Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company Gas' revenues or net income, but will affect cash flows.

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Base Rate Cases

Settled Base Rate Cases

On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation. The Georgia PSC maintained Atlanta Gas Light's previously authorized earnings band based on a ROE between 10.55% and 10.95% and increased the allowed equity ratio by4% to an equity ratio of 55% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. Additionally, Atlanta Gas Light is required to file a traditional base rate case on or before June 1, 2019 for rates effective January 1, 2020.

On May 2, 2018, the Illinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately $44 million in annual base rate revenues became effective May 5, 2018. Nicor Gas' previously-authorized capital structure and ROE of9.8% were not addressed in the rehearing and remain unchanged. The impact of the Tax Reform Legislation prior to May 5, 2018 was addressed in the variable income tax rider discussed herein under "Riders."

On October 15, 2018, the Tennessee Public Utility Commission (PUC) approved a $1 million increase in Chattanooga Gas' annual base rate revenues, which was based on a projected test year ending June 30, 2019 and a ROE of 9.80%. The new rates became effective November 1, 2018.

Other

The Virginia Commission issued an order effective January 1, 2018 requiring utilities in the state to defer as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of the flowback of excess deferred income taxes. Through September 30, 2018, Virginia Natural Gas had deferred a total of $9 million. On August 30, 2018, Virginia Natural Gas filed an annual information form, which was subsequently revised on October 25, 2018, proposing to reduce annual base rates effective January 1, 2019 due to lower tax expense as a result of the lower corporate income tax rate and the impact of the flowback of excess deferred income taxes. This filing also proposes for Virginia Natural Gas to issue customer refunds, via bill credits, for the related amounts deferred as a regulatory asset. The Virginia Commission is expected to rule on the filing during the fourth quarter 2018. If approved as filed, Virginia Natural Gas' annual base rate revenues would be reduced by $14 million. The ultimate outcome of this matter cannot be determined at this time.

Asset Management Agreements

Upon closing the sales of Elizabethtown Gas and Elkton Gas, an affiliate of South Jersey Industries, Inc. assumed the asset management agreements with wholesale gas services for Elizabethtown Gas and Elkton Gas. The sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy did not impact the asset management agreement between wholesale gas services and Florida City Gas, which will remain in effect until its original maturity of March 31, 2019. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on these dispositions. For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Asset Management Agreements" of Southern Company Gas in Item 7 of the Form 10-K.

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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. Excluding the natural gas distribution utilities sold in July 2018, infrastructure expenditures incurred in the first nine months of 2018 were as follows:

Utility	Program	Year-to-Date 2018
		(in millions)
Nicor Gas	Investing in Illinois	$	267
Atlanta Gas Light	Georgia Rate Adjustment Mechanism (GRAM) infrastructure spending	217
Virginia Natural Gas	Steps to Advance Virginia's Energy	33
Total		$	517

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 3 to the financial statements of Southern Company Gas under "Regulatory Matters – Regulatory Infrastructure Programs" in Item 8 of the Form 10-K for additional information.

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company Gas in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.

Other Matters

Southern Company Gas is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the ordinary course of business. The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) 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 Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies and regulatory matters, and other matters being litigated which may affect future earnings potential.

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

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 Note 1 to the financial statements of Southern Company Gas 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.

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Recently Issued Accounting Standards

See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Company Gas in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company Gas' recently adopted accounting standards.

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

Southern Company Gas has elected the transition methodology provided by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, whereby it will apply the requirements of ASU 2016-02 on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. Southern Company Gas expects to elect the package of practical expedients provided by ASU 2016-02 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, Southern Company Gas expects to apply the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and to elect the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed. Southern Company Gas also expects to make accounting policy elections to account for short-term leases in all asset classes as off-balance sheet leases and to combine lease and non-lease components in the computations of lease obligations and right-of-use assets for most asset classes.

Southern Company Gas is continuing to complete the implementation of an information technology system to track and account for its leases and of changes to its internal controls and accounting policies to support the accounting for leases under ASU 2016-02. Southern Company Gas has substantially completed its lease inventory and determined its most significant leases involve real estate and fleet vehicles. While Southern Company Gas has not yet determined the ultimate impact, adoption of ASU 2016-02 is expected to result in recording lease liabilities and right-of-use assets on Southern Company Gas' balance sheet each totaling approximately $90 million, with no material impact on Southern Company Gas' statement of income.

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 September 30, 2018. 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 September 30, 2018, the amount of subsidiary retained earnings restricted to dividend totaled $786 million. This restriction did not impact Southern Company Gas' ability to meet its cash obligations.

Net cash provided from operating activities totaled $736 million for the first nine months of 2018, a decrease of $410 million from the corresponding period in 2017. The decrease was primarily due to higher income tax payments due to the net taxable gains from the Southern Company Gas Dispositions, partially offset by increased volumes of natural gas sold during the first nine months of 2018 as a result of colder weather compared to the prior year. Net cash provided from investing activities totaled $1.4 billion for the first nine months of 2018 primarily due to proceeds from the Southern Company Gas Dispositions, partially offset by gross property additions primarily related to utility capital expenditures and pre-approved rider and infrastructure investments recovered through

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

replacement programs at gas distribution operations as well as capital contributed to equity method investments in pipelines. Net cash used for financing activities totaled $2.2 billion for the first nine months of 2018 primarily due to net repayments of commercial paper borrowings, the redemption of gas facility revenue bonds, and common stock dividend payments and return of capital to Southern Company, partially offset by proceeds from the issuance of first mortgage 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 nine months of 2018 include $2.8 billion and $404 million in total assets and liabilities sold, respectively, associated with the Southern Company Gas Dispositions as described in Note (J) to the Condensed Financial Statements herein under "Southern Company Gas," a decrease of $109 million in natural gas for sale due to the use of stored natural gas, and a $1.4 billion decrease in notes payable primarily related to net repayments of commercial paper borrowings. Other significant balance sheet changes include decreases of $63 million in accounts payable as well as $109 million and $25 million in energy marketing receivables and payables, respectively, due to lower natural gas prices and an increase of $714 million in total property, plant, and equipment primarily due to utility capital expenditures and pre-approved rider and infrastructure investments recovered through replacement programs.

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 September 30, 2018, Southern Company Gas Capital repaid at maturity $155 million aggregate principal amount of 3.50% Series B Senior Notes. An additional $350 million will be required through September 30, 2019 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 3 to the consolidated financial statements of 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 through operating cash flows, external securities issuances, borrowings from financial institutions, and borrowings 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.

Southern Company Gas' current liabilities exceeded current assets by $469 million primarily as a result of $515 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. Southern Company Gas intends to utilize operating cash flows, external securities issuances, borrowings from financial institutions, borrowings and equity contributions from Southern Company, and the proceeds from its dispositions to fund its short-term capital needs. Southern Company Gas has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.

202

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At September 30, 2018, Southern Company Gas had $56 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2018 were as follows:

Company	Expires 2022		Unused
	(in millions)
Southern Company Gas Capital(a)	$	1,400	$	1,395
Nicor Gas	500		500
Total(b)	$	1,900	$	1,895

(a) Southern Company Gas guarantees the obligations of Southern Company Gas Capital.

(b) Pursuant to the credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.

See Note 6 to the consolidated financial statements of Southern Company Gas 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 multi-year credit arrangement of Southern Company Gas Capital and Nicor Gas (Facility) contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 70% for each of Southern Company Gas and Nicor Gas 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 September 30, 2018, both companies were in compliance with such covenant. The Facility does not contain a material adverse change clause at the time of borrowings.

Subject to applicable market conditions, the applicable company expects to renew or replace the Facility as needed, prior to expiration. In connection therewith, the applicable company may extend the maturity dates and/or increase or decrease the lending commitments thereunder. A portion of unused credit with banks provides liquidity support to Southern Company Gas.

Southern Company Gas makes short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Commercial paper borrowings are included in notes payable in the balance sheets.

Details of short-term borrowings were as follows:

	Short-Term Debt at September 30, 2018				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	$	—	—	%	$	18	2.4	%	$	573
Nicor Gas	136		2.4	%	67		2.3	%	154
Short-term loans:
Southern Company Gas	—		—	%	12		2.8	%	276
Total	$	136	2.4	%	$	97	2.3	%

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2018.

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

Additionally, prior to its sale, Pivotal Utility Holdings redeemed five series of gas facility revenue bonds issued under loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida totaling

203

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

$200 million during the second quarter 2018. See "Financing Activities" herein for additional information regarding the redemption of these bonds.

Credit Rating Risk

Southern Company Gas does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change below BBB- and/or Baa3. These contracts are for physical gas purchases and sales and energy price risk management. The maximum potential collateral requirement under these contracts at September 30, 2018 was approximately $10 million.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company Gas to access capital markets and would be likely to impact the cost at which it does so.

On September 28, 2018, Fitch assigned a negative rating outlook to the ratings of Southern Company and certain of its subsidiaries (including Southern Company Gas, Southern Company Gas Capital, and Nicor Gas).

As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Southern Company Gas, may be negatively impacted. Southern Company Gas and its regulated subsidiaries have taken actions to mitigate the resulting impacts, which, among other alternatives, include adjusting capital structure. Absent actions by Southern Company and its subsidiaries that fully mitigate the impacts, Southern Company Gas', Southern Company Gas Capital's, and Nicor Gas' credit ratings could be negatively affected. The Georgia PSC's May 15, 2018 approval of a stipulation for Atlanta Gas Light's annual rate adjustment maintained the previously authorized earnings band and increased the equity ratio to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information.

Financing Activities

The long-term debt on Southern Company Gas' balance sheets includes both principal and non-principal components. As of September 30, 2018, the non-principal components totaled $469 million, which consisted of the unamortized portions of the fair value adjustment recorded in purchase accounting, debt premiums, debt discounts, and debt issuance costs.

On January 4, 2018, Southern Company Gas issued a floating rate promissory note to Southern Company in an aggregate principal amount of $100 million bearing interest based on one-month LIBOR. On March 28, 2018, Southern Company Gas repaid this promissory note.

Prior to its sale, in the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of gas facility revenue bonds to be redeemed. Also in the second quarter 2018, Pivotal Utility Holdings, as borrower, and Southern Company Gas, as guarantor, entered into a $181 million short-term delayed draw floating rate bank term loan bearing interest based on one-month LIBOR, which Pivotal Utility Holdings used to repay the gas facility revenue bonds. In July 2018, Pivotal Utility Holdings repaid this short-term loan.

In May 2018, Southern Company Gas Capital borrowed $95 million pursuant to a short-term uncommitted bank credit arrangement, guaranteed by Southern Company Gas, bearing interest at a rate agreed upon by Southern Company Gas Capital and the bank from time to time and payable on no less than 30 days' demand by the bank. The proceeds of the loan were used to repay short-term debt. In July 2018, Southern Company Gas Capital repaid this loan.

In July 2018, Nicor Gas agreed to issue $300 million aggregate principal amount of first mortgage bonds in a private placement, $100 million of which was issued in August 2018 and $200 million of which was issued in

204

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

November 2018. The proceeds will be used for the repayment of short-term debt, capital expenditures, and other general corporate purposes.

Subsequent to September 30, 2018, Southern Company Gas Capital repaid at maturity $155 million aggregate principal amount of 3.50% Series B Senior Notes.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company Gas plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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 third quarter2018. 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 (D) and (I) 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 manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. For the weather risk associated with Nicor Gas, Southern Company Gas has a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower 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:

	Third Quarter 2018			Third Quarter 2017			Year-to-Date 2018			Year-to-Date 2017
	(in millions)
Contracts outstanding at beginning of period, assets (liabilities), net	$	(90	)	$	51		$	(106	)	$	12
Contracts realized or otherwise settled	6			(6		)	57			(22		)
Current period changes(a)	(34		)	(16		)	(69		)	39
Contracts outstanding at the end of period, assets (liabilities), net	$	(118	)	$	29		$	(118	)	$	29
Netting of cash collateral	189			76			189			76
Cash collateral and net fair value of contracts outstanding at end of period(b)	$	71		$	105		$	71		$	105

(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 $5 million at September 30, 2018 and includes premium and the intrinsic value associated with weather derivatives of $13 million at September 30, 2017.

205

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The maturities of Southern Company Gas' energy-related derivative contracts at September 30, 2018 were as follows:

				Fair Value Measurements
				September 30, 2018
	Total Fair Value			Maturity
				Year 1			Years 2 & 3			Years 4 and thereafter
	(in millions)
Level 1(a)	$	(145	)	$	(8	)	$	(106	)	$	(31	)
Level 2(b)	27			2			25			—
Fair value of contracts outstanding at end of period(c)	$	(118	)	$	(6	)	$	(81	)	$	(31	)

(a) Valued using NYMEX futures prices.

(b) Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.

(c) Excludes cash collateral of $189 million as well as premium and associated intrinsic value associated with weather derivatives of $5 million at September 30, 2018.

206

NOTES TO THE CONDENSED FINANCIAL STATEMENTS

FOR

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF 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	208
B	Contingencies and Regulatory Matters	218
C	Revenue from Contracts with Customers	238
D	Fair Value Measurements	244
E	Stockholders' Equity	249
F	Financing	251
G	Retirement Benefits	255
H	Income Taxes	259
I	Derivatives	261
J	Acquisitions and Dispositions	276
K	Variable Interest Entity and Equity Method Investments	280
L	Segment and Related Information	282

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
Alabama Power	A, B, C, D, F, G, H, I
Georgia Power	A, B, C, D, F, G, H, I
Gulf Power	A, B, C, D, F, G, H, I, J
Mississippi Power	A, B, C, D, F, G, H, I
Southern Power	A, B, C, D, E, F, G, H, I, J, K
Southern Company Gas	A, B, C, D, F, G, H, I, J, K, L

207

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF 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, 2017 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 September 30, 2018 and 2017. 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

See Note 1 to the financial statements of the registrants under "Recently Issued Accounting Standards" in Item 8 of the Form 10-K for additional information.

Revenue

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry-specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. ASC 606 became effective on January 1, 2018 and the registrants adopted it using the modified retrospective method applied to open contracts and only to the version of the contracts in effect as of January 1, 2018. In accordance with the modified retrospective method, the registrants' previously issued financial statements have not been restated to comply with ASC 606 and the registrants did not have a cumulative-effect adjustment to retained earnings. The adoption of ASC 606 had no significant impact on the timing of revenue recognition compared to previously reported results; however, it requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers, which are included in Note (C).

208

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

ASC 606 provided additional clarity on financial statement presentation that resulted in reclassifications into other revenues and other operations and maintenance from other income/(expense), net at Alabama Power and Georgia Power related to certain unregulated sales of products and services. In addition, contract assets related to certain fixed retail revenues at Georgia Power and Southern Company's unregulated distributed generation business have been reclassified from unbilled revenue in accordance with the guidance in ASC 606. These reclassifications did not affect the timing or amount of revenues recognized or cash flows. ASC 606 also provided additional guidance on revenue recognized over time, resulting in a change in the timing of revenue recognized from guaranteed and fixed billing arrangements at Southern Company Gas. The changes in natural gas revenues recognized in the third quarter and year-to-date 2018 relate primarily to the seasonal nature of natural gas usage.

The net impact of accounting for revenue under ASC 606 decreased Southern Company's and Southern Company Gas' consolidated net income by $4 million for the three months ended September 30, 2018 and increased Southern Company's and Southern Company Gas' consolidated net income by $1 million for the nine months ended September 30, 2018.

The specific impacts of applying ASC 606 to revenues from contracts with customers on the financial statements of Southern Company, Alabama Power, Georgia Power, and Southern Company Gas compared to previously recognized guidance is shown below.

209

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	For the Three Months Ended September 30, 2018							For the Nine Months Ended September 30, 2018
Condensed Statements of Income	As Reported		Balances Without Adoption of ASC 606		Effect of Change			As Reported		Balances Without Adoption of ASC 606		Effect of Change
	(in millions)							(in millions)
Southern Company
Natural gas revenues	$	492	$	497	$	(5	)	$	2,806	$	2,805	$	1
Other revenues	199		198		1			1,007		1,003		4
Other operations and maintenance	1,404		1,387		17			4,217		4,178		39
Operating income	2,174		2,195		(21		)	3,613		3,647		(34		)
Other income (expense), net	57		41		16			195		160		35
Earnings (loss) before income taxes	1,845		1,850		(5		)	2,629		2,628		1
Income taxes (benefit)	623		624		(1		)	598		598		—
Consolidated net income (loss)	1,222		1,226		(4		)	2,031		2,030		1
Consolidated net income (loss) attributable to Southern Company	1,164		1,168		(4		)	1,948		1,947		1
Alabama Power
Other revenues	$	68	$	59	$	9		$	199	$	173	$	26
Other operations and maintenance	401		390		11			1,191		1,159		32
Operating income	561		563		(2		)	1,313		1,319		(6		)
Other income (expense), net	9		7		2			24		18		6
Georgia Power
Other revenues	$	121	$	97	$	24		$	349	$	287	$	62
Other operations and maintenance	460		437		23			1,325		1,268		57
Operating income (loss)	991		990		1			1,032		1,027		5
Other income (expense), net	30		31		(1		)	104		109		(5		)
Southern Company Gas
Natural gas revenues	$	487	$	492	$	(5	)	$	2,829	$	2,828	$	1
Operating income	374		379		(5		)	810		809		1
Earnings before income taxes	362		367		(5		)	769		768		1
Income taxes	316		317		(1		)	475		475		—
Net income (loss)	46		50		(4		)	294		293		1

210

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	For the Nine Months Ended September 30, 2018
Condensed Statements of Cash Flows	As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)
Southern Company
Consolidated net income	$	2,031		$	2,030		$	1
Changes in certain current assets and liabilities:
Receivables	37			27			10
Other current assets	(90		)	(80		)	(10		)
Other current liabilities	(67		)	(68		)	1
Georgia Power
Changes in certain current assets and liabilities:
Receivables	$	(205	)	$	(242	)	$	37
Other current assets	(36		)	1			(37		)
Southern Company Gas
Net income	$	294		$	293		$	1
Changes in certain current assets and liabilities:
Other current liabilities	35			34			1

	At September 30, 2018
Condensed Balance Sheets	As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)
Southern Company
Unbilled revenues	$	738		$	776		$	(38	)
Other accounts and notes receivable	690			691			(1		)
Other current assets	232			193			39
Other current liabilities	763			764			(1		)
Retained earnings	9,048			9,047			1
Georgia Power
Unbilled revenues	$	245		$	310		$	(65	)
Other accounts and notes receivable	96			97			(1		)
Other current assets	91			25			66
Southern Company Gas
Other current liabilities	122			123			(1		)
Accumulated deficit	(273		)	(274		)	1

Other

In 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating,

211

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

investing, and financing activities in the statements of cash flows. In addition, the net change in cash and cash equivalents during the period includes amounts generally described as restricted cash or restricted cash equivalents. The registrants adopted ASU 2016-18 effective January 1, 2018 with no material impact on their financial statements. Southern Company, Southern Power, and Southern Company Gas retrospectively applied ASU 2016-18 effective January 1, 2018 and have restated prior periods in the statements of cash flows by immaterial amounts. The change in restricted cash in the statements of cash flows was previously disclosed in operating activities for Southern Company and Southern Company Gas and in investing activities for Southern Company and Southern Power. See "Restricted Cash" herein for additional information.

In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the statements of income outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. The registrants adopted ASU 2017-07 effective January 1, 2018 with no material impact on their financial statements. ASU 2017-07 has been applied retrospectively for the presentation of the service cost component and the other components of net periodic benefit costs in the statements of income for Southern Company, the traditional electric operating companies, and Southern Company Gas. Since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017, no retrospective presentation of Southern Power's net periodic benefits costs is required. The requirement to limit capitalization to the service cost component of net periodic benefit costs has been applied on a prospective basis from the date of adoption for all registrants. The presentation changes resulted in a decrease in operating income and an increase in other income for the three and nine months ended September 30, 2018 and 2017 for Southern Company, the traditional electric operating companies, and Southern Company Gas.

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12). ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The registrants adopted ASU 2017-12 effective January 1, 2018 with no material impact on their financial statements. See Note (I) for disclosures required by ASU 2017-12.

On February 14, 2018, the FASB issued ASU No. 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (ASU 2018-02) to address the application of ASC 740, Income Taxes (ASC 740) to certain provisions of the Tax Reform Legislation. ASU 2018-02 specifically addresses the ASC 740 requirement that the effect of a change in tax laws or rates on deferred tax assets and liabilities be included in income from continuing operations, even when the tax effects were initially recognized directly in OCI at the previous rate, which strands the income tax rate differential in accumulated OCI. The amendments in ASU 2018-02 allow a reclassification from accumulated OCI to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. The registrants adopted ASU 2018-02 effective January 1, 2018 with no material impact on their financial statements.

Asset Retirement Obligations

See Note 1 to the financial statements of Southern Company and the traditional electric operating companies under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information regarding each company's AROs and the EPA's Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule).

212

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

As of September 30, 2018, details of the AROs, including those related to the CCR Rule, included in the condensed balance sheets of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power were as follows:

	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Balance at December 31, 2017	$	4,824		$	1,709		$	2,638		$	142		$	174
Liabilities incurred	2			—			—			—			—
Liabilities settled	(160		)	(31		)	(82		)	(23		)	(22		)
Accretion	153			72			70			3			4
Cash flow revisions	1,510			1,451			(32		)	42			21
Reclassification to held for sale	(164		)	—			—			—			—
Balance at September 30, 2018	$	6,165		$	3,201		$	2,594		$	164		$	177

In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related to the CCR Rule. Mississippi Power also recorded an increase of approximately $11 million to its AROs related to an ash pond at Plant Greene County, which is jointly-owned with Alabama Power. The revised cost estimates were based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power, including Plant Greene County. During the second quarter 2018, Alabama Power's management completed its analysis of these studies which indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology. As the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material.

Georgia Power continues to perform engineering studies related to its plans to close the ash ponds at all of its generating plants, including Plant Scherer Unit 3, which is jointly owned with Gulf Power, in compliance with federal and state CCR rules. Georgia Power also continues to refine its closure strategy and cost estimates for each ash pond and is preparing permit applications as required by the State of Georgia CCR rule. While Georgia Power and Gulf Power believe their recorded liabilities for ash pond closures appropriately reflect their obligations under the current closure strategies they have elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase their ARO liabilities. It is not currently possible to quantify the impacts of any increase related to a change in closure strategies and/or ongoing engineering studies for the current closure strategies, and the timing of future cash outflows is indeterminable at this time; however, the impact on Georgia Power's and Gulf Power's ARO liabilities is expected to be material. As permit applications advance, engineering studies continue, and the timing of individual ash pond closures develops further during the fourth quarter 2018, Georgia Power and Gulf Power will record any necessary changes to their ARO liabilities.

The traditional electric operating companies expect to continue to periodically update their ARO cost estimates, which could increase further, as additional information becomes available. 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 this matter cannot be determined at this time.

In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in an increase in Southern Company's and Alabama Power's ARO liability of approximately $300 million. See "Nuclear Decommissioning" below for additional information.

Georgia Power expects to complete updated decommissioning cost site studies for Plant Hatch and Plant Vogtle Units 1 and 2 in the fourth quarter 2018, which could result in additional changes to Southern Company's and Georgia Power's ARO liability. The ultimate outcome of these studies cannot be determined at this time.

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(UNAUDITED)

The reclassification of a portion of the ARO liability to liabilities held for sale by Southern Company represents the AROs related to Gulf Power. See Note (J) under "Southern Company's Sale of Gulf Power" and "Assets Held for Sale" for additional information.

Nuclear Decommissioning

See Note 1 to the financial statements of Southern Company and Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated costs of decommissioning based on the 2018 site study are as follows:

Decommissioning periods:
Beginning year	2037
Completion year	2076
	(in millions)
Site study costs:
Radiated structures	$	1,621
Non-radiated structures	99
Total site study costs	$	1,720

The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.

For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and a trust earnings rate of 7.0%. The next site study is expected to be completed in 2023.

Amounts previously contributed to the external trust funds are currently projected to be adequate to meet the updated decommissioning obligations. Alabama Power will continue to provide site specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with the NRC and other applicable requirements.

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Goodwill and Other Intangible Assets

The following table presents year-to-date changes in goodwill balances for Southern Company and Southern Company Gas:

	Goodwill
	Southern Company				Southern Company Gas
					Gas Distribution Operations			Gas Marketing Services			Total
	(in millions)
Balance at December 31, 2017	$	6,268			$	4,702		$	1,265		$	5,967
Impairment(a)	(42		)		—			(42		)	(42		)
Dispositions(b)	(910		)		(668		)	(242		)	(910		)
Balance at September 30, 2018	$	5,315		(c)	$	4,034		$	981		$	5,015

(a) On April 11, 2018, Southern Company Gas entered into a stock purchase agreement for the sale of Pivotal Home Solutions. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded in the first quarter 2018. See Note (J) under "Southern Company Gas" for additional information.

(b) Gas distribution operations reflects goodwill allocated to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold during the third quarter 2018. Gas marketing services reflects goodwill associated with Pivotal Home Solutions, which was sold on June 4, 2018. See Note (J) under "Southern Company Gas" for additional information.

(c) Total does not add due to rounding.

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.

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(UNAUDITED)

Other intangible assets were as follows:

	At September 30, 2018							At December 31, 2017
	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(*)	$	223	$	(87	)	$	136	$	288	$	(83	)	$	205
Trade names(*)	70		(18		)	52		159		(17		)	142
Storage and transportation contracts	64		(49		)	15		64		(34		)	30
PPA fair value adjustments	456		(66		)	390		456		(47		)	409
Other	11		(5		)	6		17		(5		)	12
Total other intangible assets subject to amortization	$	824	$	(225	)	$	599	$	984	$	(186	)	$	798
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—			75		75		—			75
Total other intangible assets	$	899	$	(225	)	$	674	$	1,059	$	(186	)	$	873
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	456	$	(66	)	$	390	$	456	$	(47	)	$	409
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services(*)
Customer relationships	$	156	$	(78	)	$	78	$	221	$	(77	)	$	144
Trade names	26		(6		)	20		115		(9		)	106
Wholesale gas services
Storage and transportation contracts	64		(49		)	15		64		(34		)	30
Total other intangible assets subject to amortization	$	246	$	(133	)	$	113	$	400	$	(120	)	$	280

(*) Balances as of September 30, 2018 reflect Southern Company Gas' sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

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(UNAUDITED)

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Nine Months Ended
	September 30, 2018
	(in millions)
Southern Company	$	21	$	70
Southern Power	$	6	$	19
Southern Company Gas	$	12	$	42

Restricted Cash

The registrants adopted ASU 2016-18 as of January 1, 2018. See "Recently Adopted Accounting Standards – Other" herein for additional information.

At December 31, 2017, Southern Power had restricted cash primarily related to certain acquisitions and construction projects. At both September 30, 2018 and December 31, 2017, 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 September 30, 2018 and/or December 31, 2017:

	Southern Company			Southern Company Gas
	(in millions)
At September 30, 2018
Cash and cash equivalents	$	1,847		$	56
Cash and cash equivalents classified as assets held for sale	37			—
Restricted cash:
Other accounts and notes receivable	6			6
Total cash, cash equivalents, and restricted cash	$	1,891	(*)	$	62

(*) Total does not add due to rounding.

	Southern Company		Southern Power		Southern Company Gas
	(in millions)
At December 31, 2017
Cash and cash equivalents	$	2,130	$	129	$	73
Restricted cash:
Other accounts and notes receivable	5		—		5
Deferred charges and other assets	12		11		—
Total cash, cash equivalents, and restricted cash	$	2,147	$	140	$	78

Natural Gas for Sale

Southern Company Gas' natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a WACOG basis.

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.

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(UNAUDITED)

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. Southern Company Gas had no inventory decrement at September 30, 2018. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's or Southern Company Gas' net income.

Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower of weighted average cost or current market price, with cost determined 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 had no material LOCOM adjustment in any period presented.

Hypothetical Liquidation at Book Value

Southern Power has consolidated renewable generation projects that are partially funded by a third-party tax equity investor. The related contractual provisions represent profit-sharing arrangements because the allocations of cash distributions and tax benefits are not based on fixed ownership percentages. Therefore, the noncontrolling interest is accounted for under a balance sheet approach utilizing the hypothetical liquidation at book value (HLBV) method. The HLBV method calculates each partner's share of income based on the change in net equity the partner can legally claim in a hypothetical liquidation at the end of the period compared to the beginning of the period.

(B) CONTINGENCIES AND REGULATORY MATTERS

See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.

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 predicted 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, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In June 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. In July 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition in September

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(UNAUDITED)

2017. On March 29, 2018, the U.S. District Court for the Northern District of Georgia, Atlanta Division, issued an order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers of Southern Company and Mississippi Power and dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. On April 26, 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. On August 10, 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal.

In February 2017, Jean Vineyard filed a shareholder derivative lawsuit and, in May 2017, Judy Mesirov filed a shareholder derivative lawsuit, each in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. In August 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On April 25, 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.

In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On May 4, 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.

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

Alabama Power

On March 2, 2018, the Alabama Department of Environmental Management (ADEM) issued proposed administrative orders assessing a penalty of $1.25 million to Alabama Power for unpermitted discharge of fluids and/or pollutants to groundwater at five electric generating plants. The orders were finalized and Alabama Power paid the penalty on September 27, 2018. This matter is now concluded.

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 municipal franchise fees (all of which are remitted 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 August 2017. On June 18, 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. On August 27, 2018,

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Georgia Power filed a motion to stay the case and requested the trial court refer the case to the Georgia PSC for a declaratory ruling. Georgia Power believes the plaintiffs' claims have no merit and will continue to vigorously defend itself in this matter. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether any class will ultimately be certified; the scope of such a class, if certified; 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 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled to include, among other things, Southern Company as a defendant. The individual plaintiff alleged that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches unjustly enriched Mississippi Power and Southern Company. The plaintiffs sought unspecified actual damages and punitive damages; asked the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; asked the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and sought attorney's fees, costs, and interest. The plaintiffs also sought an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. In June 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. In July 2017, the plaintiffs filed notice of an appeal. On July 13, 2018, Mississippi Power and Southern Company reached a settlement agreement with the plaintiffs and the plaintiffs' appeal was dismissed with prejudice. The settlement had no material impact on Southern Company's or Mississippi Power's financial statements.

On May 18, 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in September 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. 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. Southern Company and Mississippi Power will vigorously defend themselves in this matter, the ultimate outcome of which cannot be determined at this time.

On May 14, 2018, Mississippi Power's claim for lost revenue resulting from the Deepwater Horizon oil spill in the Gulf of Mexico in 2010 was settled. The settlement proceeds of $18 million, net of expenses and income tax, are included in Southern Company's and Mississippi Power's earnings for the nine months ended September 30, 2018.

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 November 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 May 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, (State Court lawsuit) against XL Insurance America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from the hail storm and McCarthy's installation practices. On June 1, 2018, the court in the State Court lawsuit granted Roserock's motion for partial summary judgment, finding that the insurers were in breach of contract and in violation of the Texas Insurance Code for failing to pay any monies owed for the hail claim. In addition to the State Court lawsuit, lawsuits were filed between Roserock

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

and McCarthy, as well as other parties, and that litigation has been consolidated in the U.S. District Court for the Western District of Texas. Southern Power intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.

Southern Company Gas

Nicor Energy Services Company, doing business as Pivotal Home Solutions, formerly a wholly-owned subsidiary of Southern Company Gas, was a defendant in a putative class action initially filed in 2017 in the state court in Indiana. The plaintiffs purported to represent a class of the customers who purchased products from Nicor Energy Services Company and alleged that the marketing, sale, and billing of the products violated the Indiana Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. In 2018, Nicor Energy Services Company was named in a second class action filed in the state court of Ohio asserting nearly identical allegations and legal claims. The plaintiffs sought, on behalf of the classes they purported to represent, actual and punitive damages, interest costs, attorney fees, and injunctive relief. To facilitate the sale of Pivotal Home Solutions, Southern Company Gas retained most of the financial responsibility for these lawsuits following the completion of the sale. On June 12, 2018, the parties settled these claims and Southern Company Gas recorded an $11 million charge, which is included in other operations and maintenance expenses for the nine months ended September 30, 2018.

Environmental Matters

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 all received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.

Georgia Power's environmental remediation liability was $25 million and $22 million as of September 30, 2018 and December 31, 2017, 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.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $48 million and $52 million as of September 30, 2018 and December 31, 2017, respectively. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power's substations. The schedule for completion of the remediation projects is subject to FDEP approval.

At September 30, 2018, Southern Company Gas' environmental remediation liability was $294 million based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. At December 31, 2017, Southern Company Gas' total environmental remediation liability was $388 million, of which $85 million related to Elizabethtown Gas, which was sold on July 1, 2018. 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. See Note (J) under "Southern Company Gas" for information regarding Southern Company Gas' sale of Elizabethtown Gas.

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, Gulf Power, or Southern Company Gas.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

FERC Matters

Market-Based Rate Authority

See Note 3 to the financial statements of Southern Company, the traditional electric operating companies, and Southern Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies'and Southern Power's 2014 and 2017 triennial market power analyses.

On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companiesand Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companiesand Southern Power made the compliance filing required by the order. These proceedings are concluded.

Open Access Transmission Tariff

On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companiesclaiming that the current11.25%base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies'open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than8.65%and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companiesfiled their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material to Southern Company's or the traditional electric operating companies' results of operations. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At September 30, 2018, the amount of over-recovered wholesale MRA fuel costs included in other regulatory liabilities, current on the condensed balance sheet was approximately $7 million compared to an immaterial amount at December 31, 2017. Under-recovered wholesale MB fuel costs included in the balance sheets were immaterial at September 30, 2018 and December 31, 2017.

Cooperative Energy Power Supply Agreement

See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Cooperative Energy Power Supply Agreement" in Item 8 of the Form 10-K for additional information regarding Cooperative Energy's network integration transmission service agreement (NITSA) with SCS.

On March 23, 2018, the FERC accepted the amendment to the NITSA between Cooperative Energy and SCS, effective April 1, 2018.

Regulatory Matters

Alabama Power

See Note 3 to the financial statements of Southern Company and Alabama Power under "Regulatory Matters – Alabama Power" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional

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(UNAUDITED)

information regarding Alabama Power's recovery of retail costs through various regulatory clauses and accounting orders. The balance of each regulatory clause recovery on the balance sheet follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2018		December 31, 2017
		(in millions)
Rate CNP Compliance	Deferred under recovered regulatory clause revenues	$	—	$	17
	Under recovered regulatory clause revenues	7		—
Rate CNP PPA	Deferred under recovered regulatory clause revenues	30		12
Retail Energy Cost Recovery	Deferred under recovered regulatory clause revenues	58		25
	Under recovered regulatory clause revenues	41		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	24		38

On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. At September 30, 2018, Alabama Power's equity ratio was approximately 47%.

Rate RSE

The approved modifications to Rate RSE became effective June 2018 and are applicable for January 2019 billings and thereafter. The modifications include reducing the top of the allowed weighted common equity return (WCER) range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range.

Generally, if Alabama Power's actual WCER range is between 6.15% and 7.65%, customers will receive 25% of the amount between 6.15% and 6.65%, 40% of the amount between 6.65% and 7.15%, and 75% of the amount between 7.15% and 7.65%. Customers will receive all amounts in excess of an actual WCER of 7.65%.

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

In accordance with an established retail tariff that provides for an interim adjustment to customer billings to recognize the impact of a change in the statutory income tax rate, Alabama Power has returned $151 million through September 30, 2018 and anticipates returning a total of approximately $257 million to retail customers through bill credits by December 31, 2018 as a result of the change in the federal income tax rate under the Tax Reform Legislation.

Rate ECR

On May 1, 2018, the Alabama PSC approved an increase to Rate ECR from 2.015 cents per KWH to 2.353 cents per KWH effective July 2018 which is expected to result in additional collections of approximately $100 million through December 31, 2018. The approved increase in the Rate ECR factor will have no significant effect on Alabama Power's net income, but will increase operating cash flows related to fuel cost recovery in 2018. Absent any further order from the Alabama PSC, in January 2019, the rate will return to the originally authorized 5.910 cents per KWH.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Accounting Order

On May 1, 2018, the Alabama PSC approved an accounting order that authorizes Alabama Power to defer the benefits of federal excess deferred income taxes associated with the Tax Reform Legislation for the year ending December 31, 2018 as a regulatory liability and to use up to $30 million of such deferrals to offset under recovered amounts under Rate ECR. Any remaining amounts will be used for the benefit of customers as determined by the Alabama PSC. As of September 30, 2018, Alabama Power had applied the full $30 million to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 5 to the financial statements of Southern Company and Alabama Power under "Federal Tax Reform Legislation" and of Alabama Power under "Current and Deferred Income Taxes" in Item 8 of the Form 10-K for additional information.

Plant Greene County

Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information regarding the joint ownership agreement. On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP) with the Mississippi PSC, which proposes a four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively. Mississippi Power's proposed Plant Greene County unit retirements would require the completion of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will monitor Mississippi Power's proposed RMP and associated regulatory process as well as the proposed transmission and system reliability improvements. Alabama Power will review all the facts and circumstances and will evaluate all its alternatives prior to reaching a final determination on the ongoing operations of Plant Greene County. The ultimate outcome of this matter cannot be determined at this time.

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 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 "Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Nuclear Construction" and Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also see "Fuel Cost Recovery" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" and Georgia Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery.

Rate Plans

See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's 2013 ARP and the Georgia PSC's 2018 order related to the Tax Reform Legislation.

On April 3, 2018, the Georgia PSC approved a settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation (Georgia Power Tax Reform Settlement Agreement). Pursuant to the Georgia Power Tax Reform Settlement Agreement, to reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power will refund to customers a total of $330 million through bill credits. Georgia Power issued bill credits of approximately $130 million in October 2018 and will issue bill credits of approximately $95 million in June 2019 and $105 million in February 2020. In addition, Georgia Power is deferring as a regulatory liability (i) the revenue equivalent of the tax expense reduction resulting from

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legislation lowering the Georgia state income tax rate from 6.00% to 5.75% in 2019 and (ii) the entire benefit of approximately $700 million in federal and state excess accumulated deferred income taxes. At September 30, 2018, Georgia Power's related regulatory liability balance totaled$655 million.The amortization of these regulatory liabilities is expected to be addressed in Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. If there is not a base rate case in 2019, customers will receive $185 million in annual bill credits beginning in 2020, with any additional federal and state income tax savings deferred as a regulatory liability, until Georgia Power's next base rate case.

To address the negative cash flow and credit metric impacts of the Tax Reform Legislation, the Georgia PSC also approved an increase in Georgia Power's retail equity ratio to the lower of (i) Georgia Power's actual common equity weight in its capital structure or (ii) 55%, until Georgia Power's next base rate case. At September 30, 2018, Georgia Power's actual retail common equity ratio (on a 13-month average basis) was approximately 53%. Benefits from reduced federal income tax rates in excess of the amounts refunded to customers will be retained by Georgia Power to cover the carrying costs of the incremental equity in 2018 and 2019.

Fuel Cost Recovery

As of September 30, 2018 and December 31, 2017, Georgia Power's under recovered fuel balance totaled $105 million and $165 million, respectively, and is included as under recovered fuel clause revenues on Southern Company's and Georgia Power's condensed balance sheets. On August 16, 2018, the Georgia PSC approved the deferral of Georgia Power's next fuel case to no later than March 16, 2020, with rates to be effective June 1, 2020. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million.

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 or Georgia Power's revenues or net income, but will affect cash flow.

Storm Damage Recovery

See Note 3 to the financial statements of Southern Company under "Regulatory Matters–Georgia Power– Storm Damage Recovery" and Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.

Georgia Power is accruing$30 millionannually through December 31, 2019, as provided in the 2013 ARP, for incremental operations and maintenance costs of damage from major storms to its transmission and distribution facilities. As of September 30, 2018, the total balance in Georgia Power's regulatory asset related to storm damage was$311 million. During October 2018, Hurricane Michael caused significant damage to Georgia Power's transmission and distribution facilities. Georgia Power currently estimates the costs of repairing the damage will total approximately$125 million to $150 million, which will be charged to Georgia Power's storm damage reserve or capitalized. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. The ultimate outcome of this matter cannot be determined at this time.

Gulf Power

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's rates and charges for service to retail customers.

Storm Damage Cost Recovery

See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the Form 10-K for information on how Gulf Power maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generating facilities and other property.

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On October 10, 2018, Hurricane Michael made landfall on the Gulf Coast of Florida causing substantial damage in Gulf Power's service territory. Gulf Power currently estimates the costs of repairing the damages to its transmission and distribution lines and uninsured facilities will total approximately $350 million to $400 million, which primarily will be charged to Gulf Power's property damage reserve or capitalized. At September 30, 2018, Gulf Power had a balance of approximately $48 million in its property damage reserve. In accordance with the 2017 Gulf Power Rate Case Settlement Agreement, Gulf Power can petition the Florida PSC to seek recovery of the costs associated with Hurricane Michael, along with replenishing the property damage reserve to approximately $40 million. Any recovery from customers would begin, on an interim basis, 60 days following the filing of the cost recovery petition. The ultimate outcome of this matter cannot be determined at this time.

Retail Base Rate Case

See Note 3 to the financial statements of Southern Company and Gulf Power under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" and "Retail Regulatory Matters – Retail Base Rate Cases," respectively, in Item 8 of the Form 10-K for additional information.

As a continuation of a settlement agreement approved by the Florida PSC in April 2017 (2017 Gulf Power Rate Case Settlement Agreement), on March 26, 2018, the Florida PSC approved a stipulation and settlement agreement among Gulf Power and three intervenors addressing the retail revenue requirement effects of the Tax Reform Legislation (Gulf Power Tax Reform Settlement Agreement).

The Gulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates implemented April 1, 2018 and also provided for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through a reduced fuel cost recovery rate over the remainder of 2018. Through September 30, 2018, approximately $53 million of this refund has been reflected in customer bills. As a result of the Gulf Power Tax Reform Settlement Agreement, the Florida PSC also approved an increase in Gulf Power's maximum equity ratio from 52.5% to 53.5% for all retail regulatory purposes.

As part of the Gulf Power Tax Reform Settlement Agreement, a limited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was initiated on April 30, 2018. On October 30, 2018, the Florida PSC approved a $9.6 million annual reduction in base rate revenues effective January 2019, which concluded this proceeding. Through September 30, 2018, Gulf Power has deferred $7 million of related 2018 tax benefits as a regulatory liability to be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.

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Cost Recovery Clauses

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders, as approved by the Florida PSC. Regulatory clause recovery balances included in the balance sheets are as follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2018		December 31, 2017
		(in millions)
Fuel Cost Recovery	Under recovered regulatory clause revenues	$	—	$	22
Fuel Cost Recovery	Other regulatory liabilities, current	23		—
Purchased Power Capacity Recovery	Other regulatory liabilities, current	4		—
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	—		2
Environmental Cost Recovery(*)	Other regulatory liabilities, current	13		—
Environmental Cost Recovery(*)	Under recovered regulatory clause revenues	—		2
Energy Conservation Cost Recovery	Other regulatory liabilities, current	2		—

(*) At September 30, 2018 and December 31, 2017, the over and under recovered balances, respectively, included in the balance sheets represents the current portion of the regulatory assets associated with projected environmental expenditures of approximately $8 million and $13 million, respectively, net of the over recovered environmental cost recovery balance of approximately $21 million and $11 million, respectively.

On November 5, 2018, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2019. The net effect of the approved changes is a $38 million decrease in annual revenues effective in January 2019, the majority of which will be offset by related expense decreases.

Mississippi Power

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.

On May 8, 2018, the Mississippi PSC issued an order to begin an operations review of Mississippi Power, which began in August 2018, with the final report expected by February 28, 2019. Mississippi Power expects that the review will include, but not be limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time.

Performance Evaluation Plan

In 2013, the Mississippi Public Utilities Staff (MPUS) contested Mississippi Power's PEP lookback filing for 2012, which indicated a refund due to customers of $5 million. In each of 2014, 2015, 2016, and 2017, Mississippi Power submitted its annual PEP lookback filing for the prior year, which for 2013 and 2014 each indicated no surcharge or refund and for each of 2015 and 2016 indicated a $5 million surcharge. Additionally, in July 2016, in November 2016, and on November 15, 2017, Mississippi Power submitted its annual projected PEP filings for 2016, 2017, and 2018, respectively, which for 2016 and 2017 indicated no change in rates and for 2018 indicated a rate increase of 4%, or $38 million in annual revenues. The Mississippi PSC suspended each of these filings to allow more time for review.

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On February 7, 2018, Mississippi Power submitted its revised 2018 projected PEP filing to the Mississippi PSC, which reflected the impacts of the Tax Reform Legislation, requesting an increase in annual retail revenues of $26 million based on a performance-adjusted ROE of 9.33% and an increased equity ratio of 55%.

On March 22, 2018, Mississippi Power submitted its annual PEP lookback filing for 2017, which reflected no surcharge or refund.

On July 27, 2018, Mississippi Power and the MPUS entered into a settlement agreement with respect to the 2018 PEP filing and all unresolved PEP filings for prior years (PEP Settlement Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement became effective with the first billing cycle of September 2018. The PEP Settlement Agreement provides for an increase of approximately $21.6 million in annual base retail revenues, which excludes certain compensation costs contested by the MPUS, as well as approximately $2 million which was subsequently approved for recovery through the 2018 Energy Efficiency Cost Rider as discussed below. Under the PEP Settlement Agreement, Mississippi Power is deferring the contested compensation costs for 2018 and 2019 as a regulatory asset, which totaled $3 million as of September 30, 2018 and is included in other regulatory assets, deferred on Mississippi Power's condensed balance sheet. The Mississippi PSC is currently expected to rule on the appropriate treatment for such costs in connection with Mississippi Power's next base rate case, which is scheduled to be filed in the fourth quarter 2019 (2019 Base Rate Case). The ultimate outcome of this matter cannot be determined at this time.

Pursuant to the PEP Settlement Agreement, Mississippi Power's performance-adjusted allowed ROE is 9.31% and its allowed equity ratio remains at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power retained $44 million of excess accumulated deferred income taxes resulting from the Tax Reform Legislation, which had been proposed to be amortized beginning in 2018, until the conclusion of the 2019 Base Rate Case. Further, Mississippi Power will seek equity contributions sufficient to restore its equity ratio (which was 45% at September 30, 2018) to 50% by December 31, 2018. In the event Mississippi Power's actual average equity ratio for 2018 is more than 1% higher or lower than the 50% target, Mississippi Power will defer the corresponding difference in its revenue requirement as a regulatory asset or liability for resolution in the 2019 Base Rate Case. As of September 30, 2018, Mississippi Power has recorded $5 million in other regulatory liabilities, deferred on Mississippi Power's condensed balance sheet related to the estimated December 31, 2018 average equity ratio differential from target applicable to PEP.

Pursuant to the PEP Settlement Agreement, PEP proceedings are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolved all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power recognized revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.

Energy Efficiency

On May 8, 2018, the Mississippi PSC issued an order approving Mississippi Power's revised annual projected Energy Efficiency Cost Rider 2018 compliance filing, which increased annual retail revenues by approximately $3 million effective with the first billing cycle for June 2018.

Ad Valorem Tax Adjustment

On May 8, 2018, the Mississippi PSC also approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2018, which included an annual rate increase of 0.8%, or $7 million, in annual retail revenues effective with the first billing cycle for June 2018, primarily due to increased assessments.

Environmental Compliance Overview Plan

On August 3, 2018, Mississippi Power and the MPUS entered into a settlement agreement with respect to the 2018 ECO Plan filing (ECO Settlement Agreement), which provides for an increase of approximately $17 million in annual base retail revenues and was approved by the Mississippi PSC on August 7, 2018. Rates under the ECO Settlement Agreement became effective with the first billing cycle of September 2018 and will continue in effect

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until modified by the Mississippi PSC. These revenues are expected to be sufficient to recover the costs included in Mississippi Power's request for 2018, as well as the remaining deferred amounts that were originally expected to be recovered in 2019. In accordance with the ECO Settlement Agreement, ECO Plan proceedings are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not required to make any ECO Plan filings for 2018, 2019, and 2020, with any necessary true-ups to be reflected in the 2019 Base Rate Case. The ECO Settlement Agreement contains the same terms as the PEP Settlement Agreement described herein with respect to allowed ROE and equity ratio. As of September 30, 2018, Mississippi Power has recorded $2 million in other regulatory liabilities, deferred on Mississippi Power's condensed balance sheet related to the estimated December 31, 2018 average equity ratio differential from target applicable to the ECO Plan.

Fuel Cost Recovery

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form10-K for additional information regarding Mississippi Power's retail fuel cost recovery.

At September 30, 2018, the amount of over-recovered retail fuel costs included on Mississippi Power's condensed balance sheet in customer accounts receivable was approximately $13 million compared to $6 million under recovered at December 31, 2017.

Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on Mississippi Power's revenues or net income, but will affect cash flow.

Southern Company Gas

See Note 3 to the financial statements of Southern Company and Southern Company Gas under "Regulatory Matters – Southern Company Gas" and "Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Southern Company Gas' regulatory matters.

Riders

On April 19, 2018, the Illinois Commission approved Nicor Gas' variable income tax adjustment rider. This rider provides for refund or recovery of changes in income tax expense that result from income tax rates that differ from those used in Nicor Gas' last rate case. Customer refunds, via bill credits, began on July 1, 2018 related to the impacts of the Tax Reform Legislation from January 25, 2018 through May 4, 2018. The impact of the Tax Reform Legislation subsequent to May 4, 2018 was addressed in Nicor Gas' approved rehearing request discussed herein under "Settled Base Rate Cases."

Natural Gas Cost Recovery

Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company's or Southern Company Gas' revenues or net income, but will affect cash flows.

Base Rate Cases

Settled Base Rate Cases

On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation. The Georgia PSC maintained Atlanta Gas Light's previously authorized earnings band based on a ROE between

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10.55% and 10.95% and increased the allowed equity ratio by4% to an equity ratio of 55% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. Additionally, Atlanta Gas Light is required to file a traditional base rate case on or before June 1, 2019 for rates effective January 1, 2020.

On May 2, 2018, the Illinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately$44 million in annual base rate revenues became effective May 5, 2018. Nicor Gas' previously-authorized capital structure and ROE of9.8% were not addressed in the rehearing and remain unchanged. The impact of the Tax Reform Legislation prior to May 5, 2018 was addressed in the variable income tax rider discussed herein under "Riders."

On October 15, 2018, the Tennessee Public Utility Commission (PUC) approved a $1 million increase in Chattanooga Gas' annual base rate revenues, which was based on a projected test year ending June 30, 2019 and a ROE of 9.80%. The new rates became effective November 1, 2018.

Other

The Virginia Commission issued an order effective January 1, 2018 requiring utilities in the state to defer as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of the flowback of excess deferred income taxes. Through September 30, 2018, Virginia Natural Gas had deferred a total of $9 million. On August 30, 2018, Virginia Natural Gas filed an annual information form, which was subsequently revised on October 25, 2018, proposing to reduce annual base rates effective January 1, 2019 due to lower tax expense as a result of the lower corporate income tax rate and the impact of the flowback of excess deferred income taxes. This filing also proposes for Virginia Natural Gas to issue customer refunds, via bill credits, for the related amounts deferred as a regulatory asset. The Virginia Commission is expected to rule on the filing during the fourth quarter 2018. If approved as filed, Virginia Natural Gas' annual base rate revenues would be reduced by $14 million. The ultimate outcome of this matter cannot be determined at this time.

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. See Note 3 to the financial statements of Southern Company and Southern Company Gas under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" and "Regulatory Matters – Regulatory Infrastructure Programs," respectively, in Item 8 of the Form 10-K for additional information.

Atlanta Gas Light's Pipeline Replacement Program

One of the capital projects under Atlanta Gas Light's Pipeline Replacement Program experienced construction issues and Atlanta Gas Light was required to complete mitigation work prior to placing it in service. In the first quarter 2018, Atlanta Gas Light recovered $7 million from the final settlement of contractor litigation claims. Mitigation costs recovered through the legal process are retained by Atlanta Gas Light. For additional information on the Pipeline Replacement Program settlement, see Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters – PRP Settlement" in Item 8 of the Form 10-K.

Nuclear Construction

See Note 3 to the financial statements of Southern Company and Georgia Power under "Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, VCM reports, and the NCCR tariff.

In 2009, the Georgia PSC certified construction of 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

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

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

In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor.

Cost and Schedule

In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. 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 September 30, 2018(b)	(4.3		)
Remaining estimate to complete(a)	$	4.1

(a) Excludes financing costs expected to be capitalized through AFUDC of approximately $350 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 $3.2 billion, of which $1.8 billion had been incurred through September 30, 2018.

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The table above reflects the $0.7 billion increase to the base capital cost forecast reported in the second quarter 2018 and is based on the cost reforecast performed prior to the nineteenth VCM filing, which primarily resulted from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.

Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power did not seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs) in the nineteenth VCM report that was filed with the Georgia PSC on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018, which includes the total increase in the base capital cost forecast and construction contingency estimate.

As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule continue to increase significantly through the remainder of 2018 and into 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers 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 resolution of Inspections, Tests, Analyses, and Acceptance Criteria (ITAAC) and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Joint Owner Contracts

In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective August 31, 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue

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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 as described above, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. On September 26, 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.

Amendments to the Vogtle Joint Ownership Agreements

In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners, and (ii) a term sheet (MEAG Term Sheet and, together with the Vogtle Owner Term Sheet, Term Sheets) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 (Project J) under certain circumstances. Pursuant to the Vogtle Owner Term Sheet, the Vogtle Joint Ownership Agreements will be modified as follows: (i) each Vogtle Owner will pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which forms the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million of additional construction costs; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests.

If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion. In this event, Georgia Power will have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Vogtle Owner. If Georgia Power accepts the offer to purchase a portion of another Vogtle Owner's ownership interest in Plant Vogtle Units 3 and 4, the ownership interest(s) to be conveyed from the tendering Vogtle Owner(s) to Georgia Power would be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Vogtle Owner(s) and by Georgia Power as of the commercial operation date of Plant Vogtle Unit 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Vogtle Owner in accordance with the second and third items described in the paragraph above would be treated as payments made by the applicable Vogtle Owner.

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

For purposes of the foregoing provisions, qualifying construction costs would not include costs (i) resulting from force majeure events, including governmental actions or inactions (or significant delays associated with issuance of

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such actions) that affect the licensing, completion, startup, operations, or financing of Plant Vogtle Units 3 and 4, administrative proceedings or litigation regarding ITAAC or other regulatory challenges to commencement of operation of Plant Vogtle Units 3 and 4, and changes in laws or regulations governing Plant Vogtle Units 3 and 4, (ii) legal fees and legal expenses incurred due to litigation with contractors or subcontractors that are not subsidiaries or affiliates of Southern Company, and (iii) additional costs caused by Vogtle Owner requests other than Georgia Power, except for the exercise of a right to vote granted under the Vogtle Joint Ownership Agreements, that increase costs by $100,000 or more.

Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain of the above provisions of the Vogtle Owner Term Sheet.

Under the Vogtle Owner Term Sheet, the provisions of the Vogtle Joint Ownership Agreements requiring that Vogtle Owners holding 90% of the ownership interests in Plant Vogtle Units 3 and 4 vote to continue construction following certain adverse events (Project Adverse Events) will be modified. Pursuant to the Vogtle Joint Ownership Agreements and the Vogtle Owner Term Sheet, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain Project Adverse Events occur, including: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Vogtle Owner Term Sheet provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule. Under the Vogtle Owner Term Sheet, Georgia Power may cancel the project at any time in its sole discretion.

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

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

Purchase of PTCs During Commercial Operation

In addition, under the terms of the Vogtle Owner Term Sheet, Georgia Power agreed to purchase additional PTCs from OPC, Dalton, MEAG SPVM, MEAG SPVP, and MEAG SPVJ (to the extent any MEAG SPVJ PTC rights remain after any purchases required under the MEAG Term Sheet as described below) at varying purchase prices dependent upon the actual cost to complete construction of Plant Vogtle Units 3 and 4 as compared to the EAC included in the nineteenth VCM report. The purchases will be at the option of the applicable Vogtle Owner and will occur during the month after such PTCs are earned.

Potential Funding to MEAG Project J

Pursuant to the MEAG Term Sheet, if MEAG SPVJ is unable to make its payments due under the Vogtle Joint Ownership Agreements solely because (i) the conduct of JEA, such as JEA's legal challenges of its obligations under a PPA with MEAG (PPA-J), materially impedes access to capital markets for MEAG for Project J, or (ii)

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PPA-J is declared void by a court of competent jurisdiction or rejected by JEA under the applicable provisions of the U.S. Bankruptcy Code (each of (i) and (ii), a JEA Default), Georgia Power would purchase from MEAG SPVJ the rights to PTCs attributable to MEAG SPVJ's share of Plant Vogtle Units 3 and 4 (approximately 206 MWs) at varying prices dependent upon the stage of construction of Plant Vogtle Units 3 and 4. The aggregate purchase price of the PTCs, together with any advances made as described in the next paragraph, shall not exceed $300 million.

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

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

Under the terms of the MEAG Term Sheet, Georgia Power may decline to provide any funding in the form of advances, including in the event of a failure to receive any required Georgia PSC or DOE approvals, and cancel the project in lieu of providing such funding.

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. As of September 30, 2018, Georgia Power had recovered approximately $1.8 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. Georgia Power expects to file on November 9, 2018 to increase the NCCR tariff by approximately $90 million annually, effective January 1, 2019, pending Georgia PSC approval.

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) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying 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

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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 $25 million in 2017 and are estimated to have negative earnings impacts of approximately $100 million in 2018 and an aggregate of $680 million from 2019 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.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. On March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's final decision and denial of Georgia Watch's motion for reconsideration. Georgia Power believes the two appeals have no merit; however, an adverse outcome in either 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.

The Georgia PSC has approved eighteen VCM reports covering the periods through December 31, 2017, including total construction capital costs incurred through that date of $4.9 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds). On August 31, 2018, Georgia Power filed its nineteenth VCM report with the Georgia PSC, which requested approval of $578 million of construction capital costs incurred from January 1, 2018 through June 30, 2018.

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

DOE Financing

As of September 30, 2018, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In September 2018, the DOE extended the conditional commitment to March 31, 2019. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements of Southern Company and Georgia Power under "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

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(UNAUDITED)

events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and conditions to borrowing.

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

Kemper County Energy Facility

For additional information on the Kemper County energy facility, see Note 3 to the financial statements of Southern Company and Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K.

As the mining permit holder for the Kemper County energy facility, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. Mine reclamation began in the first quarter 2018. See Note 1 to the financial statements of Southern Company and Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and of Mississippi Power under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.

As of September 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the third quarter 2018 and$45 million($34 millionafter tax) foryear-to-date 2018, primarily resulting from the abandonment and related closure activities 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 to cost up to$20 millionpre-tax (excluding salvage, net of dismantlement costs), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at$2 millionfor the remainder of 2018,$8 millionin 2019, and$4 millionannually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.

Reserve Margin Plan

On August 6, 2018, Mississippi Power filed its proposed RMP, as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costs related to the Kemper County energy facility. Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being thetwo-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adverse impact on customer rates.

Other Matters

Investments in Leveraged Leases

See Note 1 to the financial statements of Southern Company under "Leveraged Leases" in Item 8 of the Form 10-K for additional information regarding the leveraged lease agreements of a subsidiary of Southern Company Holdings Inc. (Southern Holdings) and concerns about the financial and operational performance of one of the lessees and the associated generation assets.

The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. As a result of operational improvements in the first half of 2018, the June 2018 lease payment was paid in full and the December 2018 lease payment is currently expected to be paid in full. However, operational issues and the resulting cash liquidity challenges persist and significant concerns continue

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regarding the lessee's ability to make the remaining semi-annual lease payments. These operational challenges may also impact the expected residual value of the assets at the end of the lease term in 2047. If any future lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders would represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable, which would result in a reduction in net income of approximately $86 million after tax based on the lease receivable balance as of September 30, 2018. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired as of September 30, 2018. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments. The ultimate outcome of this matter cannot be determined at this time.

Natural Gas Storage

A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At September 30, 2018, the facility's property, plant, and equipment had a net book value of $110 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.

The cavern continues to maintain its pressures and overall structural integrity. Southern Company Gas intends to monitor the cavern and comply with the Louisiana DNR order through 2020 and place the cavern back in service in 2021. These events were considered in connection with Southern Company Gas' 2017 long-lived asset impairment analysis, which determined there was no impairment. Any future changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements and a material impact on Southern Company Gas' financial statements.

(C) 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, such as leases, derivatives, and certain cost recovery mechanisms. See Note (A) under "Recently Adopted Accounting Standards – Revenue" for additional information on the adoption of ASC 606 for revenue from contracts with customers.

The majority of the revenues of the traditional electric operating companies and Southern Company Gas are generated from contracts with retail electric and natural gas distribution customers. Revenues from this integrated service to deliver electricity or gas when and if called upon by the customer is recognized as a single performance obligation satisfied over time and is recognized at a tariff rate as electricity or gas is delivered to the customer during the month. The traditional electric operating companies and Southern Company Gas exclude taxes imposed on the customer and collected on behalf of governmental agencies to be remitted to these agencies from the transaction price in determining the revenue related to contracts with a customer.

The traditional electric operating companies and Southern Power also have contracts with multiple performance obligations, such as capacity and energy in a wholesale PPA, where the contract's total transaction price is allocated

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(UNAUDITED)

to each performance obligation based on the standalone selling price. The standalone selling price is primarily determined by the price charged to customers for the specific goods or services transferred with the performance obligations. Generally, the registrants recognize revenue as the performance obligations are satisfied over time as electricity or natural gas is delivered to the customer or as generation capacity is available to the customer. At Southern Company Gas, the performance obligations related to wholesale gas services are satisfied, and revenue is recognized, at a point in time when natural gas is delivered to the customer.

The registrants generally have a right to consideration in an amount that corresponds directly with the value to the customer of the entity's performance completed to date and may recognize revenue in the amount to which the entity has a right to invoice and has elected to recognize revenue for its sales of electricity, capacity, and natural gas using the invoice practical expedient. In addition, payment for goods and services rendered is typically due in the subsequent month following satisfaction of the registrants' performance obligation.

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The following tables disaggregate revenue sources for the three and nine months ended September 30, 2018:

	For the Three Months Ended September 30, 2018		For the Nine Months Ended September 30, 2018
	(in millions)
Southern Company
Operating revenues
Retail electric revenues(a)
Residential	$	2,148	$	5,266
Commercial	1,527		4,084
Industrial	901		2,471
Other	29		92
Natural gas distribution revenues	433		2,299
Alternative revenue programs(b)	5		(23		)
Total retail electric and gas distribution revenues	$	5,043	$	14,189
Wholesale energy revenues(c)(d)	516		1,444
Wholesale capacity revenues(d)	177		479
Other natural gas revenues(e)	54		530
Other revenues(f)	369		1,516
Total operating revenues	$	6,159	$	18,158

(a) Retail electric revenues include $17 million and $54 million of leases for the three and nine months ended September 30, 2018, respectively, and a (net reduction) or net increase of $(98) million and $4 million for the three and nine months ended September 30, 2018, respectively, from certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 3 to the financial statements of Southern Company under "Regulatory Matters" in Item 8 of the Form 10-K for additional information on cost recovery mechanisms.

(b) See Note 1 to the financial statements of Southern Company under "Revenues" in Item 8 of the Form 10-K for additional information on alternative revenue programs at the natural gas distribution utilities. Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(c) Wholesale energy revenues include $63 million and $217 million for the three and nine months ended September 30, 2018, respectively, of revenues accounted for as derivatives, primarily related to physical energy sales in the wholesale electricity market. See Note (I) for additional information on energy-related derivative contracts.

(d) Wholesale energy and wholesale capacity revenues include $130 million and $31 million, respectively, for the three months ended September 30, 2018 and $318 million and $92 million, respectively, for the nine months ended September 30, 2018 of PPA contracts accounted for as leases.

(e) 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 $1.6 billion and $4.8 billion for the three and nine months ended September 30, 2018, respectively, of which $0.9 billion and $2.7 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.

(f) Other revenues include $92 million and $274 million for the three and nine months ended September 30, 2018, respectively, of revenues not accounted for under ASC 606.

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	Alabama Power		Georgia Power		Gulf Power		Mississippi Power
	(in millions)
For the Three Months Ended September 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	721	$	1,142	$	200	$	85
Commercial	464		877		103		82
Industrial	392		385		37		86
Other	7		21		1		1
Total retail electric revenues	$	1,584	$	2,425	$	341	$	254
Wholesale energy revenues(c)	62		33		48		92
Wholesale capacity revenues	26		14		7		1
Other revenues(b)(d)	68		121		18		11
Total operating revenues	$	1,740	$	2,593	$	414	$	358
For the Nine Months Ended September 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	1,848	$	2,671	$	537	$	209
Commercial	1,238		2,343		291		212
Industrial	1,103		1,036		100		233
Other	19		62		4		6
Total retail electric revenues	$	4,208	$	6,112	$	932	$	660
Wholesale energy revenues(c)	234		99		104		259
Wholesale capacity revenues	75		41		20		6
Other revenues(b)(d)	199		349		50		31
Total operating revenues	$	4,716	$	6,601	$	1,106	$	956

(a) Retail revenues at Alabama Power, Georgia Power, Gulf Power, and Mississippi Power include a net increase or (net reduction) of $(12) million, $(47) million, $(36) million, and $(3) million, respectively, for the three months ended September 30, 2018 and $113 million, $(35) million, $(63) million, and $(11) million, respectively, for the nine months ended September 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 3 to the financial statements of Alabama Power, Georgia Power, Gulf Power, and Mississippi Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information on cost recovery mechanisms.

(b) Retail revenues and other revenues at Georgia Power include $17 million and $34 million, respectively, for the three months ended September 30, 2018 and $54 million and $100 million, respectively, for the nine months ended September 30, 2018 of revenues accounted for as leases.

(c) Wholesale energy revenues at Alabama Power and Georgia Power include $6 million and $8 million, respectively, for the three months ended September 30, 2018 and $14 million and $21 million, respectively, for the nine months ended September 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market. See Note (I) for additional information on energy-related derivative contracts.

(d) Other revenues at Alabama Power, Georgia Power, and Gulf Power include $27 million, $28 million, and $2 million, respectively, for the three months ended September 30, 2018 and $79 million, $80 million, and $5 million, respectively, for the nine months ended September 30, 2018 of revenues not accounted for under ASC 606.

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	For the Three Months Ended September 30, 2018		For the Nine Months Ended September 30, 2018
	(in millions)
Southern Power
PPA capacity revenues(a)	$	168	$	450
PPA energy revenues(a)	336		892
Non-PPA revenues(b)	126		347
Other revenues	5		10
Total operating revenues	$	635	$	1,699

(a) PPA capacity revenues and PPA energy revenues include $47 million and $139 million, respectively, for the three months ended September 30, 2018 and $141 million and $342 million, respectively, for the nine months ended September 30, 2018 related to PPAs accounted for as leases. See Note 1 to the financial statements of Southern Power under "Revenues" in Item 8 of the Form 10-K for additional information on capacity revenues accounted for as leases.

(b) Non-PPA revenues include $47 million and $176 million for the three and nine months ended September 30, 2018, respectively, of revenues from short-term sales related to physical energy sales from uncovered capacity in the wholesale electricity market. See Note 1 to the financial statements of Southern Power under "Revenues" in Item 8 of the Form 10-K and Note (I) for additional information on energy-related derivative contracts.

	For the Three Months Ended September 30, 2018			For the Nine Months Ended September 30, 2018
	(in millions)
Southern Company Gas
Operating revenues
Natural gas distribution revenues
Residential	$	149		$	1,082
Commercial	45			313
Transportation	203			708
Industrial	4			28
Other	32			168
Alternative revenue programs(a)	5			(23		)
Total natural gas distribution revenues	$	438		$	2,276
Gas marketing services(b)	44			403
Wholesale gas services(c)	(10		)	121
Gas midstream operations	20			60
Other revenues	—			1
Total operating revenues	$	492		$	2,861

(a) See Note 1 to the financial statements of Southern Company Gas under "Revenues" in Item 8 of the Form 10-K for additional information on alternative revenue programs at the natural gas distribution utilities. Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(b) Gas marketing services includes $4 million for the nine months ended September 30, 2018 of revenues not accounted for under ASC 606.

(c) 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 $1.6 billion and $4.8 billion for the three and nine months ended September 30, 2018, respectively, of which $0.9 billion and $2.7 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues and Note (I) for additional information on energy-related derivative contracts.

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Contract Balances

The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers as of September 30, 2018:

	Receivables		Contract Assets		Contract Liabilities
	(in millions)
Southern Company	$	2,778	$	99	$	34
Alabama Power	649		1		14
Georgia Power	924		70		3
Gulf Power	186		—		—
Mississippi Power	96		—		—
Southern Power	142		—		17
Southern Company Gas	523		—		1

As of September 30, 2018, Alabama Power had contract liabilities for outstanding performance obligations primarily related to extended service agreements. Georgia Power had contract assets primarily related to 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. Southern Power's contract liabilities relate to collections recognized in advance of revenue for certain levelized PPAs with Georgia Power. Southern Company's unregulated distributed generation business had $27 million and $17 million of contract assets and contract liabilities, respectively, remaining for outstanding performance obligations.

Remaining Performance Obligations

The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. These contracts primarily relate to PPAs whereby the traditional electric operating companies and Southern Power provide electricity and generation capacity to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain fixed price contracts. Revenues from contracts with customers related to these performance obligations remaining at September 30, 2018 are expected to be recognized as follows:

	2018		2019		2020		2021		2022		2023 and Thereafter
	(in millions)
Southern Company(*)	$	168	$	406	$	322	$	322	$	310	$	2,112
Alabama Power	6		22		22		26		23		161
Georgia Power	10		41		38		40		30		113
Gulf Power	5		22		—		—		—		—
Mississippi Power	1		3		3		1		—		—
Southern Power(*)	75		310		283		277		276		2,005

(*) Excludes amounts related to held for sale assets. See Note (J) under "Southern Company's Sale of Gulf Power" and "Southern Power – Sale of Florida Plants" for additional information.

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(D) FAIR VALUE MEASUREMENTS

As of September 30, 2018, 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 September 30, 2018:	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)(b)	$	271	$	150	$	—	$	—	$	421
Foreign currency derivatives	—		122		—		—		122
Nuclear decommissioning trusts(c)	828		1,007		—		37		1,872
Non-qualified deferred compensation trusts:
Domestic equity	—		11		—		—		11
Foreign equity	—		6		—		—		6
Pooled funds – fixed income	—		13		—		—		13
Cash equivalents	15		—		—		—		15
Other	9		—		—		—		9
Cash equivalents	1,309		—		—		—		1,309
Total	$	2,432	$	1,309	$	—	$	37	$	3,778
Liabilities:
Energy-related derivatives(a)(b)	$	416	$	159	$	—	$	—	$	575
Interest rate derivatives	—		72		—		—		72
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		22		—		22
Total	$	416	$	254	$	22	$	—	$	692

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(UNAUDITED)

	Fair Value Measurements Using:
As of September 30, 2018:	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	$	—	$	7	$	—	$	—	$	7
Nuclear decommissioning trusts:(d)
Domestic equity	469		89		—		—		558
Foreign equity	60		56		—		—		116
U.S. Treasury and government agency securities	—		18		—		—		18
Corporate bonds	26		154		—		—		180
Mortgage and asset backed securities	—		22		—		—		22
Private equity	—		—		—		37		37
Other	7		—		—		—		7
Cash equivalents	513		—		—		—		513
Total	$	1,075	$	346	$	—	$	37	$	1,458
Liabilities:
Energy-related derivatives	$	—	$	10	$	—	$	—	$	10
Georgia Power
Assets:
Energy-related derivatives	$	—	$	8	$	—	$	—	$	8
Nuclear decommissioning trusts:(d)(e)
Domestic equity	250		1		—		—		251
Foreign equity	—		134		—		—		134
U.S. Treasury and government agency securities	—		236		—		—		236
Municipal bonds	—		82		—		—		82
Corporate bonds	—		163		—		—		163
Mortgage and asset backed securities	—		42		—		—		42
Other	16		9		—		—		25
Cash equivalents	350		—		—		—		350
Total	$	616	$	675	$	—	$	—	$	1,291
Liabilities:
Energy-related derivatives	$	—	$	22	$	—	$	—	$	22
Interest rate derivatives	—		6		—		—		6
Total	$	—	$	28	$	—	$	—	$	28
Gulf Power
Assets:
Cash equivalents	$	27	$	—	$	—	$	—	$	27
Liabilities:
Energy-related derivatives	$	—	$	8	$	—	$	—	$	8

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(UNAUDITED)

	Fair Value Measurements Using:
As of September 30, 2018:	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	346		—		—		—		346
Total	$	346	$	3	$	—	$	—	$	349
Liabilities:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9
Southern Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Foreign currency derivatives	—		122		—		—		122
Total	$	—	$	125	$	—	$	—	$	125
Liabilities:
Energy-related derivatives	$	—	$	7	$	—	$	—	$	7
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		22		—		22
Total	$	—	$	30	$	22	$	—	$	52
Southern Company Gas
Assets:
Energy-related derivatives(a)(b)	$	271	$	129	$	—	$	—	$	400
Non-qualified deferred compensation trusts:
Domestic equity	—		11		—		—		11
Foreign equity	—		6		—		—		6
Pooled funds – fixed income	—		13		—		—		13
Cash equivalents	4		—		—		—		4
Cash equivalents	26		—		—		—		26
Total	$	301	$	159	$	—	$	—	$	460
Liabilities:
Energy-related derivatives(a)(b)	$	416	$	101	$	—	$	—	$	517

(a) Excludes $5 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value.

(b) Excludes cash collateral of $189 million.

(c) For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.

(d) Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies.

(e) Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of September 30, 2018, approximately $37 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.

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(UNAUDITED)

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 for the three and nine months ended September 30, 2018 and 2017 by the amounts shown in the table below. The increases were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.

	Three Months Ended September 30, 2018		Three Months Ended September 30, 2017		Nine Months Ended September 30, 2018		Nine Months Ended September 30, 2017
	(in millions)
Southern Company	$	58	$	50	$	68	$	168
Alabama Power	39		25		49		87
Georgia Power	19		25		19		81

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 (I) 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 1 to the financial statements of Southern Company, Alabama Power, and Georgia Power 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 date 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

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(UNAUDITED)

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.

"Other investments" include investments that are not traded in the open market. The fair value of these investments has been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.

As of September 30, 2018, the fair value measurements of private equity investments held in the nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:

As of September 30, 2018:	Fair Value		Unfunded Commitments
	(in millions)
Southern Company	$	37	$	47
Alabama Power	$	37	$	47

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. Liquidations are expected to occur at various times over the next 10 years.

As of September 30, 2018, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Carrying Amount		Fair Value
	(in millions)
Long-term debt, including securities due within one year:
Southern Company	$	45,524	$	45,500
Alabama Power	8,120		8,321
Georgia Power	10,227		10,159
Gulf Power	1,285		1,290
Mississippi Power	1,736		1,702
Southern Power	5,029		5,058
Southern Company Gas	5,908		5,935

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, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas.

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(UNAUDITED)

(E) STOCKHOLDERS' EQUITY

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 8 to the financial statements of Southern Company 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 September 30, 2018	Three Months Ended September 30, 2017	Nine Months Ended September 30, 2018	Nine Months Ended September 30, 2017
	(in millions)
As reported shares	1,023	1,003	1,016	998
Effect of stock-based compensation	6	7	5	7
Diluted shares	1,029	1,010	1,021	1,005

Stock-based compensation awards that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for the three and nine months ended September 30, 2018 and 2017.

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(UNAUDITED)

Changes in Stockholders' Equity

The following table presents year-to-date changes in stockholders' equity of Southern Company:

	Number of Common Shares			Common Stockholders' Equity			Preferred and Preference Stock of Subsidiaries						Total Stockholders' Equity
	Issued	Treasury								Noncontrolling Interests(a)
	(in thousands)			(in millions)
Balance at December 31, 2017	1,008,532	(929	)	$	24,167		$	—		$	1,361		$	25,528
Consolidated net income attributable to Southern Company	—	—		1,948			—			—			1,948
Other comprehensive income	—	—		52			—			—			52
Stock issued	21,342	—		878			—			—			878
Stock-based compensation	—	—		74			—			—			74
Cash dividends on common stock	—	—		(1,805		)	—			—			(1,805		)
Contributions from noncontrolling interests	—	—		—			—			154			154
Distributions to noncontrolling interests	—	—		—			—			(87		)	(87		)
Net income attributable to noncontrolling interests	—	—		—			—			71			71
Sale of noncontrolling interests(b)	—	—		(410		)	—			1,690			1,280
Other	—	(57	)	(27		)	—			(1		)	(28		)
Balance at September 30, 2018	1,029,874	(986	)	$	24,877		$	—		$	3,188		$	28,065
Balance at December 31, 2016	991,213	(819	)	$	24,758		$	609		$	1,245		$	26,612
Consolidated net income attributable to Southern Company	—	—		347			—			—			347
Other comprehensive income (loss)	—	—		(2		)	—			—			(2		)
Stock issued	13,308	—		613			—			—			613
Stock-based compensation	—	—		97			—			—			97
Cash dividends on common stock	—	—		(1,716		)	—			—			(1,716		)
Preference stock redemption	—	—		—			(150		)	—			(150		)
Contributions from noncontrolling interests	—	—		—			—			77			77
Distributions to noncontrolling interests	—	—		—			—			(87		)	(87		)
Net income attributable to noncontrolling interests	—	—		—			—			45			45
Reclassification from redeemable noncontrolling interests	—	—		—			—			114			114
Other	—	(75	)	(15		)	3			1			(11		)
Balance at September 30, 2017	1,004,521	(894	)	$	24,082		$	462		$	1,395		$	25,939

(a) Primarily related to Southern Power and excludes redeemable noncontrolling interests. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(b) See Note (J) under "Southern Power – Sale of Solar Facility Interests" for additional information.

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(UNAUDITED)

(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 September 30, 2018 was approximately $1.5 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, $82 million at Gulf Power, and $40 million at Mississippi Power). In addition, at September 30, 2018, the traditional electric operating companies had approximately $573 million (comprised of approximately $120 million at Alabama Power, $345 million at Georgia Power, $58 million at Gulf Power, and $50 million at Mississippi Power) of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2018, Alabama Power purchased and held its approximately $120 million of outstanding pollution control revenue bonds required to be remarketed. See Note 6 to the financial statements of each registrant 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 September 30, 2018:

	Expires												Executable Term Loans		Expires Within One Year
Company	2018		2019		2020		2022		Total		Unused		One Year		Term Out		No Term Out
	(in millions)
Southern Company(a)	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—	$	—	$	—
Alabama Power	—		33		500		800		1,333		1,333		—		—		33
Georgia Power	—		—		—		1,750		1,750		1,736		—		—		—
Gulf Power	20		25		235		—		280		280		45		45		—
Mississippi Power	—		100		—		—		100		100		—		—		—
Southern Power Company(b)	—		—		—		750		750		728		—		—		—
Southern Company Gas(c)	—		—		—		1,900		1,900		1,895		—		—		—
Other	—		30		—		—		30		30		—		—		30
Southern Company Consolidated	$	20	$	188	$	735	$	7,200	$	8,143	$	8,101	$	45	$	45	$	63

(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 2019, of which $22 million remains unused at September 30, 2018.

(c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.

Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

DOE Loan Guarantee Borrowings

See Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding Georgia Power's Loan Guarantee Agreement.

On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) in connection with the DOE's consent to Georgia Power's entry into the Vogtle Services Agreement and the related

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(UNAUDITED)

intellectual property licenses (IP Licenses). Under the terms of the Loan Guarantee Agreement, upon termination of the Vogtle 3 and 4 Agreement, further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement. Under the terms of the LGA Amendment, Georgia Power will not request any advances unless and until certain conditions are satisfied, including (i) receipt of the DOE's approval of the Bechtel Agreement (together with the Vogtle Services Agreement and the IP Licenses, the Replacement EPC Arrangements) and (ii) Georgia Power's entry into a further amendment to the Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements.

In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In September 2018, the DOE extended the conditional commitment to March 31, 2019. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions.

As of September 30, 2018, Georgia Power had $2.6 billion of borrowings outstanding under the multi-advance term loan facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB.

Under the 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 (including any decision not to continue construction of Plant Vogtle Units 3 and 4) occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility 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 bankruptcy if Georgia Power does not maintain access to intellectual property rights under the IP Licenses; (ii) a decision by Georgia Power not to continue construction of Plant Vogtle Units 3 and 4; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (iv) 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 Facility. 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 Facility. 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 Facility 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. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Credit Facility, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.

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(UNAUDITED)

Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2018:

Company	Senior Note Issuances		Senior Note Maturities, Redemptions, and Repurchases		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Issuances		Other Long-Term Debt Redemptions and Maturities(a)
	(in millions)
Southern Company(b)	$	750	$	1,000	$	—	$	—	$	—
Alabama Power	500		—		—		—		—
Georgia Power	—		1,000		469		—		107
Mississippi Power	600		—		43		—		900
Southern Power	—		350		—		—		420
Southern Company Gas	—		—		200		100		—
Other	—		—		—		—		10
Elimination(c)	—		—		—		—		(1		)
Southern Company Consolidated	$	1,850	$	2,350	$	712	$	100	$	1,436

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

(b) Represents the Southern Company parent entity.

(c) Represents reductions in affiliate capital lease obligations at Georgia Power, which are eliminated in Southern Company's Consolidated Financial Statements.

Except as otherwise described herein, Southern Company and its subsidiaries used the proceeds of debt issuances for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital. The subsidiaries also used the proceeds for their construction programs.

Southern Company

In March 2018, Southern Company entered into a $900 million short-term floating rate bank loan bearing interest based on one-month LIBOR, which was repaid in August 2018.

In April 2018, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, bearing interest at a rate agreed upon by Southern Company and the bank from time to time and payable on no less than 30 days' demand by the bank.

In June 2018, Southern Company repaid at maturity two$100 million short-term floating rate bank term loans.

In August 2018, Southern Company issued $750 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due February 14, 2020 bearing interest based on three-month LIBOR, entered into a $1.5 billion short-term floating rate bank loan bearing interest based on one-month LIBOR, and repaid $250 million borrowed in August 2017 pursuant to a short-term uncommitted bank credit arrangement.

Alabama Power

In June 2018, Alabama Power issued $500 million aggregate principal amount of Series 2018A 4.30% Senior Notes due July 15, 2048.

253

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Georgia Power

In January 2018, Georgia Power repaid its outstanding $150 million and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively.

In April 2018, Georgia Power redeemed all $250 million aggregate principal amount of its Series 2008B 5.40% Senior Notes due June 1, 2018.

In May 2018, through cash tender offers, Georgia Power repurchased and retired $89 million of the $250 million aggregate principal amount outstanding of its Series 2007A 5.65% Senior Notes due March 1, 2037, $326 million of the $500 million aggregate principal amount outstanding of its Series 2009A 5.95% Senior Notes due February 1, 2039, and $335 million of the $600 million aggregate principal amount outstanding of its Series 2010B 5.40% Senior Notes due June 1, 2040, for an aggregate purchase price, excluding accrued and unpaid interest, of $902 million.

During 2018, Georgia Power purchased and held the following pollution control revenue bonds, which may be reoffered to the public at a later date:

• $104.6 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013

• $173 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009

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

• $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

• $71.735 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2013

Mississippi Power

In March 2018, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $100 million was repaid in the third quarter 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.

In July 2018, Mississippi Power purchased and held approximately $43 million aggregate principal amount of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002. Mississippi Power may reoffer these bonds to the public at a later date.

Subsequent to September 30, 2018, Mississippi Power completed the redemption of all 8,867 outstanding shares ($886,700 aggregate par value) of its 4.40% Series Preferred Stock, all 8,643 outstanding shares ($864,300 aggregate par value) of its 4.60% Series Preferred Stock, all 16,700 outstanding shares ($1.67 million aggregate par value) of its 4.72% Series Preferred Stock, all 1,200,000 outstanding depositary shares ($30 million aggregate stated value) each representing a ¹/₄^th interest in a share of its 5.25% Series Preferred Stock, all $30 million aggregate principal amount outstanding of its Series G 5.40% Senior Notes due July 1, 2035, and all $125 million aggregate principal amount outstanding of its Series 2009A 5.55% Senior Notes due March 1, 2019.

Southern Power

In May 2018, Southern Power entered into two short-term floating rate bank loans, each for an aggregate principal amount of $100 million, which bear interest based on one-month LIBOR.

254

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

In the second quarter 2018, Southern Power repaid $420 million aggregate principal amount of long-term floating rate bank loans and $350 million aggregate principal amount of Series 2015A 1.50% Senior Notes due June 1, 2018.

During the nine months ended September 30, 2018, Southern Power received approximately $148 million of third-party tax equity related to the Gaskell West 1 and Cactus Flats facilities. See Note (J) under "Southern Power" for additional information.

Southern Company Gas

On January 4, 2018, Southern Company Gas issued a floating rate promissory note to Southern Company in an aggregate principal amount of $100 million bearing interest based on one-month LIBOR. On March 28, 2018, Southern Company Gas repaid this promissory note.

Prior to its sale, in the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of gas facility revenue bonds to be redeemed.

In May 2018, Southern Company Gas Capital borrowed $95 million pursuant to a short-term uncommitted bank credit arrangement, guaranteed by Southern Company Gas, bearing interest at a rate agreed upon by Southern Company Gas Capital and the bank from time to time and payable on no less than 30 days' demand by the bank. The proceeds of the loan were used to repay short-term debt. In July 2018, Southern Company Gas Capital repaid this loan.

In July 2018, Nicor Gas agreed to issue $300 million aggregate principal amount of first mortgage bonds in a private placement, $100 million of which was issued in August 2018 and $200 million of which was issued in November 2018.

(G) RETIREMENT BENEFITS

On January 1, 2018, the qualified defined benefit pension plan of Southern Company Gas was merged into the qualified defined benefit pension plan of Southern Company. Following the plan merger, Southern Company has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The Southern Company qualified defined benefit 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 Southern Company qualified defined benefit pension plan are anticipated for the year ending December 31, 2018.

In addition, the Southern Company Gas non-qualified retirement plans were merged into the Southern Company non-qualified retirement plan (defined benefit and defined contribution). Following the non-qualified retirement plan mergers, Southern Company continues to provide certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis.

Furthermore, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas also provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. 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.

As indicated in Note (A), the registrants adopted ASU 2017-07 as of January 1, 2018. ASU 2017-07 requires that an employer report the service cost component of net periodic benefit costs in the same line item or items as other compensation costs and requires the other components of net periodic benefit costs to be separately presented in the statements of income outside of income from operations. The presentation requirements of ASU 2017-07 have been applied retrospectively with the service cost component of net periodic benefit costs included in operations and maintenance and all other components of net periodic benefit costs included in other income (expense), net in the statements of income for the three and nine months ended September 30, 2017.

255

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

With respect to the presentation requirements, the registrants have used the practical expedient provided by ASU 2017-07, which permits an employer to use the amounts disclosed in its retirement benefits footnote for prior comparative periods as the estimation basis for applying the retrospective presentation requirements to those periods. The amounts of the other components of net periodic benefit costs reclassified for the prior period are presented in the following tables.

See Note 2 to the financial statements of each registrant in Item 8 of the Form 10-K for additional information.

Components of the net periodic benefit costs for the three and nine months ended September 30, 2018 and 2017 are presented in the following tables.

Three Months Ended September 30, 2018	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	90		$	19		$	22		$	4		$	5		$	3		$	8
Interest cost	116			26			34			5			5			1			10
Expected return on plan assets	(236		)	(51		)	(74		)	(10		)	(11		)	(3		)	(18		)
Amortization:
Prior service costs	1			—			1			—			—			—			(1		)
Regulatory asset	—			—			—			—			—			—			4
Net (gain)/loss	53			13			18			2			3			—			3
Net periodic pension cost (income)	$	24		$	7		$	1		$	1		$	2		$	1		$	6
Postretirement Benefits
Service cost	$	6		$	1		$	2		$	—		$	—		$	1		$	—
Interest cost	19			5			7			1			—			—			2
Expected return on plan assets	(17		)	(7		)	(6		)	—			—			—			(1		)
Amortization:
Prior service costs	2			1			—			—			—			—			—
Regulatory asset	—			—			—			—			—			—			2
Net (gain)/loss	3			—			2			—			—			—			—
Net periodic postretirement benefit cost	$	13		$	—		$	5		$	1		$	—		$	1		$	3

256

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Nine Months Ended September 30, 2018	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	269		$	58		$	65		$	12		$	13		$	7		$	24
Interest cost	348			76			104			15			15			4			29
Expected return on plan assets	(707		)	(155		)	(222		)	(30		)	(31		)	(8		)	(53		)
Amortization:
Prior service costs	3			1			2			—			—			—			(2		)
Regulatory asset	—			—			—			—			—			—			11
Net (gain)/loss	160			40			52			7			8			1			9
Net periodic pension cost (income)	$	73		$	20		$	1		$	4		$	5		$	4		$	18
Postretirement Benefits
Service cost	$	18		$	4		$	5		$	1		$	1		$	1		$	1
Interest cost	56			13			21			2			2			—			7
Expected return on plan assets	(51		)	(20		)	(19		)	(1		)	(1		)	—			(5		)
Amortization:
Prior service costs	5			3			1			—			—			—			—
Regulatory asset	—			—			—			—			—			—			5
Net (gain)/loss	10			1			6			—			—			—			—
Net periodic postretirement benefit cost	$	38		$	1		$	14		$	2		$	2		$	1		$	8

257

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Three Months Ended September 30, 2017(*)	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	73		$	15		$	19		$	3		$	4		$	6
Interest cost	114			25			34			5			5			10
Expected return on plan assets	(224		)	(49		)	(71		)	(10		)	(9		)	(18		)
Amortization:
Prior service costs	3			1			—			—			—			—
Net (gain)/loss	41			10			15			2			1			5
Net periodic pension cost (income)	$	7		$	2		$	(3	)	$	—		$	1		$	3
Postretirement Benefits
Service cost	$	6		$	1		$	2		$	—		$	—		$	1
Interest cost	19			4			6			1			1			3
Expected return on plan assets	(16		)	(5		)	(6		)	—			—			(2		)
Amortization:
Prior service costs	2			1			—			—			—			(1		)
Net (gain)/loss	3			—			3			—			—			1
Net periodic postretirement benefit cost	$	14		$	1		$	5		$	1		$	1		$	2

(*) Excludes Southern Power since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017.

Nine Months Ended September 30, 2017(*)	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	220		$	47		$	56		$	10		$	11		$	17
Interest cost	341			73			103			15			15			30
Expected return on plan assets	(673		)	(147		)	(212		)	(29		)	(29		)	(53		)
Amortization:
Prior service costs	9			2			2			—			1			(1		)
Net (gain)/loss	122			31			43			5			5			15
Net periodic pension cost (income)	$	19		$	6		$	(8	)	$	1		$	3		$	8
Postretirement Benefits
Service cost	$	18		$	4		$	5		$	1		$	1		$	2
Interest cost	59			13			21			2			3			8
Expected return on plan assets	(49		)	(19		)	(18		)	(1		)	(1		)	(5		)
Amortization:
Prior service costs	5			3			1			—			—			(2		)
Net (gain)/loss	10			1			6			—			—			3
Net periodic postretirement benefit cost	$	43		$	2		$	15		$	2		$	3		$	6

(*) Excludes Southern Power since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017.

258

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(H) INCOME TAXES

See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for additional tax information.

Federal Tax Reform Legislation

Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the registrants consider all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. Each of the registrants is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note (B) under "Regulatory Matters" for additional information.

Current and Deferred Income Taxes

Tax Credit Carryforwards

Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $2.4 billion as of September 30, 2018 compared to $2.1 billion as of December 31, 2017.

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 2018 abandonment loss related to certain Kemper County energy facility expenditures as well as the projected taxable gains on the various sale transactions described in Note (J) and "Legal Entity Reorganizations" herein. The expected utilization of tax credit carryforwards could be further delayed by numerous factors, including the acquisition of additional renewable projects, increased generation at existing wind facilities, the purchase of rights to additional PTCs during construction of Plant Vogtle Units 3 and 4 pursuant to the MEAG Term Sheet, and changes in taxable income projections. See Note (B) under "Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4. The ultimate outcome of these matters cannot be determined at this time.

Valuation Allowances

	Georgia Power		Mississippi Power		Southern Company Gas		Southern Company
	(in millions)
Federal	$	6	$	—	$	11	$	19
State (net of federal benefit)	33		124		1		171
Balance at September 30, 2018	$	39	$	124	$	12	$	190

Southern Company had valuation allowances, net of related federal benefits, of $190 million at September 30, 2018 compared to $148 million at December 31, 2017. The increase was primarily due to Georgia Power's projected inability to utilize certain state tax credit carryforwards.

Effective Tax Rate

Each registrant's effective tax rate for the nine months ended September 30, 2018 varied significantly as compared to the corresponding period in 2017 due to the 14% lower 2018 federal tax rate resulting from the Tax Reform Legislation.

259

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 federal income tax benefits from ITCs and PTCs.

Southern Company's effective tax rate was 22.7% for the nine months ended September 30, 2018 compared to 42.6% for the corresponding period in 2017. The effective tax rate decrease was primarily due to the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation, the net state income tax benefits related to changes in state apportionment rates arising from the reorganization of Southern Power's legal entities as discussed further herein, and the $3.1 billion pre-tax loss on the Kemper IGCC, net of the non-deductible AFUDC equity portion, recorded in 2017, partially offset by the $1.1 billion pre-tax loss related to Plant Vogtle Units 3 and 4 and the income taxes recorded related to the Southern Company Gas Dispositions in 2018. See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) under "Kemper County Energy Facility" for additional information regarding the Kemper IGCC and Note (B) under "Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4. See Note (B) under "Regulatory Matters" for additional information on the flowback of excess deferred income taxes and Note (J) under "Southern Company Gas" for additional information on the Southern Company Gas Dispositions.

Southern Company recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Company uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.

Alabama Power

Alabama Power's effective tax rate was 23.9% for the nine months ended September 30, 2018 compared to 39.9% for the corresponding period in 2017. The effective tax rate decrease was primarily due to the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation. See Note (B) under "Regulatory Matters – Alabama Power" for additional information.

Georgia Power

Georgia Power's effective tax rate was 25.5% for the nine months ended September 30, 2018 compared to 37.0% for the corresponding period in 2017. The effective tax rate decrease was primarily due to the reduction in the federal corporate income tax rate and the $1.1 billion pre-tax loss related to the estimated probable loss on Plant Vogtle Units 3 and 4 recorded in 2018, partially offset by the valuation allowance on certain state tax credit carryforwards. See Note (B) under "Nuclear Construction" for additional information.

Gulf Power

Gulf Power's effective tax benefit rate was (0.5)% for the nine months ended September 30, 2018 compared to an effective tax rate of 39.4% for the corresponding period in 2017. The effective tax rate decrease was primarily due to the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation. See Note (B) under "Regulatory Matters – Gulf Power" for additional information.

Mississippi Power

Mississippi Power's effective tax rate was 20.8% for the nine months ended September 30, 2018 compared to a benefit rate of (30.3)% for the corresponding period in 2017. The effective tax rate increase was primarily due to the $3.1 billion pre-tax loss on the Kemper IGCC, net of the non-deductible AFUDC equity portion, recorded in 2017, partially offset by the reduction in the federal corporate income tax rate as a result of the Tax Reform Legislation. See Note (B) under "Regulatory Matters – Mississippi Power" for additional information.

260

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Southern Power

Southern Power's effective tax benefit rate was (220.3)% for the nine months ended September 30, 2018 compared to (66.5)% for the corresponding period in 2017. The effective tax rate decrease was primarily due to lower earnings before income taxes resulting from a $119 million asset impairment charge as a result of the pending sale of Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) and a $36 million asset impairment charge on wind turbine equipment held for development projects, as well as the reduction in the federal corporate income tax rate and the net state income tax benefits related to certain changes in apportionment rates arising from the reorganization of Southern Power's legal entities as described below. See Note (J) under "Southern Power" for additional information.

Southern Power recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Power uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.

Southern Company Gas

Southern Company Gas' effective tax rate was 61.8% for the nine months ended September 30, 2018 compared to 43.4% for the corresponding period in 2017. This increase was primarily related to income taxes recorded related to the Southern Company Gas Dispositions, partially offset by the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation, as well as the 2017 increases in deferred tax expense related to the enactment of the State of Illinois income tax legislation and new income tax apportionment factors in several states. See Note (B) under "Regulatory Matters – Southern Company Gas" and Note (J) under "Southern Company Gas" for additional information.

Legal Entity Reorganizations

In April 2018, Southern Power completed the final stage of a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization resulted in net state tax benefits related to certain changes in apportionment rates totaling approximately $54 million, which were recorded in the first half of 2018.

In September 2018, Southern Power also completed a legal reorganization of eight operating wind facilities under a new holding company, SP Wind, which resulted in net state tax benefits totaling approximately $11 million related to certain changes in apportionment rates.

Unrecognized Tax Benefits

See Note 5 to the financial statements of each registrant under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information.

The registrants had no unrecognized tax benefits as of September 30, 2018. It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

The IRS has finalized its audits of Southern Company's consolidated income tax returns through 2016, as well as the pre-Merger Southern Company Gas tax returns. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2012.

(I) 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

261

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 (D) for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. The 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.

The registrants adopted ASU 2017-12 as of January 1, 2018. See Note (A) under "Recently Adopted Accounting Standards – Other" for additional information.

Energy-Related Derivatives

Southern Company, 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 is expected to continue to mitigate price volatility. The Florida PSC approved a moratorium on Gulf Power's fuel-hedging program until January 1, 2021. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. 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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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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

• Regulatory Hedges — Energy-related derivative contracts which are 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 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 September 30, 2018, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, 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(*)	595	2022	2029
Alabama Power	82	2022	—
Georgia Power	165	2022	—
Gulf Power	9	2020	—
Mississippi Power	69	2022	—
Southern Power	15	2020	—
Southern Company Gas(*)	255	2021	2029

(*) Southern Company's and 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 4.3 billion mmBtu and short natural gas positions of 4 billion mmBtu as of September 30, 2018, 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 gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 13 million mmBtu for Southern Company, 2 million mmBtu for Alabama Power, 4 million mmBtu for Georgia Power, 1 million mmBtu for Gulf Power, 2 million mmBtu for Mississippi Power, and 4 million mmBtu for Southern Power.

For cash flow hedges of energy-related derivatives, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending September 30, 2019 are immaterial for all registrants.

Interest Rate Derivatives

Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize

263

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(UNAUDITED)

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 September 30, 2018, 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 September 30, 2018
	(in millions)					(in millions)
Fair Value Hedges of Existing Debt
Southern Company(*)	$	300	2.75%	3-month LIBOR + 0.92%	June 2020	$	(6	)
Southern Company(*)	1,500		2.35%	1-month LIBOR + 0.87%	July 2021	(60		)
Georgia Power	500		1.95%	3-month LIBOR + 0.76%	December 2018	(3		)
Georgia Power	200		4.25%	3-month LIBOR + 2.46%	December 2019	(3		)
Southern Company Consolidated	$	2,500				$	(72	)

(*) 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 next 12-month period ending September 30, 2019 are $(19) million for Southern Company and immaterial for all other registrants. Southern Company and certain subsidiaries have deferred gains and losses expected to be amortized into earnings through 2046.

Foreign Currency Derivatives

Southern Company and certain subsidiaries may also 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.

264

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At September 30, 2018, the following foreign currency derivatives were outstanding:

	Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at September 30, 2018
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	48
Southern Power	564		3.78%	500		1.85%	June 2026	51
Total	$	1,241		€	1,100			$	99

The estimated pre-tax gains (losses) related to foreign currency derivatives that will be reclassified from accumulated OCI to earnings for the next 12-month period ending September 30, 2019 are $(23) million for Southern Company and Southern Power.

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.

265

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(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 September 30, 2018						As of December 31, 2017
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	$	15		$	17		$	10		$	43
Other deferred charges and assets/Other deferred credits and liabilities	5			26			7			24
Assets held for sale, current/Liabilities held for sale, current	—			6			—			—
Assets held for sale/Liabilities held for sale	—			2			—			—
Total derivatives designated as hedging instruments for regulatory purposes	$	20		$	51		$	17		$	67
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	3		$	6		$	3		$	14
Other deferred charges and assets/Other deferred credits and liabilities	1			1			—			—
Interest rate derivatives:
Other current assets/Other current liabilities	—			22			1			4
Other deferred charges and assets/Other deferred credits and liabilities	—			50			—			34
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	122			—			129			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	126		$	102		$	133		$	75
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	263		$	317		$	380		$	437
Other deferred charges and assets/Other deferred credits and liabilities	134			198			170			215
Total derivatives not designated as hedging instruments	$	397		$	515		$	550		$	652
Gross amounts recognized	$	543		$	668		$	700		$	794
Gross amounts offset(a)	$	(303	)	$	(491	)	$	(405	)	$	(598	)
Net amounts recognized in the Balance Sheets(b)	$	240		$	177		$	295		$	196

266

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	As of September 30, 2018						As of December 31, 2017
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	$	5		$	4		$	2		$	6
Other deferred charges and assets/Other deferred credits and liabilities	2			6			2			4
Total derivatives designated as hedging instruments for regulatory purposes	$	7		$	10		$	4		$	10
Gross amounts recognized	$	7		$	10		$	4		$	10
Gross amounts offset	$	(4	)	$	(4	)	$	(4	)	$	(4	)
Net amounts recognized in the Balance Sheets	$	3		$	6		$	—		$	6
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	5		$	9		$	2		$	9
Other deferred charges and assets/Other deferred credits and liabilities	2			13			4			10
Total derivatives designated as hedging instruments for regulatory purposes	$	7		$	22		$	6		$	19
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	5		$	—		$	4
Other deferred charges and assets/Other deferred credits and liabilities	—			1			—			1
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	6		$	—		$	5
Gross amounts recognized	$	7		$	28		$	6		$	24
Gross amounts offset	$	(7	)	$	(7	)	$	(6	)	$	(6	)
Net amounts recognized in the Balance Sheets	$	—		$	21		$	—		$	18
Gulf Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	—		$	6		$	—		$	14
Other deferred charges and assets/Other deferred credits and liabilities	—			2			—			7
Total derivatives designated as hedging instruments for regulatory purposes	$	—		$	8		$	—		$	21
Gross amounts recognized	$	—		$	8		$	—		$	21
Net amounts recognized in the Balance Sheets	$	—		$	8		$	—		$	21

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	As of September 30, 2018						As of December 31, 2017
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	$	2		$	3		$	1		$	6
Other deferred charges and assets/Other deferred credits and liabilities	1			6			1			3
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	9		$	2		$	9
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	—		$	1		$	—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	—		$	1		$	—
Gross amounts recognized	$	3		$	9		$	3		$	9
Gross amounts offset	$	(3	)	$	(3	)	$	(2	)	$	(2	)
Net amounts recognized in the Balance Sheets	$	—		$	6		$	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	$	2		$	6		$	3		$	11
Other deferred charges and assets/Other deferred credits and liabilities	1			1			—			—
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	122			—			129			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	125		$	30		$	132		$	34
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	—		$	—		$	—		$	2
Gross amounts recognized	$	125		$	30		$	132		$	36
Gross amounts offset	$	(2	)	$	(2	)	$	(3	)	$	(3	)
Net amounts recognized in the Balance Sheets	$	123		$	28		$	129		$	33

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	As of September 30, 2018						As of December 31, 2017
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	$	3		$	1		$	5		$	8
Other deferred charges and assets/Other deferred credits and liabilities	—			1			—			—
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	2		$	5		$	8
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	$	1		$	—		$	—		$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	262		$	316		$	379		$	434
Other deferred charges and assets/Other deferred credits and liabilities	134			198			170			215
Total derivatives not designated as hedging instruments	$	396		$	514		$	549		$	649
Gross amounts of recognized	$	400		$	516		$	554		$	660
Gross amounts offset(a)	$	(287	)	$	(475	)	$	(390	)	$	(583	)
Net amounts recognized in the Balance Sheets(b)	$	113		$	41		$	164		$	77

(a) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $189 million and $193 million as of September 30, 2018 and December 31, 2017, respectively.

(b) Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $5 million and $11 million as of September 30, 2018 and December 31, 2017, respectively.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At September 30, 2018 and December 31, 2017, 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 September 30, 2018
Derivative Category and Balance Sheet Location	Southern Company(*)			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas(*)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(9	)	$	(2	)	$	(4	)	$	(6	)	$	(2	)	$	(1	)
Other regulatory assets, deferred	(20		)	(4		)	(11		)	(2		)	(5		)	—
Assets held for sale, current	(6		)	—			—			—			—			—
Assets held for sale	(2		)	—			—			—			—			—
Other regulatory liabilities, current	8			3			—			—			—			5
Total energy-related derivative gains (losses)	$	(29	)	$	(3	)	$	(15	)	$	(8	)	$	(7	)	$	4

(*) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $3 million at September 30, 2018.

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2017
Derivative Category and Balance Sheet Location	Southern Company(*)			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas(*)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(34	)	$	(4	)	$	(7	)	$	(14	)	$	(5	)	$	(4	)
Other regulatory assets, deferred	(18		)	(3		)	(6		)	(7		)	(2		)	—
Other regulatory liabilities, current	7			—			—			—			—			7
Other regulatory liabilities, deferred	1			1			—			—			—			—
Total energy-related derivative gains (losses)	$	(44	)	$	(6	)	$	(13	)	$	(21	)	$	(7	)	$	3

(*) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million at December 31, 2017.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the three and nine months ended September 30, 2018 and 2017, 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 September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Southern Company
Energy-related derivatives	$	(5	)	$	(6	)	$	7		$	(26	)
Interest rate derivatives	—			(1		)	(2		)	(2		)
Foreign currency derivatives	(10		)	46			(31		)	114
Total	$	(15	)	$	39		$	(26	)	$	86
Southern Power
Energy-related derivatives	$	(5	)	$	(6	)	$	5		$	(21	)
Foreign currency derivatives	(10		)	46			(31		)	114
Total	$	(15	)	$	40		$	(26	)	$	93
Southern Company Gas
Energy-related derivatives	$	—		$	—		$	2		$	(4	)

For the three and nine months ended September 30, 2018 and 2017, 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 nine months ended September 30, 2017, there was no material ineffectiveness recorded in earnings for any registrant. Upon the adoption of ASU 2017-12, beginning in 2018, ineffectiveness was no longer separately measured and recorded in earnings. See Note (A) for additional information.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the three and nine months ended September 30, 2018 and 2017, 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 September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Southern Company
Cost of natural gas	$	104		$	134		$	1,053		$	1,085
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	—			—			(2		)	—
Depreciation and amortization	787			767			2,338			2,236
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	—			(6		)	2			(12		)
Interest expense, net of amounts capitalized	(458		)	(407		)	(1,386		)	(1,248		)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(5		)	(5		)	(16		)	(15		)
Foreign currency derivatives	(6		)	(5		)	(18		)	(17		)
Gain (loss) on fair value hedges(b)
Interest rate derivatives	(4		)	(5		)	(35		)	(6		)
Other income (expense), net	57			65			195			165
Gain (loss) on cash flow hedges(a)(c)
Foreign currency derivatives	(9		)	43			(46		)	139
Alabama Power
Interest expense, net of amounts capitalized	$	(82	)	$	(76	)	$	(240	)	$	(229	)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(1		)	(2		)	(4		)	(5		)
Georgia Power
Interest expense, net of amounts capitalized	$	(95	)	$	(105	)	$	(303	)	$	(310	)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(1		)	(1		)	(4		)	(3		)
Gain (loss) on fair value hedges(b)
Interest rate derivatives	—			—			(1		)	(1		)
Mississippi Power
Interest expense, net of amounts capitalized	$	(19	)	$	13		$	(59	)	$	(23	)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	—			—			(1		)	(1		)

272

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Southern Power
Depreciation and amortization	$	130		$	131		$	370		$	379
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	—			(6		)	2			(12		)
Interest expense, net of amounts capitalized	(45		)	(47		)	(138		)	(144		)
Gain (loss) on cash flow hedges(a)
Foreign currency derivatives	(6		)	(5		)	(18		)	(17		)
Other income (expense), net	17			3			22			3
Gain (loss) on cash flow hedges(a)(c)
Foreign currency derivatives	(9		)	43			(46		)	139
Southern Company Gas
Cost of natural gas	$	104		$	134		$	1,053		$	1,085
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	—			—			(2		)	—

(a) Amounts reflect gains or losses on cash flow hedges that were reclassified from accumulated OCI into income.

(b) For fair value hedges presented above, generally changes in the fair value of the derivative contracts are 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 nine months ended September 30, 2018 and 2017, the pre-tax effects of cash flow hedge accounting on income for interest rate derivatives were immaterial for Gulf Power and Southern Company Gas.

As of September 30, 2018 and December 31, 2017, 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 September 30, 2018			As of December 31, 2017			As of September 30, 2018		As of December 31, 2017
	(in millions)						(in millions)
Southern Company
Securities due within one year	$	(499	)	$	(746	)	$	1	$	3
Long-term debt	(2,526		)	(2,553		)	65		35
Georgia Power
Securities due within one year	$	(499	)	$	(746	)	$	1	$	3
Long-term debt	(497		)	(498		)	2		1

273

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the three and nine months ended September 30, 2018 and 2017, 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 September 30,						Nine Months Ended September 30,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2018			2017			2018			2017
		(in millions)						(in millions)
Energy-related derivatives:	Natural gas revenues(*)	$	(36	)	$	(17	)	$	(79	)	$	48
	Cost of natural gas	2			2			5			(2		)
Total derivatives in non-designated hedging relationships		$	(34	)	$	(15	)	$	(74	)	$	46

(*) Excludes gains (losses) recorded in natural gas revenues associated with weather derivatives of $15 million for the nine months ended September 30, 2017 and immaterial amounts for all other periods presented.

For the three and nine months ended September 30, 2018 and 2017, 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 September 30, 2018, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

For the registrants with interest rate derivatives at September 30, 2018, 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 September 30, 2018, 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.

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 September 30, 2018, 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 September 30, 2018, cash collateral held on deposit in broker margin accounts was $189 million.

274

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas 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. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's, the traditional electric operating companies', Southern Power's, and Southern Company Gas' exposure to counterparty credit risk. 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.

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

275

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(J) ACQUISITIONS AND DISPOSITIONS

Southern Company's Sale of Gulf Power

On May 20, 2018, Southern Company entered into a stock purchase agreement (Gulf Power SPA) with NextEra Energy and its wholly-owned subsidiary 700 Universe, LLC, which provides for the sale of all of the capital stock of Gulf Power for an aggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $1.3 billion), subject to (i) customary adjustments for indebtedness and working capital and (ii) reduction by the amount (if any) by which Gulf Power fails to meet a specified capital expenditure target.

The Gulf Power SPA contains customary representations, warranties, and covenants of Southern Company, 700 Universe, LLC, and NextEra Energy. These covenants include, among others, an obligation of Southern Company to cause Gulf Power to operate its business in the ordinary course until the sale is consummated and an obligation for each of the parties to use reasonable best efforts to obtain the governmental and regulatory approvals described below.

The completion of the sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) approval by the FERC and the Federal Communications Commission, (ii) the entry into certain ancillary agreements, including transmission-related agreements and a transition services agreement, among the parties and their affiliates, and (iii) other customary closing conditions.

The Gulf Power SPA may be terminated by either Southern Company or 700 Universe, LLC under certain circumstances, including if the sale is not consummated by June 28, 2019 (subject to extension to December 31, 2019, if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). The Gulf Power SPA further provides that, upon the termination thereof, (i) under certain specified circumstances, 700 Universe, LLC will be required to pay Southern Company a termination fee of $100 million or $200 million (such amount depending on the specific circumstances of such termination) and (ii) upon certain other specified circumstances Southern Company will be required to pay 700 Universe, LLC a termination fee of $100 million.

The sale of Gulf Power is expected to occur in the first quarter 2019. The assets and liabilities of Gulf Power are classified as assets held for sale and liabilities held for sale on Southern Company's balance sheet as of September 30, 2018. See "Assets Held for Sale" below for additional information. The ultimate outcome of this matter cannot be determined at this time.

Southern Power

See Note 11 to the financial statements of Southern Power and Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K for additional information.

Acquisitions During the Nine Months Ended September 30, 2018

During the nine months ended September 30, 2018, one of Southern Power's wholly-owned subsidiaries acquired and completed construction of the Gaskell West 1 solar facility. Acquisition-related costs were expensed as incurred and were not material.

Project Facility	Resource	Seller; Acquisition Date	Approximate Nameplate Capacity (MW)	Location	Southern Power Percentage Ownership		Actual COD	PPA Contract Period
Gaskell West 1	Solar	Recurrent Energy Development Holdings, LLC January 26, 2018	20	Kern County, CA	100% of Class B	(*)	March 2018	20 years

(*) Southern Power owns 100% of the class B membership interests under a tax equity partnership agreement.

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The Gaskell West 1 facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service during March 2018.

Construction Projects in Progress and/or Completed

During the nine months ended September 30, 2018, Southern Power started, continued, or completed construction of the projects set forth in the table below. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $575 million and $640 million for the Mankato, Wild Horse Mountain, and Reading facilities. At September 30, 2018, construction costs included in CWIP related to these projects totaled $246 million. 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
Cactus Flats(a)	Wind	148	Concho County, TX	July 2018	12-15 years
Mankato	Natural Gas	385	Mankato, MN	First half 2019	20 years
Wild Horse 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 July 2017, Southern Power purchased 100% of the Cactus Flats facility and commenced construction. In July 2018, the facility was placed in service and, in August 2018, Southern Power closed on a tax equity partnership agreement and owns 100% of the class B membership interests.

(b) In May 2018, Southern Power purchased 100% of the Wild Horse Mountain facility and commenced construction. Southern Power may enter into a tax equity partnership agreement, in which case it would then own 100% of the class B membership interests.

(c) In August 2018, Southern Power purchased 100% of the membership interests from the joint development arrangement with Renewable Energy Systems Americas, Inc. and commenced construction. Southern Power may enter into a tax equity partnership agreement, in which case it would then own 100% of the class B membership interests.

Development Projects

During 2017, as part of its renewable development strategy, Southern Power purchased wind turbine equipment from Siemens Gamesa Renewable Energy Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction projects. Any wind projects using this equipment and reaching commercial operation by the end of 2021 are expected to qualify for 80% PTCs.

During 2016, Southern Power entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct wind projects. In addition, in 2016, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Any wind projects using this equipment and reaching commercial operation by the end of 2020 are expected to qualify for 100% PTCs.

In response to the previously disclosed decrease of planned expenditures for plant acquisitions and placeholder growth, Southern Power continues to refine the deployment of the wind turbine equipment to potential joint development and construction projects as well as the amount of MW capacity to be constructed. During the third quarter 2018, as a result of a review of various options for probable dispositions of wind turbine equipment not already deployed to development or construction projects, Southern Power recorded a $36 million asset impairment charge on the equipment.

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

Sale of Solar Facility Interests

In May 2018, Southern Power sold a 33% equity interest in SPSH, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, to Global Atlantic Financial Group Limited (Global Atlantic) for approximately $1.2 billion, subject to customary working capital adjustments. The proceeds were used to repay

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$770 million of existing indebtedness, to return capital of $250 million to Southern Company, and for other general corporate purposes, including working capital. Since Southern Power retains control of the limited partnership through its wholly-owned general partner, the sale was recorded as an equity transaction and Southern Power will continue to consolidate the results of SPSH. On the date of the transaction, the noncontrolling interest was increased by $511 million to reflect 33% of the carrying value of the partnership. This difference, partially offset by the tax impact and other related transaction charges, also resulted in a $410 million decrease to Southern Power's common stockholder's equity.

Sale of Florida Plants

In May 2018, Southern Power entered into an equity interest purchase agreement with NextEra Energy to sell all of its equity interests in the Florida Plants, for an aggregate purchase price of $195 million, subject to customary working capital and timing adjustments.

The sale is subject to certain closing and timing conditions and approvals, including, but not limited to, approval by the FERC. The ultimate purchase price will decrease $110,000 per day for each day after December 31, 2018 through the closing of the transaction. Conversely, the ultimate purchase price will increase $110,000 per day for each day the closing occurs prior to December 31, 2018. The sale is expected to occur in the first quarter 2019. As a result of this pending transaction, Southern Power recorded an asset impairment charge of approximately $119 million ($89 million after tax) in the second quarter 2018. The assets and liabilities of the Florida Plants are classified as assets held for sale and liabilities held for sale on Southern Company's and Southern Power's balance sheets as of September 30, 2018. See "Assets Held for Sale" below for additional information. The ultimate outcome of this matter cannot be determined at this time.

Sale of Wind Facility Interests

On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. The transaction is subject to Public Utility Commission of Texas approval and is expected to close by the end of 2018. Southern Power intends to use the proceeds to return capital of approximately $1.0 billion to Southern Company. The ultimate outcome of this matter cannot be determined at this time.

Sale of Mankato Plant

On November 5, 2018, Southern Power entered into an agreement with Northern States Power to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of $650 million, subject to customary working capital and timing adjustments. The ultimate purchase price will decrease $66,667 per day for each day after June 1, 2019, if the expansion has not achieved commercial operation, but such decrease will not exceed $15 million. This transaction is subject to the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and FERC and state commission approvals and is expected to close mid-2019. The ultimate outcome of this matter cannot be determined at this time.

Assets Subject to Lien

Under the terms of the PPA and the expansion PPA for the Mankato project, approximately $500 million of assets, primarily related to property, plant, and equipment, are subject to lien at September 30, 2018.

Southern Company Gas

Sale of Pivotal Home Solutions

On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $365 million, which includes the final working capital adjustment. This disposition resulted in an estimated net loss of $73 million, which includes $39 million of income tax expense, the calculation of which is expected to be finalized in the fourth quarter 2018. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded during the first quarter 2018. The after-tax

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loss included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Southern Company Gas and American Water Enterprises LLC entered into a transition services agreement whereby Southern Company Gas provided certain administrative and operational services through November 4, 2018.

Sale of Elizabethtown Gas and Elkton Gas

On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion and an additional $40 million for working capital, subject to a final working capital adjustment expected in the fourth quarter 2018. This disposition resulted in an estimated pre-tax gain of approximately $230 million and an after-tax gain of approximately $18 million, the calculations of which are expected to be finalized in the fourth quarter 2018. The after-tax gain included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Southern Company Gas and South Jersey Industries, Inc. entered into transition services agreements whereby Southern Company Gas will provide certain administrative and operational services through no later than January 31, 2020.

Sale of Florida City Gas

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 Energyfor a total cash purchase price of$530 million (less $3 million of indebtedness assumed at closing for customer deposits) and an additional $60 million for cash and other working capital, which includes the final working capital adjustment. This disposition resulted in an estimated pre-tax gain of approximately $121 million and an after-tax gain of approximately $20 million, the calculations of which are expected to be finalized in the fourth quarter 2018. The after-tax gain included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Southern Company Gas and NextEra Energy entered into a transition services agreement whereby Southern Company Gas will provide certain administrative and operational services through no later than July 29, 2020.

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 September 30, 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 May 2018, Southern Power ceased recognizing depreciation on the Florida Plants' property, plant, and equipment to be sold. Since the depreciation of the assets to be sold in the Gulf Power transaction continues to be reflected in customer rates and will be reflected in the carryover basis of the assets when sold, Southern Company will continue to record depreciation on those assets through the date the transaction closes. Likewise, since the depreciation of the assets sold in the Elizabethtown Gas, Elkton Gas, and Florida City Gas transactions continued to be reflected in customer rates and was reflected in the carryover basis of the assets when sold, Southern Company Gas continued to record depreciation on those assets through the respective date that each transaction closed.

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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 September 30, 2018:

	Southern Company		Southern Power
	(in millions)
Assets Held for Sale:
Current assets	$	407	$	18
Total property, plant, and equipment	4,093		168
Other non-current assets	574		17
Total Assets Held for Sale	$	5,074	$	203
Liabilities Held for Sale:
Current liabilities	$	355	$	4
Long-term debt	1,285		—
Accumulated deferred income taxes	542		—
Other non-current liabilities	1,008		—
Total Liabilities Held for Sale	$	3,190	$	4

Southern Company, Southern Power, and Southern Company Gas 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 the Florida Plants represent individually significant components of Southern Company and Southern Power, respectively; therefore, pre-tax profit for these components for the three and nine months ended September 30, 2018 and 2017 is presented below:

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2018		2017		2018		2017
	(in millions)				(in millions)
Earnings before income taxes:
Gulf Power	$	59	$	103	$	146	$	199
Southern Power's Florida Plants	$	18	$	11	$	40	$	28

(K) VARIABLE INTEREST ENTITY AND EQUITY METHOD INVESTMENTS

Southern Power

In May 2018, Southern Power sold a 33% limited partnership interest in SPSH to Global Atlantic. See Note (J) under "Southern Power" for additional information. A wholly-owned subsidiary of Southern Power is the general partner and holds a 1% ownership interest in SPSH and another wholly-owned subsidiary of Southern Power owns the remaining 66% ownership in SPSH. SPSH is a variable interest entity (VIE) because the arrangement is structured as a limited partnership and the 33% limited partner does not have substantive kick-out rights against the general partner. Southern Power previously consolidated SPSH and will continue to do so as the primary beneficiary of the VIE because it controls the most significant activities of the partnership, including operating and maintaining its assets.

At September 30, 2018, SPSH had total assets of $6.4 billion, total liabilities of $111 million, and noncontrolling interests related to other partners' interests of $1.2 billion. Cash distributions from SPSH are allocated 67% to

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(UNAUDITED)

Southern Power and 33% to Global Atlantic in accordance with their membership interests and the limited partnership agreement.

Transfers and sales of the assets in the VIE are subject to limited partner consent and the liabilities do not have recourse to the general credit of Southern Power. Liabilities consist of customary working capital items and do not include any long-term debt.

Southern Company Gas

See Note 4 to the financial statements of Southern Company Gas 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 September 30, 2018 and December 31, 2017 and related income from those investments for the three and nine-month periods ended September 30, 2018 and September 30, 2017 were as follows:

Investment Balance	September 30, 2018		December 31, 2017
	(in millions)
SNG	$	1,260	$	1,262
Atlantic Coast Pipeline	73		41
PennEast Pipeline	70		57
Other	126		117
Total	$	1,529	$	1,477

Earnings from Equity Method Investments	Three Months Ended September 30, 2018		Three Months Ended September 30, 2017		Nine Months Ended September 30, 2018		Nine Months Ended September 30, 2017
	(in millions)
SNG	$	29	$	28	$	95	$	86
PennEast Pipeline	2		1		4		5
Atlantic Coast Pipeline	1		1		4		4
Other	2		2		5		5
Total	$	34	$	32	$	108	$	100

Southern Natural Gas

Selected financial information of SNG for the three and nine months ended September 30, 2018 and September 30, 2017 is as follows:

Income Statement Information	Three Months Ended September 30, 2018		Three Months Ended September 30, 2017		Nine Months Ended September 30, 2018		Nine Months Ended September 30, 2017
	(in millions)
Revenues	$	145	$	146	$	451	$	445
Operating income	$	71	$	71	$	230	$	218
Net income	$	58	$	57	$	190	$	172

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(L) 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 four traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four 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 marketing services, wholesale gas services, and gas midstream operations. In July 2018, Southern Company Gas completed sales of three of its natural gas distribution utilities. See Note (J) under "Southern Company Gas" for additional information.

Southern Company's reportable business segments are the sale of electricity by the four 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 $134 million and $326 million for the three and nine months ended September 30, 2018, respectively, and $105 million and $295 million for the three and nine months ended September 30, 2017, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were $14 million and $22 million for the three and nine months ended September 30, 2018, respectively, and $9 million and $19 million for the three and nine months ended September 30, 2017, respectively. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $38 million and $96 million for the three and nine months ended September 30, 2018, respectively, and $38 million and $94 million for the three and nine months ended September 30, 2017, 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 technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers; as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.

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Financial data for business segments and products and services for the three and nine months ended September 30, 2018 and 2017 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 September 30, 2018:
Operating revenues	$	5,014	$	635	$	(140	)	$	5,509	$	492	$	202		$	(44	)	$	6,159
Segment net income (loss)(a)(b)(c)(d)	1,148		92		—			1,240		46		(119		)	(3		)	1,164
Nine Months Ended September 30, 2018:
Operating revenues	$	13,117	$	1,699	$	(360	)	$	14,456	$	2,861	$	984		$	(143	)	$	18,158
Segment net income (loss)(a)(b)(c)(d)	1,711		235		—			1,946		294		(292		)	—			1,948
At September 30, 2018:
Goodwill	$	—	$	2	$	—		$	2	$	5,015	$	298		$	—		$	5,315
Total assets	75,069		15,355		(322		)	90,102		20,398		3,086			(1,869		)	111,717
Three Months Ended September 30, 2017:
Operating revenues	$	5,017	$	618	$	(112	)	$	5,523	$	565	$	153		$	(40	)	$	6,201
Segment net income (loss)(a)(b)	1,008		124		—			1,132		15		(80		)	2			1,069
Nine Months Ended September 30, 2017:
Operating revenues	$	12,960	$	1,597	$	(318	)	$	14,239	$	2,841	$	442		$	(119	)	$	17,403
Segment net income (loss)(a)(b)(e)	—		276		—			276		303		(232		)	—			347
At December 31, 2017:
Goodwill	$	—	$	2	$	—		$	2	$	5,967	$	299		$	—		$	6,268
Total assets	72,204		15,206		(325		)	87,085		22,987		2,552			(1,619		)	111,005

(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 $1 million ($1 million after tax) and $34 million ($21 million after tax) for the three months ended September 30, 2018 and 2017, respectively, and $1.1 billion ($0.8 billion after tax) and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2018 and 2017, respectively. See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) under "Nuclear Construction" and "Kemper County Energy Facility" for additional information.

(c) Segment net income (loss) for Southern Power includes pre-tax impairment charges of $36 million ($27 million after tax) and $155 million ($116 million after tax) for the three and nine months ended September 30, 2018, respectively. See Note (J) under "Southern Power – Development Projects" and " – Sale of Florida Plants" for additional information.

(d) Segment net income (loss) for Southern Company Gas includes a net gain on dispositions of $353 million ($40 million gain after tax) and $317 million ($35 million loss after tax) for the three and nine months ended September 30, 2018, respectively, related to the Southern Company Gas Dispositions and a goodwill impairment charge of $42 million for the nine months ended September 30, 2018 related to the sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.

(e) Segment net income (loss) for the traditional electric operating companies includes a pre-tax charge for the write-down of Gulf Power's ownership of Plant Scherer Unit 3 of $33 million ($20 million after tax) for the nine months ended September 30, 2017. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.

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(UNAUDITED)

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2018	$	4,605	$	693	$	211	$	5,509
Three Months Ended September 30, 2017	4,615		718		190		5,523
Nine Months Ended September 30, 2018	$	11,913	$	1,923	$	620	$	14,456
Nine Months Ended September 30, 2017	11,786		1,867		586		14,239

	Southern Company Gas' Revenues
Period	Gas Distribution Operations		Gas Marketing Services		Other			Total
	(in millions)
Three Months Ended September 30, 2018	$	438	$	44	$	10		$	492
Three Months Ended September 30, 2017	430		143		(8		)	565
Nine Months Ended September 30, 2018	$	2,276	$	403	$	182		$	2,861
Nine Months Ended September 30, 2017	2,119		597		125			2,841

Southern Company Gas

Southern Company Gas manages its business through four reportable segments – gas distribution operations, gas marketing services, wholesale gas services, and gas midstream operations. 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 seven states. In July 2018, Southern Company Gas sold three of its natural gas distribution utilities, Elizabethtown Gas, Elkton Gas, and Florida City Gas. See Note (J) under "Southern Company Gas" for additional information.

Gas marketing services includes natural gas marketing to end-use customers primarily in Georgia and Illinois. On June 4, 2018, Southern Company Gas sold Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.

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 midstream operations primarily consists of Southern Company Gas' pipeline investments, with storage and fuel operations also aggregated into this segment.

The all other column includes segments below the quantitative threshold for separate disclosure, including the subsidiaries that fall below the quantitative threshold for separate disclosure.

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(UNAUDITED)

Business segment financial data for the three and nine months ended September 30, 2018 and 2017 was as follows:

	Gas Distribution Operations(a)(c)		Gas Marketing Services(b)(c)			Wholesale Gas Services(d)			Gas Midstream Operations		Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended September 30, 2018:
Operating revenues	$	441	$	44		$	(8	)	$	20	$	497	$	1		$	(6	)	$	492
Segment net income (loss)	74		(8		)	(18		)	16		64		(18		)	—			46
Nine Months Ended September 30, 2018:
Operating revenues	2,297		403			142			60		2,902		3			(44		)	2,861
Segment net income (loss)	290		(71		)	65			54		338		(44		)	—			294
Total assets at September 30, 2018:	16,850		1,522			855			2,297		21,524		10,146			(11,272		)	20,398
Three Months Ended September 30, 2017:
Operating revenues	$	472	$	143		$	(24	)	$	16	$	607	$	2		$	(44	)	$	565
Segment net income (loss)	52		1			(23		)	14		44		(29		)	—			15
Nine Months Ended September 30, 2017:
Operating revenues	2,255		597			95			53		3,000		7			(166		)	2,841
Segment net income (loss)	223		36			28			38		325		(22		)	—			303
Total assets at December 31, 2017:	19,358		2,147			1,096			2,241		24,842		12,184			(14,039		)	22,987

(a) Operating revenues for the three gas distribution operations dispositions were $8 million and $50 million for the three months ended September 30, 2018 and 2017, respectively, and $245 million and $274 million for the nine months ended September 30, 2018 and 2017, respectively. See Note (J) under "Southern Company Gas" for additional information.

(b) Operating revenues for the gas marketing services disposition were $32 million for the three months ended September 30, 2017 and $55 million and $95 million for the nine months ended September 30, 2018 and 2017, respectively. See Note (J) under "Southern Company Gas" for additional information.

(c) Segment net income for gas distribution operations includes a gain on dispositions of $351 million ($38 million after tax) for the three and nine months ended September 30, 2018. Segment net income for gas marketing services includes a gain on disposition of $2 million ($2 million after tax) for the three months ended September 30, 2018 and a loss on disposition of $34 million ($73 million loss after tax) and a goodwill impairment charge of $42 million for the nine months ended September 30, 2018 recorded in contemplation of the sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.

(d) 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 September 30, 2018	$	1,573	$	82	$	1,655	$	1,663	$	(8	)
Three Months Ended September 30, 2017	1,411		103		1,514		1,538		(24		)
Nine Months Ended September 30, 2018	$	4,847	$	352	$	5,199	$	5,057	$	142
Nine Months Ended September 30, 2017	4,781		362		5,143		5,048		95

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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. Except as described below, there have been no material changes to these risk factors from those previously disclosed in the Form 10-K.

Georgia Power may incur additional costs or delays in the construction of Plant Vogtle Units 3 or 4 and may not be able to recover its investments, which could have a material impact on the financial statements of Southern Company and Georgia Power.

Background

In 2009, the Georgia PSC certified construction of 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 Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired in July 2017 when Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement. Under the Vogtle Services Agreement, Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis.

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.

In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor.

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Cost and Schedule

In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. 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 September 30, 2018(b)	(4.3		)
Remaining estimate to complete(a)	$	4.1

(a) Excludes financing costs expected to be capitalized through AFUDC of approximately $350 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 $3.2 billion, of which $1.8 billion had been incurred through September 30, 2018.

The table above reflects the $0.7 billion increase to the base capital cost forecast reported in the second quarter 2018 and is based on the cost reforecast performed prior to the nineteenth VCM filing, which primarily resulted from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.

Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power did not seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs) in the nineteenth VCM report that was filed with the Georgia PSC on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018, which includes the total increase in the base capital cost forecast and construction contingency estimate.

As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule continue to increase significantly through the remainder of 2018 and into 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers 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

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approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria (ITAAC) and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Joint Owner Contracts

In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective August 31, 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements).

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

Amendments to the Vogtle Joint Ownership Agreements

In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners, and (ii) a term sheet (MEAG Term Sheet and, together with the Vogtle Owner Term Sheet, Term Sheets) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 (Project J) under certain circumstances. Pursuant to the Vogtle Owner Term Sheet, the Vogtle Joint Ownership Agreements will be modified as follows: (i) each Vogtle Owner will pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which forms the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million of additional construction costs; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests.

If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction

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costs in excess of the EAC in the nineteenth VCM plus $2.1 billion. In this event, Georgia Power will have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Vogtle Owner. If Georgia Power accepts the offer to purchase a portion of another Vogtle Owner's ownership interest in Plant Vogtle Units 3 and 4, the ownership interest(s) to be conveyed from the tendering Vogtle Owner(s) to Georgia Power would be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Vogtle Owner(s) and by Georgia Power as of the commercial operation date of Plant Vogtle Unit 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Vogtle Owner in accordance with the second and third items described in the paragraph above would be treated as payments made by the applicable Vogtle Owner.

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

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

Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain of the above provisions of the Vogtle Owner Term Sheet.

Under the Vogtle Owner Term Sheet, the provisions of the Vogtle Joint Ownership Agreements requiring that Vogtle Owners holding 90% of the ownership interests in Plant Vogtle Units 3 and 4 vote to continue construction following certain adverse events (Project Adverse Events) will be modified. Pursuant to the Vogtle Joint Ownership Agreements and the Vogtle Owner Term Sheet, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain Project Adverse Events occur, including: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Vogtle Owner Term Sheet provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule. Under the Vogtle Owner Term Sheet, Georgia Power may cancel the project at any time in its sole discretion.

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

The Vogtle Owner Term Sheet provides that if the holders of at least 90% of the ownership interests fail to vote in favor of continuing the project following any future Project Adverse Event, work on Plant Vogtle Units 3 and 4 would continue for a period of 30 days if the holders of more than 50% of the ownership interests vote in favor of continuing construction (Majority Voting Owners). In such a case, the Vogtle Owners (i) would agree to negotiate in

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good faith towards the resumption of the project, (ii) if no agreement was reached during such 30-day period, the project would be cancelled, and (iii) in the event of such a cancellation, the Majority Voting Owners would be obligated to reimburse any other Vogtle Owner for the costs it incurred during such 30-day negotiation period.

Purchase of PTCs During Commercial Operation

In addition, under the terms of the Vogtle Owner Term Sheet, Georgia Power agreed to purchase additional PTCs from OPC, Dalton, MEAG SPVM, MEAG SPVP, and MEAG SPVJ (to the extent any MEAG SPVJ PTC rights remain after any purchases required under the MEAG Term Sheet as described below) at varying purchase prices dependent upon the actual cost to complete construction of Plant Vogtle Units 3 and 4 as compared to the EAC included in the nineteenth VCM report. The purchases will be at the option of the applicable Vogtle Owner and will occur during the month after such PTCs are earned.

Potential Funding to MEAG Project J

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

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

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

Under the terms of the MEAG Term Sheet, Georgia Power may decline to provide any funding in the form of advances, including in the event of a failure to receive any required Georgia PSC or DOE approvals, and cancel the project in lieu of providing such funding.

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

Regulatory Matters

In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's recommendation to continue construction and resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and related Customer Refunds) was found reasonable; (iv) construction

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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 $25 million in 2017 and are estimated to have negative earnings impacts of approximately $100 million in 2018 and an aggregate of $680 million from 2019 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.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. On March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's final decision and denial of Georgia Watch's motion for reconsideration. Georgia Power believes the two appeals have no merit; however, an adverse outcome in either 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.

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

See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

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.

	(4) Instruments Describing Rights of Security Holders, Including Indentures
	Southern Company
*	(a)1	-	Twentieth Supplemental Indenture to Senior Note Indenture, dated as of August 17, 2018, providing for the issuance of the Series 2018A Floating Rate Senior Notes due February 14, 2020.
	Southern Company Gas
*	(g)1	-	Supplemental Indenture dated August 3, 2018 of Northern Illinois Gas Company to The Bank of New York Mellon Trust Company, N.A., under Indenture dated January 1, 1954.

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(10) Material Contracts
Georgia Power
(c)1	-	First Amendment to Agreement Regarding Additional Participating Party Rights and Amendment No. 3 to Plant Alvin W. Vogtle Additional Units Ownership Participation Agreement, dated as of August 31, 2018, among Georgia Power, Oglethorpe Power Corporation, MEAG, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, and The City of Dalton, Georgia. (Designated in Form 8-K dated August 31, 2018, File No. 1-6468 as Exhibit 10.1.)
(24) Power of Attorney and Resolutions
Southern Company
(a)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2017, File No. 1-3526 as Exhibit 24(a).)
(a)2	-	Power of Attorney for Andrew W. Evans. (Designated in Form 10-Q for the quarter ended June 30, 2018, File No. 1-3526 as Exhibit 24(a)2.)
Alabama Power
(b)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2017, File No. 1-3164 as Exhibit 24(b).)
Georgia Power
(c)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2017, File No. 1-6468 as Exhibit 24(c).)
Gulf Power
(d)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2017, File No. 001-31737 as Exhibit 24(d).)
Mississippi Power
(e)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2017, File No. 001-11229 as Exhibit 24(e).)
Southern Power
(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2017, File No. 001-37803 as Exhibit 24(f).)
(f)2	-	Power of Attorney for Mark S. Lantrip. (Designated in Form 10-Q for the quarter ended March 31, 2018, File No. 001-37803, as Exhibit 24(f)2.)
Southern Company Gas
(g)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2017, File No. 1-14174 as Exhibit 24(g).)
(g)2	-	Power of Attorney for Kimberly S. Greene. (Designated in Form 10-Q for the quarter ended June 30, 2018, File No. 1-14174 as Exhibit 24(g)2.)

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	(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.
	Gulf Power
*	(d)1	-	Certificate of Gulf Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(d)2	-	Certificate of Gulf Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Mississippi Power
*	(e)1	-	Certificate of Mississippi Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(e)2	-	Certificate of Mississippi Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Southern Power
*	(f)1	-	Certificate of Southern Power Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(f)2	-	Certificate of Southern Power Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	Southern Company Gas
*	(g)1	-	Certificate of Southern Company Gas' Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(g)2	-	Certificate of Southern Company Gas' Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

293

	(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.
	Gulf Power
*	(d)	-	Certificate of Gulf Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Mississippi Power
*	(e)	-	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
*	(f)	-	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
*	(g)	-	Certificate of Southern Company Gas' Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	(99) Additional Exhibits
	Georgia Power
	(c)	-	Co-Owner Term Sheet, dated September 26, 2018, among Georgia Power, Oglethorpe Power Corporation, MEAG, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, and the City of Dalton, Georgia. (Designated in Form 8-K dated September 26, 2018, File No. 000-53908 as Exhibit 10.1.)
	(101) Interactive Data Files
*	INS	-	XBRL Instance 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

294

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: November 6, 2018

295

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: November 6, 2018

296

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	Xia Liu
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 6, 2018

297

GULF 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.

	GULF POWER COMPANY
By	S. W. Connally, Jr.
	Chairman, President and Chief Executive Officer
	(Principal Executive Officer)
By	Robin B. Boren
	Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 6, 2018

298

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: November 6, 2018

299

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, President, and Chief Executive Officer
	(Principal Executive Officer)
By	William C. Grantham
	Senior Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 6, 2018

300

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	Elizabeth W. Reese
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 6, 2018

301

EX-4.A1

Exhibit 4(a)1

THE SOUTHERN COMPANY

TO

WELLS FARGO BANK, NATIONAL ASSOCIATION,

TRUSTEE

____________________

TWENTIETH SUPPLEMENTAL INDENTURE

DATED AS OF AUGUST 17, 2018

____________________

SERIES 2018A FLOATING RATE SENIOR NOTES

DUE FEBRUARY 14, 2020

TABLE OF CONTENTS¹ 

		Page
	ARTICLE 1	SERIES 2018A SENIOR NOTES	1
	SECTION 101.	Establishment	1
	SECTION 102.	Definitions	2
	SECTION 103.	Payment of Principal and Interest	4
	SECTION 104.	Determination of Interest	4
	SECTION 105.	Denominations	5
	SECTION 106.	Global Securities	5
	SECTION 107.	Transfer	6
	SECTION 108.	Redemption at the Company’s Option	7
	SECTION 109.	Information to Holders	8
	ARTICLE 2	MISCELLANEOUS PROVISIONS	8
	SECTION 201.	Recitals by Company	8
	SECTION 202.	Ratification and Incorporation of Original Indenture	8
	SECTION 203.	Executed in Counterparts	8
	SECTION 204.	Legends	9
EXHIBIT A Form of Series 2018A Note			A-1
EXHIBIT B Certificate of Authentication			B-1

_________________________

¹ This Table of Contents does not constitute part of the Indenture or have any bearing upon the interpretation of any of its terms and provisions.

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THIS TWENTIETH SUPPLEMENTAL INDENTURE is made as of the 17th day of August, 2018, by and between THE SOUTHERN COMPANY, a Delaware corporation, 30 Ivan Allen Jr. Blvd., N.W., Atlanta, Georgia 30308 (the “Company”), and Wells Fargo Bank, National Association, a national banking association, 150 East 42^nd Street, 40^th Floor, New York, New York 10017 (the “Trustee”).

W I T N E S S E T H:

WHEREAS, the Company has heretofore entered into a Senior Note Indenture, dated as of January 1, 2007 (the “Original Indenture”), with Wells Fargo Bank, National Association;

WHEREAS, the Original Indenture is incorporated herein by this reference and the Original Indenture, as heretofore supplemented and as further supplemented by this Twentieth Supplemental Indenture, is herein called the “Indenture”;

WHEREAS, under the Original Indenture, a new series of Senior Notes may at any time be established pursuant to a supplemental indenture executed by the Company and the Trustee;

WHEREAS, the Company proposes to create under the Indenture a new series of Senior Notes;

WHEREAS, additional Senior Notes of other series hereafter established, except as may be limited in the Original Indenture as at the time supplemented and modified, may be issued from time to time pursuant to the Indenture as at the time supplemented and modified; and

WHEREAS, all conditions necessary to authorize the execution and delivery of this Twentieth Supplemental Indenture and to make it a valid and binding obligation of the Company have been done or performed.

NOW, THEREFORE, in consideration of the agreements and obligations set forth herein and for other good and valuable consideration, the sufficiency of which is hereby acknowledged, the parties hereto hereby agree as follows:

ARTICLE 1

SERIES 2018A SENIOR NOTES

SECTION 101.    Establishment. There is hereby established a new series of Senior Notes to be issued under the Indenture, to be designated as the Company’s Series 2018A Floating Rate Senior Notes due February 14, 2020 (the “Series 2018A Notes”).

There are to be authenticated and delivered $750,000,000 principal amount of Series 2018A Notes, and such principal amount of the Series 2018A Notes may be increased from time to time pursuant to Section 301 of the Original Indenture. All Series 2018A Notes need not be issued at the same time and such series may be reopened at any time, without the consent of any Holder, for issuances of additional Series 2018A Notes. Any such additional Series 2018A Notes will have the same interest rate, maturity and other terms as those initially issued (except for the public offering price and issue date and the initial interest accrual date and initial Interest Payment Date (as defined

below), if applicable). No Series 2018A Notes shall be authenticated and delivered in excess of the principal amount as so increased except as provided by Sections 203, 303, 304, 907 or 1107 of the Original Indenture. The Series 2018A Notes shall be issued in fully registered form.

The Series 2018A Notes shall be issued in the form of one or more Global Securities in substantially the form set out in Exhibit A hereto. The Depositary with respect to the Series 2018A Notes shall be The Depository Trust Company.

The form of the Trustee’s Certificate of Authentication for the Series 2018A Notes shall be in substantially the form set forth in Exhibit B hereto.

Each Series 2018A Note shall be dated the date of authentication thereof and shall bear interest from the date of original issuance thereof or from the most recent Interest Payment Date to which interest has been paid or duly provided for.

SECTION 102.    Definitions. The following defined terms used herein shall, unless the context otherwise requires, have the meanings specified below. Capitalized terms used herein for which no definition is provided herein shall have the meanings set forth in the Original Indenture.

“1933 Act” has the meaning set forth in Section 106 of this Twentieth Supplemental Indenture.

“Calculation Agent” means Wells Fargo Bank, National Association, or its successor appointed by the Company, acting as calculation agent.

“Distribution Compliance Period” has the meaning set forth in Section 107 of this Twentieth Supplemental Indenture.

“Interest Determination Date” means the second London Business Day immediately preceding the first day of the relevant Interest Period.

“Interest Payment Dates” means the 14th day of February, May, August and November, commencing November 14, 2018; provided, however, in the event that any Interest Payment Date (other than the Interest Payment Date that is the Stated Maturity) would otherwise be a day that is not a Business Day, the Interest Payment Date will be the next succeeding Business Day.

“Interest Period” means the period commencing on an Interest Payment Date (or, with respect to the initial Interest Period only, commencing on the Original Issue Date) and ending on the day before the next succeeding Interest Payment Date.

“London Business Day” means a day that is a Business Day and a day on which dealings in deposits in U.S. dollars are transacted, or with respect to any future date are expected to be transacted, in the London interbank market.

“Original Issue Date” means August 17, 2018.

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“Regular Record Date” means, with respect to each Interest Payment Date, the 15^th calendar day preceding such Interest Payment Date (whether or not a Business Day).

“Regulation S Global Note” has the meaning set forth in Section 106 of this Twentieth Supplemental Indenture.

“Regulation S Legend” has the meaning set forth in Section 106 of this Twentieth Supplemental Indenture.

“Reuters LIBOR01 Page” means the display designated as Reuters LIBOR01 on the Reuters service (or such other page as may replace the Reuters LIBOR01 Page on that service, or such other service as may be nominated as the information vendor, for the purpose of displaying rates or prices comparable to the London interbank offered rate for U.S. dollar deposits).

“Rule 144A Global Note” has the meaning set forth in Section 106 of this Twentieth Supplemental Indenture.

“Rule 144A Legend” has the meaning set forth in Section 106 of this Twentieth Supplemental Indenture.

“Stated Maturity” means February 14, 2020; provided that if the Stated Maturity is not a Business Day, the principal and interest due on that date will be payable on the next succeeding Business Day, and no interest shall accrue for the intervening period; provided further that if such next succeeding Business Day is in the next succeeding calendar year, such payment will be made on the immediately preceding Business Day.

“Three-Month LIBOR” means, with respect to any Interest Period, the rate (expressed as a percentage per annum) for deposits in U.S. dollars having an index maturity of three months that appears on the Reuters LIBOR01 Page as of 11:00 a.m. (London time) on the Interest Determination Date for that Interest Period. If such rate does not appear on the Reuters LIBOR01 Page as of 11:00 a.m. (London time) on the Interest Determination Date for that Interest Period, Three-Month LIBOR will be determined on the basis of the rates at which deposits in U.S. dollars for the Interest Period and in a principal amount of not less than $1,000,000 are offered to prime banks in the London interbank market by four major banks in the London interbank market (which may include affiliates of one or more of the initial purchasers of the Series 2018A Notes) selected by the Company, at approximately 11:00 a.m., London time, on the Interest Determination Date for that Interest Period. The Calculation Agent will request the principal London office of each such bank to provide a quotation of its rate. If at least two such quotations are provided, Three-Month LIBOR with respect to that Interest Period will be the arithmetic mean of such quotations. If fewer than two quotations are provided, Three-Month LIBOR with respect to that Interest Period will be the arithmetic mean of the rates quoted by three major banks in New York City (which may include affiliates of one or more of the initial purchasers of the Series 2018A Notes) selected by the Company, at approximately

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11:00 a.m., New York City time, on the Interest Determination Date for that Interest Period for loans in U.S. dollars to leading European banks for that Interest Period and in a principal amount of not less than $1,000,000. However, if fewer than three banks selected by the Company to provide quotations are quoting as described above, Three-Month LIBOR for that Interest Period will be the same as Three-Month LIBOR as determined for the previous Interest Period.

SECTION 103.    Payment of Principal and Interest. The principal of the Series 2018A Notes shall be due at Stated Maturity (unless earlier redeemed). The unpaid principal amount of the Series 2018A Notes shall bear interest at the rates set quarterly pursuant to Section 104 hereof until paid or duly provided for. Interest shall be paid quarterly in arrears on each Interest Payment Date to the Person in whose name the Series 2018A Notes are registered at the close of business on the Regular Record Date for such Interest Payment Date, provided that interest payable at the Stated Maturity or on a Redemption Date as provided herein will be paid to the Person to whom principal is payable. Any such interest that is not so punctually paid or duly provided for will forthwith cease to be payable to the Holders on such Regular Record Date and may either be paid to the Person or Persons in whose name the Series 2018A Notes are registered at the close of business on a Special Record Date for the payment of such defaulted interest to be fixed by the Trustee, notice whereof shall be given to Holders of the Series 2018A Notes not less than ten (10) days prior to such Special Record Date, or be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange, if any, on which the Series 2018A Notes shall be listed, and upon such notice as may be required by any such exchange, all as more fully provided in the Original Indenture.

Payments of interest on the Series 2018A Notes will include interest accrued to but excluding the respective Interest Payment Dates. Interest payments for the Series 2018A Notes shall be computed and paid on the basis of the actual number of days elapsed over a 360-day year.

Payment of the principal and interest due at the Stated Maturity or earlier redemption of the Series 2018A Notes shall be made upon surrender of the Series 2018A Notes at the Corporate Trust Office of the Trustee. The principal of and interest on the Series 2018A Notes shall be paid in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts. Payments of interest (including interest on any Interest Payment Date) will be made, subject to such surrender where applicable, at the option of the Company, (i) by check mailed to the address of the Person entitled thereto as such address shall appear in the Security Register or (ii) by wire transfer or other electronic transfer at such place and to such account at a banking institution in the United States as may be designated in writing to the Trustee at least sixteen (16) days prior to the date for payment by the Person entitled thereto.

SECTION 104.    Determination of Interest. The Series 2018A Notes will bear interest for each Interest Period at a per annum rate determined by the Calculation Agent, subject to the maximum interest rate permitted by New York or other applicable state law, as such law may be modified by United States law of general application. The interest rate applicable during each Interest Period will be equal to Three-Month LIBOR on the Interest Determination Date for such Interest Period plus 0.49%; provided, that in no event shall the applicable interest rate be less than 0% for any Interest Period. Promptly upon such determination, the Calculation Agent will notify the Company and the Trustee, if the Trustee is not then serving as the Calculation Agent, of the interest rate for the new Interest Period. The interest rate determined by the Calculation Agent, absent

4

manifest error, shall be binding and conclusive upon the beneficial owners and Holders of the Series 2018A Notes, the Company and the Trustee.

Upon the request of a Holder of the Series 2018A Notes, the Calculation Agent will provide to such Holder the interest rate in effect on the date of such request and, if determined, the interest rate for the next Interest Period.

SECTION 105.    Denominations. The Series 2018A Notes may be issued in denominations of $2,000 and integral multiples of $1,000 in excess thereof.

SECTION 106.    Global Securities. The Series 2018A Notes will be issued in the form of one or more Global Securities registered in the name of the Depositary (which shall be The Depository Trust Company) or its nominee. The Series 2018A Notes will be initially issued pursuant to an exemption or exemptions from the registration requirements of the Securities Act of 1933, as amended (the “1933 Act”). Beneficial interests in the Series 2018A Notes offered and sold to “qualified institutional buyers” (as defined in Rule 144A under the 1933 Act) in reliance upon Rule 144A under the 1933 Act shall be represented by one or more separate Global Securities (each, a “Rule 144A Global Note”). Each Rule 144A Global Note shall bear the Rule 144A legend in substantially the form set forth in Exhibit A hereto (the “Rule 144A Legend”). Beneficial interests in the Series 2018A Notes offered and sold to purchasers outside of the United States pursuant to Regulation S under the 1933 Act shall be represented by one or more separate Global Securities (each, a “Regulation S Global Note”) and shall bear the Regulation S legend in substantially the form set forth in Exhibit A hereto (the “Regulation S Legend”).

Except under the limited circumstances described below, Series 2018A Notes represented by one or more Global Securities will not be exchangeable for, and will not otherwise be issuable as, Series 2018A Notes in definitive form. The Global Securities described above may not be transferred except by the Depositary to a nominee of the Depositary or by a nominee of the Depositary to the Depositary or another nominee of the Depositary or to a successor Depositary or its nominee.

Owners of beneficial interests in such a Global Security will not be considered the Holders thereof for any purpose under the Indenture, and no Global Security representing a Series 2018A Note shall be exchangeable, except for another Global Security of like denomination and tenor to be registered in the name of the Depositary or its nominee or to a successor Depositary or its nominee. The rights of Holders of such Global Security shall be exercised only through the Depositary.

Subject to the procedures of the Depositary, a Global Security shall be exchangeable for Series 2018A Notes registered in the names of persons other than the Depositary or its nominee only if (i) the Depositary notifies the Company that it is unwilling or unable to continue as a Depositary for such Global Security and no successor Depositary shall have been appointed by the Company, or if at any time the Depositary ceases to be a clearing agency registered under the Securities Exchange Act of 1934, as amended, at a time when the Depositary is required to be so registered to act as such Depositary and no successor Depositary shall have been appointed by the Company, in each case within 90 days after the Company receives such notice or becomes aware of such cessation, (ii) the Company in its sole discretion determines that such Global Security shall be so exchangeable, or (iii) there shall have occurred an Event of Default with respect to the Series 2018A Notes. Any Global Security that is exchangeable pursuant to the preceding sentence shall be exchangeable for Series 2018A Notes registered in such names as the Depositary shall direct.

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Neither the Company, the Trustee nor any agent of the Company or the Trustee shall have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests in a Global Security or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests.

SECTION 107.    Transfer. A Rule 144A Global Note may not be transferred on the Security Register except in compliance with the restrictions on transfer contained in the Rule 144A Legend and upon receipt by the Security Registrar of a completed and executed Transfer Certificate in the form contained in Exhibit A hereto. Prior to the expiration of 40 days beginning on and including the later of (i) the day on which the offering of the Series 2018A Notes commences and (ii) the Original Issue Date (the “Distribution Compliance Period”), a Regulation S Global Note may not be transferred on the Security Register except in compliance with the restrictions on transfer contained in the Regulation S Legend and upon receipt by the Security Registrar of a completed and executed Transfer Certificate in the form contained in Exhibit A hereto. No service charge will be made for any transfer or exchange of Series 2018A Notes, but payment will be required of a sum sufficient to cover any tax or other governmental charge that may be imposed in connection therewith.

The transfer and exchange of beneficial interests in the Global Securities shall be effected through the Depositary, in accordance with this Twentieth Supplemental Indenture (including applicable restrictions on transfer set forth herein, if any) and the procedures of the Depositary therefor.

Until the expiration of the Distribution Compliance Period, transfers by an owner of a beneficial interest in a Regulation S Global Note to a transferee who takes delivery of such interest through a Rule 144A Global Note will be made only upon receipt by the Trustee of a completed and executed Transfer Certificate in the form contained in Exhibit A hereto from the transferor of the beneficial interest to the effect that such transfer is being made to a person whom the transferor reasonably believes is a qualified institutional buyer (as defined in Rule 144A under the Securities Act) in a transaction meeting the requirements of Rule 144A and the requirements of applicable securities laws of any state of the United States or any other jurisdiction.

Transfers by an owner of a beneficial interest in the Rule 144A Global Note to a transferee who takes delivery through the Regulation S Global Note, whether before or after the expiration of the Distribution Compliance Period, will be made only upon receipt by the Trustee of a Transfer Certificate in the form contained in Exhibit A hereto from the transferor to the effect that such transfer is being made in accordance with Regulation S or Rule 144 under the Securities Act and that, if such transfer is being made prior to the expiration of the Distribution Compliance Period, the interest transferred will be held immediately thereafter through Euroclear Bank S.A./N.V., as operator of the Euroclear System or Clearstream Banking, société anonyme, Luxembourg.

Any beneficial interest in one of the Global Securities that is transferred to a person who takes delivery in the form of an interest in another Global Security will, upon transfer, cease to be an interest in the initial Global Security and will become an interest in the other Global Security and, accordingly, will thereafter be subject to all transfer restrictions, if any, and other procedures applicable to beneficial interests in such other Global Security for as long as it remains such an interest.

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Transfers of beneficial interests between a Rule 144A Global Note and a Regulation S Global Note, and other transfers relating to beneficial interests in the Global Securities, shall be reflected by endorsements of the Trustee, as custodian for The Depository Trust Company, on the schedules attached to such Rule 144A Global Note and Regulation S Global Note.

Neither the Trustee, the Security Registrar nor any transfer agent shall have any obligation or duty to monitor, determine or inquire as to compliance with any restrictions on transfer imposed under the Indenture or under applicable law with respect to any transfer of any interest in any Series 2018A Note (including any transfers between or among Depositary participants, members or beneficial owners in any Global Security) other than to require delivery of such certificates and other documentation or evidence as are expressly required by, and to do so if and when expressly required by, the terms of the Indenture, and to examine the same to determine substantial compliance as to form with the express requirements hereof.

Neither the Company nor the Trustee shall have any liability for acts or omissions of the Depositary, for the Depositary records of beneficial interest, for any transactions between the Depositary, any participant member of the Depositary and/or beneficial owner of any interest in any Series 2018A Notes, or in respect of any transfers effected by the Depositary or by any participant member of the Depositary or any beneficial owner of any interest in any Series 2018A Notes held through any such participant member of the Depositary.

The Company shall not be required (a) to issue, register the transfer of or exchange any Series 2018A Notes during a period beginning at the opening of business fifteen (15) days before the date of the mailing of a notice pursuant to Section 1104 of the Original Indenture identifying the serial numbers of the Series 2018A Notes to be called for redemption, and ending at the close of business on the date of the mailing, or (b) to register the transfer of or exchange any Series 2018A Notes theretofore selected for redemption in whole or in part, except the unredeemed portion of any Series 2018A Notes redeemed in part.

SECTION 108.    Redemption at the Company’s Option. At any time and from time to time on or after February 14, 2019, the Series 2018A Notes will be subject to redemption at the option of the Company in whole or in part upon not less than 15 nor more than 60 days’ notice, at a redemption price equal to 100% of the principal amount of the Series 2018A Notes being redeemed plus accrued and unpaid interest on the Series 2018A Notes being redeemed to the Redemption Date.

If the Redemption Date is not a Business Day, the principal and interest due on that date will be payable on the next succeeding Business Day, and no interest shall accrue for the intervening period; provided, however, that if such next succeeding Business Day is in the next succeeding calendar year, such payment will be made on the immediately preceding Business Day.

In the event of redemption of the Series 2018A Notes in part only, a new Series 2018A Note or Notes for the unredeemed portion will be issued in the name or names of the Holders thereof upon the surrender thereof.

The Series 2018A Notes will not have a sinking fund.

Except as otherwise provided herein, notice of redemption shall be given as provided in Section 1104 of the Original Indenture.

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Any redemption of less than all of the Series 2018A Notes shall, with respect to the principal thereof, be divisible by $1,000.

SECTION 109.    Information to Holders. Upon the request of any Holder, any holder of a beneficial interest in the Series 2018A Notes, or the Trustee (on behalf of a Holder or a holder of a beneficial interest in the Series 2018A Notes), the Company will furnish such information as is specified in paragraph (d)(4) of Rule 144A promulgated under the 1933 Act to Holders (and to holders of beneficial interests in the Series 2018A Notes), to prospective purchasers of the Series 2018A Notes (and of beneficial interests in the Series 2018A Notes) who are qualified institutional buyers or to the Trustee for delivery to such Holder or prospective purchasers of the Series 2018A Notes or beneficial interests therein, as the case may be, unless, at the time of such request, the Company is subject to the reporting requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended.

Delivery of information to the Trustee pursuant to this Section 109 is for informational purposes only and the Trustee’s receipt of such shall not constitute constructive notice of any information contained therein or determinable from information contained therein, including the Company’s compliance with any of its covenants under the Indenture.

ARTICLE 2

MISCELLANEOUS PROVISIONS

SECTION 201.    Recitals by Company. The recitals in this Twentieth Supplemental Indenture are made by the Company only and not by the Trustee, and all of the provisions contained in the Original Indenture in respect of the rights, privileges, immunities, powers and duties of the Trustee shall be applicable in respect of Series 2018A Notes and of this Twentieth Supplemental Indenture as fully and with like effect as if set forth herein in full.

SECTION 202.    Ratification and Incorporation of Original Indenture. As supplemented hereby, the Original Indenture is in all respects ratified and confirmed, and the Original Indenture as supplemented by this Twentieth Supplemental Indenture shall be read, taken and construed as one and the same instrument.

SECTION 203.    Executed in Counterparts. This Twentieth Supplemental Indenture may be simultaneously executed in several counterparts, each of which shall be deemed to be an original, and such counterparts shall together constitute but one and the same instrument.

SECTION 204.    Legends. Except as determined by the Company in accordance with applicable law, each Series 2018A Note shall bear the applicable legends relating to restrictions on transfer pursuant to the securities laws in substantially the form set forth on Exhibit A hereto.

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IN WITNESS WHEREOF, each party hereto has caused this instrument to be signed in its name and behalf by its duly authorized officer, all as of the day and year first above written.

THE SOUTHERN COMPANY
By:	/s/Andrew W. Evans
	Andrew W. Evans Executive Vice President and Chief Financial Officer
WELLS FARGO BANK, NATIONAL ASSOCIATION, as Trustee
By:	/s/Stefan Victory
	Stefan Victory Vice President

EXHIBIT A

FORM OF SERIES 2018A NOTE

[RULE 144A LEGEND FOR USE WITH RULE 144A GLOBAL NOTES]

NEITHER THIS NOTE NOR ANY BENEFICIAL INTEREST HEREIN HAS BEEN REGISTERED UNDER THE UNITED STATES SECURITIES ACT OF 1933, AS AMENDED (THE “1933 ACT”). EACH HOLDER HEREOF, AND EACH OWNER OF A BENEFICIAL INTEREST HEREIN, BY PURCHASING THIS NOTE, AGREES FOR THE BENEFIT OF THE SOUTHERN COMPANY (THE “COMPANY”) THAT THIS NOTE MAY NOT BE RESOLD, PLEDGED OR OTHERWISE TRANSFERRED PRIOR TO THE DATE WHICH IS SIX MONTHS (IF ALL APPLICABLE CONDITIONS TO SUCH RESALE UNDER RULE 144 UNDER THE 1933 ACT (OR ANY SUCCESSOR PROVISION THEREOF) ARE SATISFIED) AFTER THE LATER OF THE ORIGINAL ISSUANCE DATE THEREOF, THE ISSUANCE DATE OF ANY SUBSEQUENT ISSUANCE OF ADDITIONAL NOTES OF THE SAME SERIES AND THE LAST DATE ON WHICH THE COMPANY OR ANY AFFILIATE THEREOF WAS THE OWNER OF THIS NOTE OR THE EXPIRATION OF SUCH SHORTER PERIOD AS MAY BE PRESCRIBED BY SUCH RULE 144 (OR SUCH SUCCESSOR PROVISION) PERMITTING RESALES OF THIS NOTE WITHOUT ANY CONDITIONS (THE “RESALE RESTRICTION TERMINATION DATE”) OTHER THAN (A)(1) TO THE COMPANY, (2) IN A TRANSACTION ENTITLED TO AN EXEMPTION FROM REGISTRATION PROVIDED BY RULE 144 UNDER THE 1933 ACT (IF AVAILABLE), (3) SO LONG AS THIS NOTE IS ELIGIBLE FOR RESALE PURSUANT TO RULE 144A UNDER THE 1933 ACT (“RULE 144A”), TO A PERSON WHOM THE SELLER REASONABLY BELIEVES IS A QUALIFIED INSTITUTIONAL BUYER WITHIN THE MEANING OF RULE 144A PURCHASING FOR ITS OWN ACCOUNT OR FOR THE ACCOUNT OF A QUALIFIED INSTITUTIONAL BUYER TO WHOM NOTICE IS GIVEN THAT THE RESALE, PLEDGE OR OTHER TRANSFER IS BEING MADE IN RELIANCE ON RULE 144A UNDER THE 1933 ACT (AS INDICATED BY THE BOX CHECKED BY THE TRANSFEROR ON THE CERTIFICATE OF TRANSFER ATTACHED TO THIS NOTE), (4) IN AN OFFSHORE TRANSACTION IN ACCORDANCE WITH RULE 903 OR 904 OF REGULATION S UNDER THE 1933 ACT (AS INDICATED BY THE BOX CHECKED BY THE TRANSFEROR ON THE CERTIFICATE OF TRANSFER ATTACHED TO THIS NOTE), (5) IN ACCORDANCE WITH ANOTHER APPLICABLE EXEMPTION FROM THE REGISTRATION REQUIREMENTS OF THE 1933 ACT (AND BASED UPON AN OPINION OF COUNSEL ACCEPTABLE TO THE COMPANY), OR (6) PURSUANT TO AN EFFECTIVE REGISTRATION STATEMENT UNDER THE 1933 ACT AND (B) IN EACH CASE IN ACCORDANCE WITH ANY APPLICABLE SECURITIES LAWS OF ANY STATE OF THE UNITED STATES. THE FOREGOING RESTRICTIONS ON RESALE WILL NOT APPLY SUBSEQUENT TO THE RESALE RESTRICTION TERMINATION DATE. THE HOLDER HEREOF, BY PURCHASING THIS NOTE, REPRESENTS AND AGREES FOR THE BENEFIT OF THE COMPANY THAT IT IS (i) A QUALIFIED INSTITUTIONAL BUYER WITHIN THE MEANING OF RULE 144A UNDER THE 1933 ACT OR (ii) A NON-U.S. PERSON OUTSIDE THE UNITED STATES WITHIN THE MEANING OF, OR AN ACCOUNT SATISFYING THE

REQUIREMENTS OF, PARAGRAPH (k)(2) OF RULE 902 UNDER REGULATION S UNDER THE 1933 ACT. THE HOLDER OF THIS NOTE ACKNOWLEDGES THAT THE COMPANY OR THE TRUSTEE RESERVES THE RIGHT PRIOR TO ANY OFFER, SALE OR OTHER TRANSFER (1) PURSUANT TO CLAUSE (A)(2) PRIOR TO THE RESALE RESTRICTION TERMINATION DATE TO REQUIRE THE DELIVERY OF AN OPINION OF COUNSEL, CERTIFICATIONS OR OTHER INFORMATION SATISFACTORY TO THE COMPANY AND THE TRUSTEE AND (2) IN EACH OF THE FOREGOING CASES, TO REQUIRE THAT A CERTIFICATE AS TO COMPLIANCE WITH CERTAIN CONDITIONS TO TRANSFER IS COMPLETED AND DELIVERED BY THE TRANSFEROR TO THE COMPANY AND THE TRUSTEE.

[REGULATION S LEGEND FOR USE WITH REGULATION S GLOBAL NOTES]

THE SECURITIES COVERED HEREBY HAVE NOT BEEN REGISTERED UNDER THE UNITED STATES SECURITIES ACT OF 1933, AS AMENDED (THE “1933 ACT”), AND MAY NOT BE OFFERED OR SOLD WITHIN THE UNITED STATES OR TO, OR FOR THE ACCOUNT OR BENEFIT OF, U.S. PERSONS (I) AS PART OF THEIR DISTRIBUTION AT ANY TIME OR (II) OTHERWISE UNTIL 40 DAYS AFTER THE LATER OF THE DATE OF THE COMMENCEMENT OF THE OFFERING OF THE SECURITIES AND THE DATE OF ORIGINAL ISSUANCE OF THE SECURITIES, EXCEPT IN EITHER CASE IN ACCORDANCE WITH REGULATION S OR RULE 144A UNDER THE 1933 ACT OR ANY OTHER AVAILABLE EXEMPTION FROM REGISTRATION UNDER THE 1933 ACT. TERMS USED ABOVE HAVE THE MEANINGS GIVEN TO THEM BY REGULATION S.

NO. _______ CUSIP NO. ___________________

THE SOUTHERN COMPANY

SERIES 2018A FLOATING RATE SENIOR NOTE

DUE FEBRUARY 14, 2020

Initial Principal Amount:	$______________
Regular Record Date:	15th calendar day prior to the applicable Interest Payment Date (whether or not a Business Day)
Original Issue Date:	August 17, 2018
Stated Maturity:	February 14, 2020; provided that if the Stated Maturity is not a Business Day, the principal and interest due on that date will be payable on the next succeeding Business Day, and no interest shall accrue for the intervening period; provided further that if such next succeeding Business Day is in the next succeeding calendar year, such payment will be made on the immediately preceding Business Day.
Interest Payment Dates:	14th day of February, May, August and November; provided, however, in the event that any Interest Payment Date (other than the Interest Payment Date that is the Stated Maturity) would otherwise be a day that is not a Business Day, the Interest Payment Date will be the next succeeding Business Day
Interest Rate:	Three-Month LIBOR plus 0.49% per annum, as set on each Interest Determination Date
Authorized Denominations:	$2,000 or any integral multiple of $1,000 in excess thereof

The Southern Company, a Delaware corporation (the “Company,” which term includes any successor corporation under the Indenture referred to on the reverse hereof), for value received, hereby promises to pay to _____________________________________, or registered assigns, the principal sum of ________________________________ DOLLARS ($__________), or such other amount as indicated on the Schedule of Increases or Decreases in Global Security attached hereto as Schedule I, on the Stated Maturity shown above (or upon earlier redemption), and to pay interest

A-1

thereon from the Original Issue Date shown above, or from the most recent Interest Payment Date to which interest has been paid or duly provided for, quarterly in arrears on each Interest Payment Date as specified above, commencing on November 14, 2018 and on the Stated Maturity (or upon earlier redemption) at the rates per annum determined in accordance with the provisions specified below until the principal hereof is paid or made available for payment and at such rates on any overdue principal and on any overdue installment of interest. The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date (other than an Interest Payment Date that is the Stated Maturity or on a Redemption Date) will, as provided in such Indenture, be paid to the Person in whose name this Note (the “Note”) is registered at the close of business on the Regular Record Date as specified above next preceding such Interest Payment Date, provided that any interest payable at the Stated Maturity or on any Redemption Date will be paid to the Person to whom principal is payable. Except as otherwise provided in the Indenture, any such interest not so punctually paid or duly provided for will forthwith cease to be payable to the Holder on such Regular Record Date and may either be paid to the Person in whose name this Note is registered at the close of business on a Special Record Date for the payment of such defaulted interest to be fixed by the Trustee, notice whereof shall be given to Holders of Notes of this series not less than 10 days prior to such Special Record Date, or be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange, if any, on which the Notes of this series shall be listed, and upon such notice as may be required by any such exchange, all as more fully provided in the Indenture.

The Series 2018A Notes (as defined on the reverse hereof) will bear interest for each Interest Period at a per annum rate determined by the Calculation Agent, subject to the maximum interest rate permitted by New York or other applicable state law, as such law may be modified by United States law of general application. The interest rate applicable during each Interest Period will be equal to Three-Month LIBOR on the Interest Determination Date for such Interest Period plus 0.49%; provided, that in no event shall the applicable interest rate be less than 0% for any Interest Period. Promptly upon such determination, the Calculation Agent will notify the Company and the Trustee, if the Trustee is not then serving as the Calculation Agent, of the interest rate for the new Interest Period. The interest rate determined by the Calculation Agent, absent manifest error, shall be binding and conclusive upon the beneficial owners and Holders of the Series 2018A Notes, the Company and the Trustee.

“Calculation Agent” means Wells Fargo Bank, National Association, or its successor appointed by the Company, acting as calculation agent.

“Interest Determination Date” means the second London Business Day immediately preceding the first day of the relevant Interest Period.

“Interest Period” means the period commencing on an Interest Payment Date (or, with respect to the initial Interest Period only, commencing on the Original Issue Date) and ending on the day before the next succeeding Interest Payment Date.

“Three-Month LIBOR” means, with respect to any Interest Period, the rate (expressed as a percentage per annum) for deposits in U.S. dollars having an index maturity of three months that appears on the Reuters LIBOR01 Page as of 11:00 a.m. (London time) on the Interest Determination

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Date for that Interest Period. If such rate does not appear on the Reuters LIBOR01 Page as of 11:00 a.m. (London time) on the Interest Determination Date for that Interest Period, Three-Month LIBOR will be determined on the basis of the rates at which deposits in U.S. dollars for the Interest Period and in a principal amount of not less than $1,000,000 are offered to prime banks in the London interbank market by four major banks in the London interbank market (which may include affiliates of one or more of the initial purchasers of the Series 2018A Notes) selected by the Company, at approximately 11:00 a.m., London time, on the Interest Determination Date for that Interest Period. The Calculation Agent will request the principal London office of each such bank to provide a quotation of its rate. If at least two such quotations are provided, Three-Month LIBOR with respect to that Interest Period will be the arithmetic mean of such quotations. If fewer than two quotations are provided, Three-Month LIBOR with respect to that Interest Period will be the arithmetic mean of the rates quoted by three major banks in New York City (which may include affiliates of one or more of the initial purchasers of the Series 2018A Notes) selected by the Company, at approximately 11:00 a.m., New York City time, on the Interest Determination Date for that Interest Period for loans in U.S. dollars to leading European banks for that Interest Period and in a principal amount of not less than $1,000,000. However, if fewer than three banks selected by the Company provide quotations are quoting as described above, Three-Month LIBOR for that Interest Period will be the same as Three-Month LIBOR as determined for the previous Interest Period.

“London Business Day” means a day that is a Business Day and a day on which dealings in deposits in U.S. dollars are transacted, or with respect to any future date are expected to be transacted, in the London interbank market.

“Reuters LIBOR01 Page” means the display designated as Reuters LIBOR01 on the Reuters service (or such other page as may replace the Reuters LIBOR01 Page on that service, or such other service as may be nominated as the information vendor, for the purpose of displaying rates or prices comparable to the London interbank offered rate for U.S. dollar deposits).

Payments of interest on this Note will include interest accrued to but excluding the respective Interest Payment Dates. Interest payments for this Note shall be computed and paid on the basis of the actual number of days elapsed over a 360-day year. A “Business Day” shall mean a day other than (i) a Saturday or a Sunday, (ii) a day on which banks in New York, New York are authorized or obligated by law or executive order to remain closed, or (iii) a day on which the Trustee’s Corporate Trust Office is closed for business.

Payment of the principal of and interest due at the Stated Maturity or earlier redemption of the Series 2018A Notes shall be made upon surrender of the Series 2018A Notes at the Corporate Trust Office of the Trustee. The principal of and interest on the Series 2018A Notes shall be paid in such coin or currency of the United States of America as at the time of payment is legal tender for payment of public and private debts. Payment of interest (including interest on an Interest Payment Date) will be made, subject to such surrender where applicable, at the option of the Company, (i) by check mailed to the address of the Person entitled thereto as such address shall appear in the Security Register or (ii) by wire transfer or other electronic transfer at such place and to such account at a banking institution in the United States as may be designated in writing to the Trustee at least 16 days prior to the date for payment by the Person entitled thereto.

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REFERENCE IS HEREBY MADE TO THE FURTHER PROVISIONS OF THIS NOTE SET FORTH ON THE REVERSE HEREOF, WHICH FURTHER PROVISIONS SHALL FOR ALL PURPOSES HAVE THE SAME EFFECT AS IF SET FORTH AT THIS PLACE.

Unless the certificate of authentication hereon has been executed by the Trustee by manual signature, this Note shall not be entitled to any benefit under the Indenture or be valid or obligatory for any purpose.

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IN WITNESS WHEREOF, the Company has caused this instrument to be duly executed under its corporate seal.

Dated:

	THE SOUTHERN COMPANY
	By:
	Title:
Attest:
Title:

{Seal of THE SOUTHERN COMPANY appears here}

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CERTIFICATE OF AUTHENTICATION

This is one of the Senior Notes referred to in the within-mentioned Indenture.

WELLS FARGO BANK, NATIONAL ASSOCIATION, as Trustee
By:
	Authorized Signatory

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(Reverse Side of Note)

This Note is one of a duly authorized issue of Senior Notes of the Company (the “Notes”), issued and issuable in one or more series under a Senior Note Indenture (the “Original Indenture”), dated as of January 1, 2007, as supplemented, including by a Twentieth Supplemental Indenture dated as of August 17, 2018 (the “Indenture”), between the Company and Wells Fargo Bank, National Association, Trustee (the “Trustee,” which term includes any successor trustee under the Indenture), to which Indenture and all indentures incidental thereto reference is hereby made for a statement of the respective rights, limitation of rights, duties and immunities thereunder of the Company, the Trustee and the Holders of the Notes issued thereunder and of the terms upon which said Notes are, and are to be, authenticated and delivered. This Note is one of the series designated on the face hereof as Series 2018A Floating Rate Senior Notes due February 14, 2020 (the “Series 2018A Notes”) which is unlimited in aggregate principal amount. Capitalized terms used herein for which no definition is provided herein shall have the meanings set forth in the Indenture.

At any time and from time to time on or after February 14, 2019, the Series 2018A Notes will be subject to redemption at the option of the Company in whole or in part upon not less than 15 nor more than 60 days’ notice, at a redemption price equal to 100% of the principal amount of the Series 2018A Notes being redeemed plus accrued and unpaid interest on the Series 2018A Notes being redeemed to the Redemption Date.

If the Redemption Date is not a Business Day, the principal and interest due on that date will be payable on the next succeeding Business Day, and no interest shall accrue for the intervening period; provided, however, that if such next succeeding Business Day is in the next succeeding calendar year, such payment will be made on the immediately preceding Business Day.

In the event of redemption of this Note in part only, a new Note or Notes of this series for the unredeemed portion hereof will be issued in the name of the Holder hereof upon the surrender hereof. The Series 2018A Notes will not have a sinking fund.

If an Event of Default with respect to the Notes of this series shall occur and be continuing, the principal of the Notes of this series may be declared due and payable in the manner, with the effect and subject to the conditions provided in the Indenture.

The Indenture permits, with certain exceptions as therein provided, the amendment thereof and the modification of the rights and obligations of the Company and the rights of the Holders of the Notes of each series to be affected under the Indenture at any time by the Company and the Trustee with the consent of the Holders of not less than a majority in principal amount of the Notes at the time Outstanding of each series to be affected. The Indenture also contains provisions permitting the Holders of specified percentages in principal amount of the Notes of each series at the time Outstanding, on behalf of the Holders of all Notes of such series, to waive compliance by the Company with certain provisions of the Indenture and certain past defaults under the Indenture and their consequences. Any such consent or waiver by the Holder of this Note shall be conclusive and binding upon such Holder and upon all future Holders of this Note and of any Note issued upon

A-7

the registration of transfer hereof or in exchange hereof or in lieu hereof, whether or not notation of such consent or waiver is made upon this Note.

No reference herein to the Indenture and no provision of this Note or of the Indenture shall alter or impair the obligation of the Company, which is absolute and unconditional, to pay the principal of and interest on this Note at the times, place and rates, and in the coin or currency, herein prescribed.

As provided in the Indenture and subject to certain limitations therein set forth, the transfer of this Note is registrable in the Security Register, upon surrender of this Note for registration of transfer at the office or agency of the Company for such purpose, duly endorsed by, or accompanied by a written instrument of transfer in form satisfactory to the Company and the Security Registrar and duly executed by, the Holder hereof or his attorney duly authorized in writing, together with the completed and executed Transfer Certificate attached hereto (as applicable), and thereupon one or more new Notes of this series, of authorized denominations and of like tenor and for the same aggregate principal amount, will be issued to the designated transferee or transferees. No service charge shall be made for any such registration of transfer or exchange, but the Company may require payment of a sum sufficient to cover any tax or other governmental charge payable in connection therewith.

Prior to due presentment of this Note for registration of transfer, the Company, the Trustee and any agent of the Company or the Trustee may treat the Person in whose name this Note is registered as the owner hereof for all purposes, whether or not this Note be overdue, and neither the Company, the Trustee nor any such agent shall be affected by notice to the contrary.

The Notes of this series are issuable only in registered form without coupons in denominations of $2,000 and any integral multiple of $1,000 in excess thereof. As provided in the Indenture and subject to certain limitations therein set forth, Notes of this series are exchangeable for a like aggregate principal amount of Notes of this series of a different authorized denomination, as requested by the Holder surrendering the same upon surrender of the Note or Notes to be exchanged at the office or agency of the Company.

This Note shall be governed by, and construed in accordance with, the internal laws of the State of New York.

A-8

ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this instrument, shall be construed as though they were written out in full according to applicable laws or regulations:

TEN COM-  as tenants in common	UNIF GIFT MIN ACT- _______ Custodian ________                                          (Cust)                     (Minor)
TEN ENT-   as tenants by the entireties
JT TEN-       as joint tenants with right of survivorship and not as tenants in common	under Uniform Gifts to Minors Act ___________________             (State)

Additional abbreviations may also be used

though not on the above list.

FOR VALUE RECEIVED, the undersigned hereby sell(s) and transfer(s) unto

_____________________________________________________________________________

(please insert Social Security or other identifying number of assignee)

_____________________________________________________________________________

PLEASE PRINT OR TYPEWRITE NAME AND ADDRESS, INCLUDING POSTAL ZIP CODE OF ASSIGNEE

_____________________________________________________________________________

_____________________________________________________________________________

the within Note and all rights thereunder, hereby irrevocably constituting and appointing

_____________________________________________________________________________

_____________________________________________________________________________

agent to transfer said Note on the books of the Company, with full power of substitution in the premises.

Dated:

NOTICE: The signature to this assignment must correspond with the name as written upon the face of the within instrument in every particular without alteration or enlargement, or any change whatever.

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TRANSFER CERTIFICATE

In connection with any transfer of any of the Series 2018A Notes evidenced by this certificate [prior to the expiration of the Distribution Compliance Period]², the undersigned confirms that such Series 2018A Notes are being:

CHECK ONE BOX BELOW

(1)	¨	exchanged for the undersigned’s own account without transfer; or
(2)	¨	transferred to the Company; or
(3)	¨	transferred to a person whom the undersigned reasonably believes is a “qualified institutional buyer” within the meaning of Rule 144A under the Securities Act of 1933, as amended (the “1933 Act”), purchasing for its own account or for the account of a “qualified institutional buyer” to whom notice is given that the resale, pledge or other transfer is being made in reliance on Rule 144A under the 1933 Act; or
(4)	¨	transferred pursuant to an exemption under Rule 144 under the 1933 Act; or
(5)	¨	transferred in an offshore transaction in accordance with Rule 903 or Rule 904 of Regulation S under the 1933 Act; or
(6)	¨	transferred pursuant to another available exemption from the registration requirements of the 1933 Act; or
(7)	¨	transferred pursuant to an effective registration statement under the 1933 Act.

Unless one of the boxes is checked, the Trustee will refuse to register any of the Series 2018A Notes evidenced by this certificate in the name of any person other than the registered Holder thereof; provided, however, that if box (4) or (6) is checked, the Company may require, prior to registering any such transfer of the Series 2018A Notes, such legal opinions, certifications and other information as the Company has reasonably requested to confirm that such transfer is being made pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the 1933 Act, such as the exemption provided by Rule 144 under the 1933 Act; provided, further, that if box (3) is checked, the transferee must certify that it is a qualified institutional buyer as defined in Rule 144A.

Date: _____________________

__________________________________________

Signature

__________________________________________

Tax Identification Number

____________________

²[To be included for Regulation S Global Notes only.]

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TO BE COMPLETED BY PURCHASER IF (3) ABOVE IS CHECKED.

The undersigned represents and warrants that it is purchasing this Series 2018A Note for its own account or an account with respect to which it exercises sole investment discretion and that it and any such account is a “qualified institutional buyer” within the meaning of Rule 144A under the 1933 Act, and is aware that the sale to it is being made in reliance on Rule 144A and acknowledges that it has received such information regarding the Company as the undersigned has requested pursuant to Rule 144A or has determined not to request such information and that it is aware that the transferor is relying upon the undersigned’s foregoing representations in order to claim the exemption from registration provided by Rule 144A.

Date: _______________________

____________________________

Signature

NOTICE: If an entity, to be executed by an executive officer.

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SCHEDULE I TO GLOBAL SECURITY

The initial amount of the Global Securities evidenced by this certificate is $_______________.

SCHEDULE OF INCREASES OR DECREASES IN GLOBAL SECURITY

The following increases or decreases in this Global Security have been made

Date Amount of increase in Principal Amount of this Global Security Amount of decrease in Principal Amount of this Global Security Principal Amount of this Global Security following each decrease or increase Signature of authorized signatory of Trustee or Securities Registrar

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EXHIBIT B

CERTIFICATE OF AUTHENTICATION

This is one of the Senior Notes referred to in the within-mentioned Indenture.

WELLS FARGO BANK, NATIONAL ASSOCIATION, as Trustee
By:
	Authorized Signatory

B-1

EX-4.G1

Exhibit 4(g)1

When recorded return to:
David Hight, Esq.
Ice Miller LLP
2300 Cabot Drive
Suite 455
Lisle, IL 60532
	Space Above this Line Reserved for Recorder’s Use Only

SUPPLEMENTAL INDENTURE

MADE AS OF AUGUST 3, 2018, TO BE EFFECTIVE AUGUST 16, 2018____________________

NORTHERN ILLINOIS GAS COMPANYTOTHE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.TRUSTEE UNDER INDENTURE DATED AS OFJANUARY 1, 1954

and

SUPPLEMENTAL INDENTURES THERETO____________________

FIRST MORTGAGE BONDS 4.08% SERIES DUE AUGUST 16, 2039

FIRST MORTGAGE BONDS 4.19% SERIES DUE AUGUST 16, 2048

FIRST MORTGAGE BONDS 4.34% SERIES DUE AUGUST 16, 2058

THIS SUPPLEMENTAL INDENTURE, made as of August 3, 2018 and effective August 16, 2018, between NORTHERN ILLINOIS GAS COMPANY, a corporation organized and existing under the laws of the State of Illinois (hereinafter called the “Company”), and THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A. (hereinafter called the “Trustee”), as successor Trustee under an Indenture dated as of January 1, 1954, as modified by the Indenture of Adoption, dated February 9, 1954 and the Indenture of Release, dated February 9, 1954, and as supplemented by Supplemental Indentures dated (or made effective) April 1, 1956, June 1, 1959, July 1, 1960, June 1, 1963, July 1, 1963, August 1, 1964, August 1, 1965, May 1, 1966, August 1, 1966, July 1, 1967, June 1, 1968, December 1, 1969, August 1, 1970, June 1, 1971, July 1, 1972, July 1, 1973, April 1, 1975, April 30, 1976 (two Supplemental Indentures bearing that date), July 1, 1976, August 1, 1976, December 1, 1977, January 15, 1979, December 1, 1981, March 1, 1983, October 1, 1984, December 1, 1986, March 15, 1988, July 1, 1988, July 1, 1989, July 15, 1990, August 15, 1991, July 15, 1992, February 1, 1993, March 15, 1993, May 1, 1993, July 1, 1993, August 15, 1994, October 15, 1995, May 10, 1996, August 1, 1996, June 1, 1997, October 15, 1997, February 15, 1998, June 1, 1998, February 1, 1999, February 1, 2001, May 15, 2001, August 15, 2001, December 15, 2001, December 1, 2003 (three Supplemental Indentures bearing that date), December 15, 2006, August 15, 2008, July 30, 2009, February 1, 2011, October 26, 2012, June 23, 2016 and August 10, 2017, such Indenture dated as of January 1, 1954, as so modified and supplemented, being hereinafter called the “Indenture.”

WITNESSETH:

WHEREAS, the Indenture provides for the issuance from time to time thereunder, in series, of bonds of the Company for the purposes and subject to the limitations therein specified; and

WHEREAS, the Company desires, by this Supplemental Indenture, to create three additional series of bonds to be issuable under the Indenture, such bonds to be designated, respectively, (a) “First Mortgage Bonds 4.08% Series due August 16, 2039” (hereinafter called the “2039 Series”), (b) “First Mortgage Bonds 4.19% Series due August 16, 2048” (hereinafter called the “2048 Series”), and (c) “First Mortgage Bonds 4.34% due August 16, 2058” (hereinafter called the “2058 Series”; the 2039 Series, the 2048 Series and the 2058 Series, hereinafter called, collectively, the “bonds of this Supplemental Indenture”), and the terms and provisions to be contained in the bonds of this Supplemental Indenture or to be otherwise applicable thereto to be as set forth in this Supplemental Indenture; and

WHEREAS, the forms, respectively, of the bonds of this Supplemental Indenture, and the Trustee’s certificate to be endorsed on all bonds of this Supplemental Indenture, are to be substantially as follows:

[Remainder of Page Intentionally Left Blank]

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(FORM OF FACE OF BOND OF 2039 SERIES)

NO. RU-2018-A-__	$________
Ill. Commerce Commission No. 6775	CUSIP No. __________

NORTHERN ILLINOIS GAS COMPANYFirst Mortgage Bond 4.08% Series due August 16, 2039

NORTHERN ILLINOIS GAS COMPANY, an Illinois corporation (hereinafter called the “Company”), for value received, hereby promises to pay to                      or registered assigns, the sum of                           Dollars, on August 16, 2039, and to pay to the registered owner hereof interest on said sum from the date hereof until said sum shall be paid, at the rate of 4.08% per annum, payable semi-annually on the sixteenth day of February and the sixteenth day of August in each year, beginning on February 16, 2019. Both the principal of and the interest on this bond shall be payable at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts. Any installment of interest on this bond may, at the Company’s option, be paid by mailing checks for such interest payable to or upon the written order of the person entitled thereto to the address of such person as it appears on the registration books.

So long as there is no existing default in the payment of interest on this bond, the interest so payable on any interest payment date will be paid to the person in whose name this bond is registered on February 1 or August 1 (whether or not a business day), as the case may be, next preceding such interest payment date. If and to the extent that the Company shall default in the payment of interest due on such interest payment date, such defaulted interest shall be paid to the person in whose name this bond is registered on the record date fixed, in advance, by the Company for the payment of such defaulted interest.

Additional provisions of this bond are set forth on the reverse hereof.

This bond shall not be entitled to any security or benefit under the Indenture or be valid or become obligatory for any purpose unless and until it shall have been authenticated by the execution by the Trustee, or its successor in trust under the Indenture, of the certificate endorsed hereon.

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IN WITNESS WHEREOF, Northern Illinois Gas Company has caused this bond to be executed in its name by its                            , manually or by facsimile signature, and has caused its corporate seal to be impressed hereon or a facsimile thereof to be imprinted hereon and to be attested by its                           , manually or by facsimile signature.

Dated: August 16, 2018

		NORTHERN ILLINOIS GAS COMPANY
	By:
ATTEST:

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(FORM OF TRUSTEE’S CERTIFICATE OF AUTHENTICATION)

This bond is one of the bonds of the 2039 Series designated therein, referred to and described in the within-mentioned Supplemental Indenture dated as of August 3, 2018, effective August 16, 2018.

THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.,
   TRUSTEE

By:
	Authorized Officer

Dated:  August 16, 2018

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(FORM OF REVERSE SIDE OF BOND OF 2039 SERIES)

This bond is one, of the series hereinafter specified, of the bonds issued and to be issued in series from time to time under and in accordance with and secured by an Indenture dated as of January 1, 1954, to The Bank of New York Mellon Trust Company, N.A., as Trustee, as supplemented by certain indentures supplemental thereto, executed and delivered to the Trustee; and this bond is one of a series of such bonds, designated “Northern Illinois Gas Company First Mortgage Bond 4.08% Series due August 16, 2039” (herein called “bonds of this Series”), the issuance of which is provided for by a Supplemental Indenture dated as of August 3, 2018, effective August 16, 2018 (hereinafter called the “Supplemental Indenture”), executed and delivered by the Company to the Trustee. The term “Indenture”, as hereinafter used, means said Indenture dated as of January 1, 1954, and all indentures supplemental thereto (including, without limitation, the Supplemental Indenture) from time to time in effect. Reference is made to the Indenture for a description of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders and registered owners of said bonds, of the Company and of the Trustee in respect of the security, and the terms and conditions governing the issuance and security of said bonds.

Any transferee, by its acceptance of a bond registered in its name (or the name of its nominee), shall be deemed to have made the representation set forth in Section 6.2 of the Bond Purchase Agreement dated as of August 3, 2018 among the Company and the purchasers listed on Schedule A attached thereto, as amended, restated, supplemented or otherwise modified from time to time.

With the consent of the Company and to the extent permitted by and as provided in the Indenture, modifications or alterations of the Indenture or of any supplemental indenture and of the rights and obligations of the Company and of the holders and registered owners of the bonds may be made, and compliance with any provision of the Indenture or of any supplemental indenture may be waived, by the affirmative vote of the holders and registered owners of not less than sixty-six and two-thirds per centum (66 2/3%) in principal amount of the bonds then outstanding under the Indenture, and by the affirmative vote of the holders and registered owners of not less than sixty-six and two-thirds per centum (66 2/3%) in principal amount of the bonds of any series then outstanding under the Indenture and affected by such modification or alteration, in case one or more but less than all of the series of bonds then outstanding under the Indenture are so affected, but in any case excluding bonds disqualified from voting by reason of the Company’s interest therein as provided in the Indenture; subject, however, to the condition, among other conditions stated in the Indenture, that no such modification or alteration shall be made which, among other things, will permit the extension of the time or times of payment of the principal of or the interest or the premium, if any, on this bond, or the reduction in the principal amount hereof or in the rate of interest or the amount of any premium hereon, or any other modification in the terms of payment of such principal, interest or premium, which terms of payment are unconditional, or, otherwise than as permitted by the Indenture, the creation of any lien ranking prior to or on a parity with the lien of the Indenture with respect to any of the mortgaged property, all as more fully provided in the Indenture.

- 5 -

The bonds of this Series may be called for redemption by the Company, as a whole at any time or in part from time to time, at a redemption price equal to 100% of the principal amount of the bonds of this Series to be redeemed plus accrued and unpaid interest on the principal amount being redeemed to the date of redemption and the Make-Whole Amount (as defined in the Supplemental Indenture) applicable thereto.

Notice of each redemption shall be mailed to all registered owners not less than thirty nor more than forty-five days before the redemption date.

In case of certain completed defaults specified in the Indenture, the principal of this bond may be declared or may become due and payable in the manner and with the effect provided in the Indenture.

No recourse shall be had for the payment of the principal of or the interest or the premium, if any, on this bond, or for any claim based hereon, or otherwise in respect hereof or of the Indenture, to or against any incorporator, stockholder, officer or director, past, present or future, of the Company or of any predecessor or successor corporation, either directly or through the Company or such predecessor or successor corporation, under any constitution or statute or rule of law, or by the enforcement of any assessment or penalty, or otherwise, all such liability of incorporators, stockholders, directors and officers being waived and released by the registered owner hereof by the acceptance of this bond and being likewise waived and released by the terms of the Indenture, all as more fully provided therein.

This bond is transferable by the registered owner hereof, in person or by duly authorized attorney, at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, upon surrender and cancellation of this bond; and thereupon a new registered bond or bonds without coupons of the same aggregate principal amount and series will, upon the payment of any transfer tax or taxes payable, be issued to the transferee in exchange herefor. The Company shall not be required to exchange or transfer this bond if this bond or a portion hereof has been selected for redemption.

The security represented by this certificate has not been registered under the Securities Act of 1933, as amended (the “Securities Act”), or qualified under any state securities laws and may not be transferred, sold or otherwise disposed of except while a registration statement is in effect or pursuant to an available exemption from registration under the Securities Act and applicable state securities laws.

(END OF FORM OF BOND OF 2039 SERIES)

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(FORM OF FACE OF BOND OF 2048 SERIES)

NO. RU-2018-B-__	$________
Ill. Commerce Commission No. 6776	CUSIP No. __________

NORTHERN ILLINOIS GAS COMPANYFirst Mortgage Bond 4.19% Series due August 16, 2048

NORTHERN ILLINOIS GAS COMPANY, an Illinois corporation (hereinafter called the “Company”), for value received, hereby promises to pay to                      or registered assigns, the sum of                           Dollars, on August 16, 2048, and to pay to the registered owner hereof interest on said sum from the date hereof until said sum shall be paid, at the rate of 4.19% per annum, payable semi-annually on the sixteenth day of February and the sixteenth day of August in each year, beginning on February 16, 2019. Both the principal of and the interest on this bond shall be payable at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts. Any installment of interest on this bond may, at the Company’s option, be paid by mailing checks for such interest payable to or upon the written order of the person entitled thereto to the address of such person as it appears on the registration books.

So long as there is no existing default in the payment of interest on this bond, the interest so payable on any interest payment date will be paid to the person in whose name this bond is registered on February 1 or August 1 (whether or not a business day), as the case may be, next preceding such interest payment date. If and to the extent that the Company shall default in the payment of interest due on such interest payment date, such defaulted interest shall be paid to the person in whose name this bond is registered on the record date fixed, in advance, by the Company for the payment of such defaulted interest.

Additional provisions of this bond are set forth on the reverse hereof.

This bond shall not be entitled to any security or benefit under the Indenture or be valid or become obligatory for any purpose unless and until it shall have been authenticated by the execution by the Trustee, or its successor in trust under the Indenture, of the certificate endorsed hereon.

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IN WITNESS WHEREOF, Northern Illinois Gas Company has caused this bond to be executed in its name by its                            , manually or by facsimile signature, and has caused its corporate seal to be impressed hereon or a facsimile thereof to be imprinted hereon and to be attested by its                           , manually or by facsimile signature.

Dated: November 1, 2018

		NORTHERN ILLINOIS GAS COMPANY
	By:
ATTEST:

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(FORM OF TRUSTEE’S CERTIFICATE OF AUTHENTICATION)

This bond is one of the bonds of the 2048 Series designated therein, referred to and described in the within-mentioned Supplemental Indenture dated as of August 3, 2018, effective August 16, 2018.

THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.,
   TRUSTEE

By:
	Authorized Officer

Dated: November 1, 2018

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(FORM OF REVERSE SIDE OF BOND OF 2048 SERIES)

This bond is one, of the series hereinafter specified, of the bonds issued and to be issued in series from time to time under and in accordance with and secured by an Indenture dated as of January 1, 1954, to The Bank of New York Mellon Trust Company, N.A., as Trustee, as supplemented by certain indentures supplemental thereto, executed and delivered to the Trustee; and this bond is one of a series of such bonds, designated “Northern Illinois Gas Company First Mortgage Bond 4.19% Series due August 16, 2048” (herein called “bonds of this Series”), the issuance of which is provided for by a Supplemental Indenture dated as of August 3, 2018, effective August 16, 2018 (hereinafter called the “Supplemental Indenture”), executed and delivered by the Company to the Trustee. The term “Indenture”, as hereinafter used, means said Indenture dated as of January 1, 1954, and all indentures supplemental thereto (including, without limitation, the Supplemental Indenture) from time to time in effect. Reference is made to the Indenture for a description of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders and registered owners of said bonds, of the Company and of the Trustee in respect of the security, and the terms and conditions governing the issuance and security of said bonds.

Any transferee, by its acceptance of a bond registered in its name (or the name of its nominee), shall be deemed to have made the representation set forth in Section 6.2 of the Bond Purchase Agreement dated as of August 3, 2018 among the Company and the purchasers listed on Schedule A attached thereto, as amended, restated, supplemented or otherwise modified from time to time.

With the consent of the Company and to the extent permitted by and as provided in the Indenture, modifications or alterations of the Indenture or of any supplemental indenture and of the rights and obligations of the Company and of the holders and registered owners of the bonds may be made, and compliance with any provision of the Indenture or of any supplemental indenture may be waived, by the affirmative vote of the holders and registered owners of not less than sixty-six and two-thirds per centum (66 2/3%) in principal amount of the bonds then outstanding under the Indenture, and by the affirmative vote of the holders and registered owners of not less than sixty-six and two-thirds per centum (66 2/3%) in principal amount of the bonds of any series then outstanding under the Indenture and affected by such modification or alteration, in case one or more but less than all of the series of bonds then outstanding under the Indenture are so affected, but in any case excluding bonds disqualified from voting by reason of the Company’s interest therein as provided in the Indenture; subject, however, to the condition, among other conditions stated in the Indenture, that no such modification or alteration shall be made which, among other things, will permit the extension of the time or times of payment of the principal of or the interest or the premium, if any, on this bond, or the reduction in the principal amount hereof or in the rate of interest or the amount of any premium hereon, or any other modification in the terms of payment of such principal, interest or premium, which terms of payment are unconditional, or, otherwise than as permitted by the Indenture, the creation of any lien ranking prior to or on a parity with the lien of the Indenture with respect to any of the mortgaged property, all as more fully provided in the Indenture.

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The bonds of this Series may be called for redemption by the Company, as a whole at any time or in part from time to time, at a redemption price equal to 100% of the principal amount of the bonds of this Series to be redeemed plus accrued and unpaid interest on the principal amount being redeemed to the date of redemption and the Make-Whole Amount (as defined in the Supplemental Indenture) applicable thereto.

Notice of each redemption shall be mailed to all registered owners not less than thirty nor more than forty-five days before the redemption date.

In case of certain completed defaults specified in the Indenture, the principal of this bond may be declared or may become due and payable in the manner and with the effect provided in the Indenture.

No recourse shall be had for the payment of the principal of or the interest or the premium, if any, on this bond, or for any claim based hereon, or otherwise in respect hereof or of the Indenture, to or against any incorporator, stockholder, officer or director, past, present or future, of the Company or of any predecessor or successor corporation, either directly or through the Company or such predecessor or successor corporation, under any constitution or statute or rule of law, or by the enforcement of any assessment or penalty, or otherwise, all such liability of incorporators, stockholders, directors and officers being waived and released by the registered owner hereof by the acceptance of this bond and being likewise waived and released by the terms of the Indenture, all as more fully provided therein.

This bond is transferable by the registered owner hereof, in person or by duly authorized attorney, at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, upon surrender and cancellation of this bond; and thereupon a new registered bond or bonds without coupons of the same aggregate principal amount and series will, upon the payment of any transfer tax or taxes payable, be issued to the transferee in exchange herefor. The Company shall not be required to exchange or transfer this bond if this bond or a portion hereof has been selected for redemption.

The security represented by this certificate has not been registered under the Securities Act of 1933, as amended (the “Securities Act”), or qualified under any state securities laws and may not be transferred, sold or otherwise disposed of except while a registration statement is in effect or pursuant to an available exemption from registration under the Securities Act and applicable state securities laws.

(END OF FORM OF BOND OF 2048 SERIES)

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(FORM OF FACE OF BOND OF 2058 SERIES)

NO. RU-2018-C-__	$________
Ill. Commerce Commission No. 6777	CUSIP No. __________

NORTHERN ILLINOIS GAS COMPANYFirst Mortgage Bond 4.34% Series due August 16, 2058

NORTHERN ILLINOIS GAS COMPANY, an Illinois corporation (hereinafter called the “Company”), for value received, hereby promises to pay to                      or registered assigns, the sum of                           Dollars, on August 16, 2058, and to pay to the registered owner hereof interest on said sum from the date hereof until said sum shall be paid, at the rate of 4.34% per annum, payable semi-annually on the sixteenth day of February and the sixteenth day of August in each year, beginning on February 16, 2019. Both the principal of and the interest on this bond shall be payable at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts. Any installment of interest on this bond may, at the Company’s option, be paid by mailing checks for such interest payable to or upon the written order of the person entitled thereto to the address of such person as it appears on the registration books.

So long as there is no existing default in the payment of interest on this bond, the interest so payable on any interest payment date will be paid to the person in whose name this bond is registered on February 1 or August 1 (whether or not a business day), as the case may be, next preceding such interest payment date. If and to the extent that the Company shall default in the payment of interest due on such interest payment date, such defaulted interest shall be paid to the person in whose name this bond is registered on the record date fixed, in advance, by the Company for the payment of such defaulted interest.

Additional provisions of this bond are set forth on the reverse hereof.

This bond shall not be entitled to any security or benefit under the Indenture or be valid or become obligatory for any purpose unless and until it shall have been authenticated by the execution by the Trustee, or its successor in trust under the Indenture, of the certificate endorsed hereon.

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IN WITNESS WHEREOF, Northern Illinois Gas Company has caused this bond to be executed in its name by its            , manually or by facsimile signature, and has caused its corporate seal to be impressed hereon or a facsimile thereof to be imprinted hereon and to be attested by its            , manually or by facsimile signature.

Dated: November 1, 2018

		NORTHERN ILLINOIS GAS COMPANY
	By:
ATTEST:

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(FORM OF TRUSTEE’S CERTIFICATE OF AUTHENTICATION)

This bond is one of the bonds of the 2058 Series designated therein, referred to and described in the within-mentioned Supplemental Indenture dated as of August 3, 2018, effective August 16, 2018.

THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.,
   TRUSTEE

By:
	Authorized Officer

Dated: November 1, 2018

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(FORM OF REVERSE SIDE OF BOND OF 2058 SERIES)

This bond is one, of the series hereinafter specified, of the bonds issued and to be issued in series from time to time under and in accordance with and secured by an Indenture dated as of January 1, 1954, to The Bank of New York Mellon Trust Company, N.A., as Trustee, as supplemented by certain indentures supplemental thereto, executed and delivered to the Trustee; and this bond is one of a series of such bonds, designated “Northern Illinois Gas Company First Mortgage Bond 4.34% Series due August 16, 2058” (herein called “bonds of this Series”), the issuance of which is provided for by a Supplemental Indenture dated as of August 3, 2018, effective August 16, 2018 (hereinafter called the “Supplemental Indenture”), executed and delivered by the Company to the Trustee. The term “Indenture”, as hereinafter used, means said Indenture dated as of January 1, 1954, and all indentures supplemental thereto (including, without limitation, the Supplemental Indenture) from time to time in effect. Reference is made to the Indenture for a description of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders and registered owners of said bonds, of the Company and of the Trustee in respect of the security, and the terms and conditions governing the issuance and security of said bonds.

Any transferee, by its acceptance of a bond registered in its name (or the name of its nominee), shall be deemed to have made the representation set forth in Section 6.2 of the Bond Purchase Agreement dated as of August 3, 2018 among the Company and the purchasers listed on Schedule A attached thereto, as amended, restated, supplemented or otherwise modified from time to time.

With the consent of the Company and to the extent permitted by and as provided in the Indenture, modifications or alterations of the Indenture or of any supplemental indenture and of the rights and obligations of the Company and of the holders and registered owners of the bonds may be made, and compliance with any provision of the Indenture or of any supplemental indenture may be waived, by the affirmative vote of the holders and registered owners of not less than sixty-six and two-thirds per centum (66 2/3%) in principal amount of the bonds then outstanding under the Indenture, and by the affirmative vote of the holders and registered owners of not less than sixty-six and two-thirds per centum (66 2/3%) in principal amount of the bonds of any series then outstanding under the Indenture and affected by such modification or alteration, in case one or more but less than all of the series of bonds then outstanding under the Indenture are so affected, but in any case excluding bonds disqualified from voting by reason of the Company’s interest therein as provided in the Indenture; subject, however, to the condition, among other conditions stated in the Indenture, that no such modification or alteration shall be made which, among other things, will permit the extension of the time or times of payment of the principal of or the interest or the premium, if any, on this bond, or the reduction in the principal amount hereof or in the rate of interest or the amount of any premium hereon, or any other modification in the terms of payment of such principal, interest or premium, which terms of payment are unconditional, or, otherwise than as permitted by the Indenture, the creation of any lien ranking prior to or on a parity with the lien of the Indenture with respect to any of the mortgaged property, all as more fully provided in the Indenture.

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The bonds of this Series may be called for redemption by the Company, as a whole at any time or in part from time to time, at a redemption price equal to 100% of the principal amount of the bonds of this Series to be redeemed plus accrued and unpaid interest on the principal amount being redeemed to the date of redemption and the Make-Whole Amount (as defined in the Supplemental Indenture) applicable thereto.

Notice of each redemption shall be mailed to all registered owners not less than thirty nor more than forty-five days before the redemption date.

In case of certain completed defaults specified in the Indenture, the principal of this bond may be declared or may become due and payable in the manner and with the effect provided in the Indenture.

No recourse shall be had for the payment of the principal of or the interest or the premium, if any, on this bond, or for any claim based hereon, or otherwise in respect hereof or of the Indenture, to or against any incorporator, stockholder, officer or director, past, present or future, of the Company or of any predecessor or successor corporation, either directly or through the Company or such predecessor or successor corporation, under any constitution or statute or rule of law, or by the enforcement of any assessment or penalty, or otherwise, all such liability of incorporators, stockholders, directors and officers being waived and released by the registered owner hereof by the acceptance of this bond and being likewise waived and released by the terms of the Indenture, all as more fully provided therein.

This bond is transferable by the registered owner hereof, in person or by duly authorized attorney, at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York, upon surrender and cancellation of this bond; and thereupon a new registered bond or bonds without coupons of the same aggregate principal amount and series will, upon the payment of any transfer tax or taxes payable, be issued to the transferee in exchange herefor. The Company shall not be required to exchange or transfer this bond if this bond or a portion hereof has been selected for redemption.

The security represented by this certificate has not been registered under the Securities Act of 1933, as amended (the “Securities Act”), or qualified under any state securities laws and may not be transferred, sold or otherwise disposed of except while a registration statement is in effect or pursuant to an available exemption from registration under the Securities Act and applicable state securities laws.

(END OF FORM OF BOND OF 2058 SERIES)

and

WHEREAS, all acts and things necessary to make this Supplemental Indenture, when duly executed and delivered, a valid, binding and legal instrument in accordance with its terms, and for the purposes herein expressed, have been done and performed, and the execution and delivery of this Supplemental Indenture have in all respects been duly authorized;

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NOW THEREFORE, in consideration of the premises and of the sum of one dollar paid by the Trustee to the Company, and for other good and valuable consideration, the receipt of which is hereby acknowledged, for the purpose of securing the due and punctual payment of the principal of and the interest and premium, if any, on all bonds which shall be issued under the Indenture, and for the purpose of securing the faithful performance and observance of all the covenants and conditions set forth in the Indenture and in all indentures supplemental thereto, the Company by these presents does grant, bargain, sell, transfer, assign, pledge, mortgage, warrant and convey unto The Bank of New York Mellon Trust Company, N.A., as Trustee, and its successor or successors in the trust hereby created, all property, real and personal (other than property expressly excepted from the lien and operation of the Indenture), which, at the actual date of execution and delivery of this Supplemental Indenture, is solely used or held for use in the operation by the Company of its gas utility system and in the conduct of its gas utility business and all property, real and personal, used or useful in the gas utility business (other than property expressly excepted from the lien and operation of the Indenture) acquired by the Company after the actual date of execution and delivery of this Supplemental Indenture or (subject to the provisions of Section 16.03 of the Indenture) by any successor corporation after such execution and delivery, and it is further agreed by and between the Company and the Trustee as follows:

ARTICLE I.BONDS OF THIS SUPPLEMENTAL INDENTURE

Section 1.The bonds of this Supplemental Indenture shall, as hereinbefore recited, be designated as the Company’s (a) “First Mortgage Bonds 4.08% Series due August 16, 2039”, (b) “First Mortgage Bonds 4.19% Series due August 16, 2048”, and (c) “First Mortgage Bonds 4.34% Series due August 16, 2058”, as applicable. The bonds of the 2039 Series which may be issued and outstanding shall not exceed $100,000,000 in aggregate principal amount, exclusive of bonds of such series authenticated and delivered pursuant to Section 4.12 of the Indenture. The bonds of the 2048 Series which may be issued and outstanding shall not exceed $100,000,000 in aggregate principal amount, exclusive of bonds of such series authenticated and delivered pursuant to Section 4.12 of the Indenture. The bonds of the 2058 Series which may be issued and outstanding shall not exceed $100,000,000 in aggregate principal amount, exclusive of bonds of such series authenticated and delivered pursuant to Section 4.12 of the Indenture.

Section 2.The bonds of this Supplemental Indenture shall be registered bonds without coupons, and the form of each series of such bonds, and of the Trustee’s certificate of authentication to be endorsed on all bonds of this Supplemental Indenture, shall be substantially as hereinbefore recited, respectively.

Section 3.The bonds of this Supplemental Indenture shall be issued in the denomination of $500,000 each and in such integral multiple or multiples thereof as shall be determined and authorized by the Board of Directors of the Company or by any officer of the Company authorized by the Board of Directors to make such determination, the authorization of the denomination of any bond to be conclusively evidenced by the execution thereof on behalf of the Company. The bonds of the 2039 Series shall be numbered RU-2018-A-1 and consecutively upwards, or in such other appropriate manner as shall be determined and authorized by the Board

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of Directors of the Company. The bonds of the 2048 Series shall be numbered RU-2018-B-1 and consecutively upwards, or in such other appropriate manner as shall be determined and authorized by the Board of Directors of the Company. The bonds of the 2058 Series shall be numbered RU-2018-C-1 and consecutively upwards, or in such other appropriate manner as shall be determined and authorized by the Board of Directors of the Company.

The bonds of the 2039 Series shall be dated August 16, 2018, except that each bond issued on or after the first payment of interest thereon shall be dated as of the date of the interest payment date thereof to which interest shall have been paid on the bonds of its series next preceding the date of issue, unless issued on an interest payment date to which interest shall have been so paid, in which event such bonds shall be dated as of the date of issue; provided, however, that bonds issued on or after February 1 and before the next succeeding February 16 or on or after August 1 and before the next succeeding August 16 shall be dated the next succeeding interest payment date if interest shall have been paid to such date. The bonds of the 2048 Series and the 2058 Series shall be dated November 1, 2018, except that each bond issued on or after the respective first payment of interest thereon shall be dated as of the date of the interest payment date thereof to which interest shall have been paid on the bonds of such series next preceding the date of issue, unless issued on an interest payment date to which interest shall have been so paid, in which event such bonds shall be dated as of the date of issue; provided, however, that bonds issued on or after February 1 and before the next succeeding February 16 or on or after August 1 and before the next succeeding August 16 shall be dated the next succeeding interest payment date if interest shall have been paid to such date. The bonds of the 2039 Series shall mature on August 16, 2039 and shall bear interest at the rate of 4.08% per annum until the principal thereof shall be paid. The bonds of the 2048 Series shall mature on August 16, 2048 and shall bear interest at the rate of 4.19% per annum until the principal thereof shall be paid. The bonds of the 2058 Series shall mature on August 16, 2058 and shall bear interest at the rate of 4.34% per annum until the principal thereof shall be paid. Interest on the bonds of this Supplemental Indenture shall be calculated on the basis of a 360-day year consisting of twelve 30-day months. Interest on the bonds of the 2039 Series shall be payable semi-annually on the sixteenth day of February and the sixteenth day of August in each year, beginning February 16, 2019. Interest on the bonds of the 2048 Series shall be payable semi-annually on the sixteenth day of February and the sixteenth day of August in each year, beginning February 16, 2019. Interest on the bonds of the 2058 Series shall be payable semi-annually on the sixteenth day of February and the sixteenth day of August in each year, beginning February 16, 2019. So long as there is no existing default in the payment of interest on the bonds of this Supplemental Indenture, such interest shall be payable to the person in whose name each such bond is registered on the respective record date (whether or not a business day), as the case may be, next preceding the respective interest payment dates; provided, however, if and to the extent that the Company shall default in the payment of interest due on such interest payment date, such defaulted interest shall be paid to the person in whose name each such bond is registered on the record date fixed, in advance, by the Company for the payment of such defaulted interest.Interest will accrue on overdue interest installments at the rate of (i) 4.08% per annum, with respect to the bonds of the 2039 Series, (ii) 4.19% per annum, with respect to the bonds of the 2048 Series, and (iii) 4.34% per annum, with respect to the bonds of the 2058 Series.

The principal of and interest and premium, if any, on the bonds of this Supplemental Indenture shall be payable in any coin or currency of the United States of America which at the

- 18 -

time of payment is legal tender for the payment of public and private debts, and shall be payable at the office or agency of the Company in the City of Chicago, State of Illinois, or, at the option of the registered owner, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York. Any installment of interest on the bonds of this Supplemental Indenture may, at the Company’s option, be paid by mailing checks for such interest payable to or upon the written order of the person entitled thereto to the address of such person as it appears on the registration books. The bonds of this Supplemental Indenture shall be registrable, transferable and exchangeable in the manner provided in Sections 4.08 and 4.09 of the Indenture, at either of such offices or agencies.

Section 4.    The bonds of this Supplemental Indenture, upon the mailing of notice and in the manner provided in Section 7.01 of the Indenture (except that no published notice shall be required for the bonds of this Supplemental Indenture) and with the effect provided in Section 7.02 thereof, shall be redeemable at the option of the Company, as a whole at any time or in part from time to time, at a redemption price equal to 100% of the principal amount of the bonds of this Supplemental Indenture to be redeemed plus accrued and unpaid interest of the principal amount being redeemed to the date of redemption plus the Make-Whole Amount applicable thereto, as calculated by the Company. “Make-Whole Amount” means, with respect to any bond of this Supplemental Indenture, an amount equal to the excess, if any, of the Discounted Value of the Remaining Scheduled Payments with respect to the Called Principal of such bond of this Supplemental Indenture over the amount of such Called Principal, provided that the Make-Whole Amount may in no event be less than zero. For the purposes of determining the Make-Whole Amount, the following terms have the following meanings:

“Called Principal” means, with respect to any bond of this Supplemental Indenture, the principal of such bond of this Supplemental Indenture that is to be redeemed.

“Discounted Value” means, with respect to the Called Principal of any bond of this Supplemental Indenture, the amount obtained by discounting all Remaining Scheduled Payments with respect to such Called Principal from their respective scheduled due dates to the Settlement Date with respect to such Called Principal, in accordance with accepted financial practice and at a discount factor (applied on the same periodic basis as that on which interest on the bond of this Supplemental Indenture is payable) equal to the Reinvestment Yield with respect to such Called Principal.

“Reinvestment Yield” means, with respect to the Called Principal of any bond of this Supplemental Indenture, the sum of (x) 0.50% plus (y) the yield to maturity implied by the “Ask Yield(s)” reported as of 10:00 a.m. (New York City time) on the second Business Day preceding the Settlement Date with respect to such Called Principal, on the display designated as “Page PX1” (or such other display as may replace Page PX1) on Bloomberg Financial Markets for the most recently issued actively traded on-the-run U.S. Treasury securities (“Reported”) having a maturity equal to the Remaining Average Life of such Called Principal as of such Settlement Date. If there are no such U.S. Treasury securities Reported having a maturity equal to such Remaining Average Life, then such implied yield to maturity will be determined by (a) converting U.S. Treasury bill quotations to bond equivalent yields in accordance with accepted financial practice and

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(b) interpolating linearly between the “Ask Yields” Reported for the applicable most recently issued actively traded on-the-run U.S. Treasury securities with the maturities (1) closest to and greater than such Remaining Average Life and (2) closest to and less than such Remaining Average Life. The Reinvestment Yield shall be rounded to the number of decimal places as appears in the interest rate of the applicable bond.

If such yields are not Reported or the yields Reported as of such time are not ascertainable (including by way of interpolation), then “Reinvestment Yield” means, with respect to the Called Principal of any bond of this Supplemental Indenture, the sum of (x) 0.50% plus (y) the yield to maturity implied by the U.S. Treasury constant maturity yields reported, for the latest day for which such yields have been so reported as of the second Business Day preceding the Settlement Date with respect to such Called Principal, in Federal Reserve Statistical Release H.15 (or any comparable successor publication) for the U.S. Treasury constant maturity having a term equal to the Remaining Average Life of such Called Principal as of such Settlement Date. If there is no such U.S. Treasury constant maturity having a term equal to such Remaining Average Life, such implied yield to maturity will be determined by interpolating linearly between (1) the U.S. Treasury constant maturity so reported with the term closest to and greater than such Remaining Average Life and (2) the U.S. Treasury constant maturity so reported with the term closest to and less than such Remaining Average Life. The Reinvestment Yield shall be rounded to the number of decimal places as appears in the interest rate of the applicable bond.

“Remaining Average Life” means, with respect to any Called Principal, the number of years obtained by dividing (a) such Called Principal into (b) the sum of the products obtained by multiplying (1) the principal component of each Remaining Scheduled Payment with respect to such Called Principal by (2) the number of years, computed on the basis of a 360-day year comprised of twelve 30-day months and calculated to the nearest two decimal places, that will elapse between the Settlement Date with respect to such Called Principal and the scheduled due date of such Remaining Scheduled Payment.

“Remaining Scheduled Payments” means, with respect to the Called Principal of any bond of this Supplemental Indenture, all payments of such Called Principal and interest thereon that would be due after the Settlement Date with respect to such Called Principal if no payment of such Called Principal were made prior to its scheduled due date, provided that if such Settlement Date is not a date on which interest payments are due to be made under the terms of the bond of this Supplemental Indenture, then the amount of the next succeeding scheduled interest payment will be reduced by the amount of interest accrued to such Settlement Date and required to be paid on such Settlement Date pursuant to the terms of this Supplemental Indenture.

“Settlement Date” means, with respect to the Called Principal of any bond of this Supplemental Indenture, the date on which such Called Principal is to be redeemed.

Section 5.No sinking fund is to be provided for the bonds of this Supplemental Indenture.

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ARTICLE IIMISCELLANEOUS PROVISIONS

Section 1.    This Supplemental Indenture is executed by the Company and the Trustee pursuant to provisions of Section 4.02 of the Indenture and the terms and conditions hereof shall be deemed to be a part of the terms and conditions of the Indenture for any and all purposes. The Indenture, as heretofore modified and supplemented and as supplemented by this Supplemental Indenture, is in all respects ratified and confirmed.

Section 2.    This Supplemental Indenture shall bind and, subject to the provisions of Article XVI of the Indenture, inure to the benefit of the respective successors and assigns of the parties hereto.

Section 3.    Although this Supplemental Indenture is made as of August 3, 2018, effective August 16, 2018, it shall be effective only from and after the actual time of its execution and delivery by the Company and the Trustee on the date indicated by their respective acknowledgements hereto.

Section 4.    This Supplemental Indenture may be simultaneously executed in any number of counterparts, and all such counterparts executed and delivered, each as an original, shall constitute but one and the same instrument.

Section 5.    The recitals herein are deemed to be those of the Company and not of the Trustee. The Trustee makes no representations as to the validity or sufficiency of this Supplemental Indenture.

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IN WITNESS WHEREOF, Northern Illinois Gas Company has caused this Supplemental Indenture to be executed in its name by its Executive Vice President, Chief Financial Officer and Treasurer and its corporate seal to be hereunto affixed and attested by its Corporate Secretary, and The Bank of New York Mellon Trust Company, N.A., as Trustee under the Indenture, has caused this Supplemental Indenture to be executed in its name by one of its Vice Presidents, and its seal to be hereunto affixed and attested by one of its Vice Presidents, all as of the day and year first above written.

NORTHERN ILLINOIS GAS COMPANY
By:	/s/ Elizabeth W. Reese		[CORPORATE SEAL]
	Name:  Elizabeth W. Reese Title:    Executive Vice President, Chief              Financial Officer and Treasurer
		ATTEST:
		By:	/s/ Barbara P. Christopher
			Name:  Barbara P. Christopher Title:    Corporate Secretary

[Signature Page to 2018 Supplemental Indenture]

THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., as Trustee
By:	/s/ Karen Yu
	Name:   Karen Yu Title:     Vice President
			ATTEST:
		By:	/s/ Fanny Chen
			Name:   Fanny Chen Title:     Vice President
	[CORPORATE SEAL]

[Signature Page to 2018 Supplemental Indenture]

STATE OF GEORGIA           }           SS:

COUNTY OF HENRY           }

I, Brenda G. Davis, a Notary Public in the State aforesaid, DO HEREBY CERTIFY that Elizabeth W. Reese, Executive Vice President, Chief Financial Officer and Treasurer of Northern Illinois Gas Company, an Illinois corporation, one of the parties described in and which executed the foregoing instrument, and Barbara P. Christopher, Corporate Secretary of said corporation, who are both personally known to me to be the same persons whose names are subscribed to the foregoing instrument as such Executive Vice President, Chief Financial Officer and Treasurer and Corporate Secretary, respectively, and who are both personally known to me to be the Executive Vice President, Chief Financial Officer and Treasurer and Corporate Secretary, respectively, of said corporation, appeared before me this day in person and severally acknowledged that they signed, sealed, executed and delivered said instrument as their free and voluntary act as such Executive Vice President, Chief Financial Officer and Treasurer and Corporate Secretary, respectively, of said corporation, and as the free and voluntary act of said corporation, for the uses and purposes therein set forth.

GIVEN under my hand and notarial seal as of the date listed below.

Dated: August 3, 2018

/s/ Brenda G. Davis

Notary Public

My Commission expires: August 17, 2021.

[Notary Seal]

ACKNOWLEDGMENT

A notary public or other officer completing this certificate verifies only the identity of the individual who signed the document to which this certificate is attached, and not the truthfulness, accuracy, or validity of that document.

State of California

County of ______Los Angeles______________________

On ___August 3, 2018______ before me, ____Alex Dominguez, Notary Public__

                                                                          (insert name and title of the officer)

personally appeared Karen Yu and Fanny Chen                                                               ,

who proved to me on the basis of satisfactory evidence to be the person(s) whose name(s) is/are subscribed to the within instrument and acknowledged to me that he/she/they executed the same in his/her/their authorized capacity(ies), and that by his/her/their signature(s) on the instrument the person(s), or the entity upon behalf of which the person(s) acted, executed the instrument.

I certify under PENALTY OF PERJURY under the laws of the State of California that the foregoing paragraph is true and correct.

WITNESS my hand and official seal.

Signature __/s/ Alex Dominguez___________________________                   (Seal)

RECORDING DATA¹ 

This Supplemental Indenture was recorded on the following dates in the office of the Recorder of Deeds in certain counties in the State of Illinois, as follows:

County	Document No.2	Date Recorded
Cook
Adams
Boone
Bureau
Carroll
Champaign
DeKalb
DeWitt
DuPage
Ford
Grundy
Hancock
Henderson
Henry
Iroquois
Jo Daviess
Kane
Kankakee
Kendall
Lake
LaSalle
Lee
Livingston
McHenry
McLean
Mercer
Ogle
Piatt
Pike
Rock Island
Stephenson
Tazewell
Vermilion
Whiteside
Will
Winnebago
Woodford

_____________________________

¹This page to be intentionally omitted from versions submitted for recording.

²For delivery at Closing, Nicor to include all document numbers received prior to Closing. With respect to recordings for which no document number shall have been received prior to Closing, Nicor to provide such numbers post Closing.

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:  November 6, 2018

/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:  November 6, 2018

/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:  November 6, 2018

/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:  November 6, 2018

/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:  November 6, 2018

/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, Xia Liu, 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:  November 6, 2018

/s/Xia Liu

Xia Liu

Executive Vice President, Chief Financial Officer and Treasurer

EX-31.D1

Exhibit 31(d)1

GULF POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, S. W. Connally, Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q of Gulf 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:  November 6, 2018

/s/S. W. Connally, Jr.

S. W. Connally, Jr.

Chairman, President and Chief Executive Officer

EX-31.D2

Exhibit 31(d)2

GULF POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Robin B. Boren, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Gulf 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:  November 6, 2018

/s/Robin B. Boren

Robin B. Boren

Vice President, Chief Financial Officer and Treasurer

EX-31.E1

Exhibit 31(e)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:  November 6, 2018

/s/Anthony L. Wilson

Anthony L. Wilson

Chairman, President and

 Chief Executive Officer

EX-31.E2

Exhibit 31(e)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:  November 6, 2018

/s/Moses H. Feagin

Moses H. Feagin

Vice President, Treasurer and

Chief Financial Officer

EX-31.F1

Exhibit 31(f)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:   November 6, 2018

/s/Mark S. Lantrip

Mark S. Lantrip

Chairman, President and Chief Executive Officer

EX-31.F2

Exhibit 31(f)2

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, William C. Grantham, 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:  November 6, 2018

/s/William C. Grantham

William C. Grantham

Senior Vice President, Treasurer and Chief

Financial Officer

EX-31.G1

Exhibit 31(g)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:  November 6, 2018

/s/Kimberly S. Greene

Kimberly S. Greene

Chairman, President, and Chief Executive Officer

EX-31.G2

Exhibit 31(g)2

SOUTHERN COMPANY GAS

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Elizabeth W. Reese, 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:  November 6, 2018

/s/Elizabeth W. Reese

Elizabeth W. Reese

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 September 30, 2018, 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 September 30, 2018, 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 September 30, 2018, 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

November 6, 2018

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 September 30, 2018, 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 September 30, 2018, 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 September 30, 2018, 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

November 6, 2018

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 September 30, 2018, 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 September 30, 2018, 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 September 30, 2018, 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/Xia Liu

Xia Liu

Executive Vice President, Chief Financial Officer and Treasurer

November 6, 2018

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 Gulf Power Company for the quarter ended September 30, 2018, 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 Gulf Power Company for the quarter ended September 30, 2018, 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 Gulf Power Company for the quarter ended September 30, 2018, fairly presents, in all material respects, the financial condition and results of operations of Gulf Power Company.

/s/S. W. Connally, Jr.

S. W. Connally, Jr.

Chairman, President and Chief Executive Officer

/s/Robin B. Boren

Robin B. Boren

Vice President, Chief Financial Officer and Treasurer

November 6, 2018

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 Mississippi Power Company for the quarter ended September 30, 2018, 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 September 30, 2018, 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 September 30, 2018, 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

November 6, 2018

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 Power Company for the quarter ended September 30, 2018, 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 September 30, 2018, 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 September 30, 2018, 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, President

and Chief Executive Officer

/s/William C. Grantham

William C. Grantham

Senior Vice President, Treasurer and

Chief Financial Officer

November 6, 2018

EX-32.G

Exhibit 32(g)

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 September 30, 2018, 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 September 30, 2018, 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 September 30, 2018, 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/Elizabeth W. Reese

Elizabeth W. Reese

Executive Vice President, Chief Financial

Officer, and Treasurer

November 6, 2018

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2018 shares
Document Information [Line Items]
Entity Registrant Name	SOUTHERN CO
Entity Central Index Key	0000092122
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Amendment Flag	false
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding	1,028,888,684
ALABAMA POWER CO
Document Information [Line Items]
Entity Registrant Name	ALABAMA POWER CO
Entity Central Index Key	0000003153
Entity Filer Category	Non-accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding	30,537,500
GEORGIA POWER CO
Document Information [Line Items]
Entity Registrant Name	GEORGIA POWER CO
Entity Central Index Key	0000041091
Entity Filer Category	Non-accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding	9,261,500
GULF POWER CO
Document Information [Line Items]
Entity Registrant Name	GULF POWER CO
Entity Central Index Key	0000044545
Entity Filer Category	Non-accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding	7,392,717
MISSISSIPPI POWER CO
Document Information [Line Items]
Entity Registrant Name	MISSISSIPPI POWER CO
Entity Central Index Key	0000066904
Entity Filer Category	Non-accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding	1,121,000
SOUTHERN POWER CO
Document Information [Line Items]
Entity Registrant Name	SOUTHERN POWER CO
Entity Central Index Key	0001160661
Entity Filer Category	Non-accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding	1,000
SOUTHERN Co GAS
Document Information [Line Items]
Entity Registrant Name	SOUTHERN Co GAS
Entity Central Index Key	0001004155
Entity Filer Category	Non-accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding	100

XML

Condensed Consolidated Statements of Income (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Operating Revenues:
Total operating revenues	$ 6,159	$ 6,201	$ 18,158	$ 17,403
Operating Expenses:
Other operations and maintenance	1,404	1,341	4,217	4,100
Depreciation and amortization	787	767	2,338	2,236
Taxes other than income taxes	319	303	990	941
Estimated loss on plants under construction	1	34	1,105	3,155
Gain on dispositions, net	(353)	0	(317)	(19)
Impairment charges	36	0	197	0
Goodwill impairment			42
Total operating expenses	3,985	4,210	14,545	15,809
Operating Income (Loss)	2,174	1,991	3,613	1,594
Other Income and (Expense):
Allowance for equity funds used during construction	36	18	99	133
Earnings from equity method investments	36	32	108	100
Interest expense, net of amounts capitalized	(458)	(407)	(1,386)	(1,248)
Other income (expense), net	57	65	195	165
Total other income and (expense)	(329)	(292)	(984)	(850)
Earnings (Loss) Before Income Taxes	1,845	1,699	2,629	744
Income taxes	623	590	598	317
Consolidated net income (loss)	1,222	1,109	2,031	427
Dividends on preferred and preference stock of subsidiaries	4	10	12	32
Net income attributable to noncontrolling interests	54	30	71	48
Net Income (Loss)	$ 1,164	$ 1,069	$ 1,948	$ 347
Earnings per share -
Basic (in dollars per share)	$ 1.14	$ 1.07	$ 1.92	$ 0.35
Diluted (in dollars per share)	$ 1.13	$ 1.06	$ 1.91	$ 0.35
Average number of shares of common stock outstanding (in millions)
Basic (in shares)	1,023	1,003	1,016	998
Diluted (in shares)	1,029	1,010	1,021	1,005
Cash dividends paid per share of common stock (in dollars per share)	$ 0.60	$ 0.58	$ 1.78	$ 1.72
Retail electric revenues
Operating Revenues:
Total operating revenues	$ 4,605	$ 4,615	$ 11,913	$ 11,786
Wholesale electric revenues
Operating Revenues:
Total operating revenues	693	718	1,923	1,867
Other electric revenues
Operating Revenues:
Total operating revenues	170	168	509	510
Natural gas
Operating Revenues:
Total operating revenues	492	532	2,806	2,746
Operating Expenses:
Cost of goods and services sold	104	134	1,053	1,085
Alternative revenue programs
Operating Revenues:
Total operating revenues	5	0	(23)	9
Other
Operating Revenues:
Total operating revenues	199	168	1,007	494
Operating Expenses:
Cost of goods and services sold	120	90	688	293
Fuel
Operating Expenses:
Cost of goods and services sold	1,310	1,285	3,514	3,372
Purchased power
Operating Expenses:
Cost of goods and services sold	257	256	760	646
ALABAMA POWER CO
Operating Revenues:
Total operating revenues	1,740	1,740	4,716	4,606
Operating Expenses:
Other operations and maintenance	401	406	1,191	1,177
Depreciation and amortization	192	185	570	549
Taxes other than income taxes	97	93	289	284
Total operating expenses	1,179	1,139	3,403	3,203
Operating Income (Loss)	561	601	1,313	1,403
Other Income and (Expense):
Allowance for equity funds used during construction	16	11	43	27
Interest expense, net of amounts capitalized	(82)	(76)	(240)	(229)
Other income (expense), net	9	10	24	35
Total other income and (expense)	(57)	(55)	(173)	(167)
Earnings (Loss) Before Income Taxes	504	546	1,140	1,236
Income taxes	127	216	272	493
Consolidated net income (loss)	377	330	868	743
Dividends on preferred and preference stock of subsidiaries	4	5	11	14
Net Income (Loss)	373	325	857	729
ALABAMA POWER CO | Retail electric revenues
Operating Revenues:
Total operating revenues	1,584	1,595	4,208	4,155
ALABAMA POWER CO | Wholesale electric revenues
Operating Revenues:
Total operating revenues	74	77	213	210
ALABAMA POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Total operating revenues	14	18	96	83
ALABAMA POWER CO | Other
Operating Revenues:
Total operating revenues	68	50	199	158
ALABAMA POWER CO | Fuel
Operating Expenses:
Cost of goods and services sold	356	343	1,028	944
ALABAMA POWER CO | Purchased power
Operating Expenses:
Cost of goods and services sold	64	57	176	132
ALABAMA POWER CO | Purchased power, affiliates
Operating Expenses:
Cost of goods and services sold	69	55	149	117
GEORGIA POWER CO
Operating Revenues:
Total operating revenues	2,593	2,546	6,601	6,426
Operating Expenses:
Other operations and maintenance	460	430	1,325	1,248
Depreciation and amortization	232	225	690	669
Taxes other than income taxes	118	112	332	311
Estimated loss on plants under construction	0	0	1,060	0
Total operating expenses	1,602	1,529	5,569	4,305
Operating Income (Loss)	991	1,017	1,032	2,121
Other Income and (Expense):
Allowance for equity funds used during construction			50	29
Interest expense, net of amounts capitalized	(95)	(105)	(303)	(310)
Other income (expense), net	30	22	104	95
Total other income and (expense)	(65)	(83)	(199)	(215)
Earnings (Loss) Before Income Taxes	926	934	833	1,906
Income taxes	262	350	212	705
Consolidated net income (loss)	664	584	621	1,201
Dividends on preferred and preference stock of subsidiaries	0	4	0	13
Net Income (Loss)	664	580	621	1,188
GEORGIA POWER CO | Retail electric revenues
Operating Revenues:
Total operating revenues	2,425	2,402	6,112	5,995
GEORGIA POWER CO | Wholesale electric revenues
Operating Revenues:
Total operating revenues	43	45	123	124
GEORGIA POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Total operating revenues	4	6	17	23
GEORGIA POWER CO | Other
Operating Revenues:
Total operating revenues	121	93	349	284
GEORGIA POWER CO | Fuel
Operating Expenses:
Cost of goods and services sold	480	482	1,269	1,297
GEORGIA POWER CO | Purchased power
Operating Expenses:
Cost of goods and services sold	106	119	338	310
GEORGIA POWER CO | Purchased power, affiliates
Operating Expenses:
Cost of goods and services sold	206	161	555	470
GULF POWER CO
Operating Revenues:
Total operating revenues	414	437	1,106	1,144
Operating Expenses:
Other operations and maintenance	82	84	248	260
Depreciation and amortization	48	42	142	95
Taxes other than income taxes	33	33	91	88
Loss on Plant Scherer Unit 3	0	0	0	33
Total operating expenses	339	324	921	915
Operating Income (Loss)	75	113	185	229
Other Income and (Expense):
Interest expense, net of amounts capitalized	(13)	(13)	(39)	(37)
Other income (expense), net	(3)	3	0	7
Total other income and (expense)	(16)	(10)	(39)	(30)
Earnings (Loss) Before Income Taxes	59	103	146	199
Income taxes	(4)	40	(1)	78
Consolidated net income (loss)	63	63	147	121
Dividends on preferred and preference stock of subsidiaries	0	0	0	4
Net Income (Loss)	63	63	147	117
GULF POWER CO | Retail electric revenues
Operating Revenues:
Total operating revenues	341	375	932	972
GULF POWER CO | Wholesale electric revenues
Operating Revenues:
Total operating revenues	15	14	41	44
GULF POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Total operating revenues	40	28	83	75
GULF POWER CO | Other
Operating Revenues:
Total operating revenues	18	20	50	53
GULF POWER CO | Fuel
Operating Expenses:
Cost of goods and services sold	132	127	305	323
GULF POWER CO | Purchased power
Operating Expenses:
Cost of goods and services sold	44	38	135	116
MISSISSIPPI POWER CO
Operating Revenues:
Total operating revenues	358	341	956	915
Operating Expenses:
Other operations and maintenance	80	68	222	213
Depreciation and amortization	42	39	126	120
Taxes other than income taxes	28	25	83	77
Estimated loss on plants under construction	1	34	45	3,155
Total operating expenses	278	292	815	3,886
Operating Income (Loss)	80	49	141	(2,971)
Other Income and (Expense):
Allowance for equity funds used during construction	0	1	0	72
Interest expense, net of amounts capitalized	(19)	13	(59)	(23)
Other income (expense), net	0	1	28	4
Total other income and (expense)	(19)	15	(31)	53
Earnings (Loss) Before Income Taxes	61	64	110	(2,918)
Income taxes	14	24	23	(885)
Consolidated net income (loss)	47	40	87	(2,033)
Dividends on preferred and preference stock of subsidiaries	0	0	1	1
Net Income (Loss)	47	40	86	(2,034)
MISSISSIPPI POWER CO | Retail electric revenues
Operating Revenues:
Total operating revenues	254	243	660	665
MISSISSIPPI POWER CO | Wholesale electric revenues
Operating Revenues:
Total operating revenues	65	72	184	196
MISSISSIPPI POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Total operating revenues	28	21	81	40
MISSISSIPPI POWER CO | Other
Operating Revenues:
Total operating revenues	11	5	31	14
MISSISSIPPI POWER CO | Fuel
Operating Expenses:
Cost of goods and services sold	116	120	312	301
MISSISSIPPI POWER CO | Purchased power
Operating Expenses:
Cost of goods and services sold	11	6	27	20
SOUTHERN POWER CO
Operating Revenues:
Total operating revenues	635	618	1,699	1,597
Operating Expenses:
Other operations and maintenance	94	83	278	272
Depreciation and amortization	130	131	370	379
Taxes other than income taxes	12	13	36	37
Impairment charges	36	0	155	0
Total operating expenses	499	459	1,487	1,261
Operating Income (Loss)	136	159	212	336
Other Income and (Expense):
Interest expense, net of amounts capitalized	(45)	(47)	(138)	(144)
Other income (expense), net	17	3	22	3
Total other income and (expense)	(28)	(44)	(116)	(141)
Earnings (Loss) Before Income Taxes	108	115	96	195
Income taxes	(38)	(39)	(210)	(129)
Consolidated net income (loss)	146	154	306	324
Net income attributable to noncontrolling interests	54	30	71	48
Net Income (Loss)	92	124	235	276
SOUTHERN POWER CO | Wholesale electric revenues
Operating Revenues:
Total operating revenues	496	510	1,363	1,293
SOUTHERN POWER CO | Wholesale revenues, affiliates
Operating Revenues:
Total operating revenues	134	105	326	295
SOUTHERN POWER CO | Other
Operating Revenues:
Total operating revenues	5	3	10	9
SOUTHERN POWER CO | Fuel
Operating Expenses:
Cost of goods and services sold	190	189	511	460
SOUTHERN POWER CO | Purchased power
Operating Expenses:
Cost of goods and services sold	37	43	137	113
SOUTHERN Co GAS
Operating Revenues:
Total operating revenues	492	565	2,861	2,841
Operating Expenses:
Other operations and maintenance	216	206	730	675
Depreciation and amortization	119	125	374	370
Taxes other than income taxes	32	26	157	140
Gain on dispositions, net	(353)	0	(317)	0
Goodwill impairment	0	0	42	0
Total operating expenses	118	498	2,051	2,290
Operating Income (Loss)	374	67	810	551
Other Income and (Expense):
Earnings from equity method investments	34	32	108	100
Interest expense, net of amounts capitalized	(52)	(51)	(170)	(145)
Other income (expense), net	6	19	21	30
Total other income and (expense)	(12)	0	(41)	(15)
Earnings (Loss) Before Income Taxes	362	67	769	536
Income taxes	316	52	475	233
Consolidated net income (loss)	46	15	294	303
Net Income (Loss)	46	15	294	303
SOUTHERN Co GAS | Natural gas
Operating Revenues:
Total operating revenues	487	532	2,829	2,737
Operating Expenses:
Cost of goods and services sold	104	134	1,053	1,085
SOUTHERN Co GAS | Alternative revenue programs
Operating Revenues:
Total operating revenues	5	0	(23)	9
SOUTHERN Co GAS | Other
Operating Revenues:
Total operating revenues	0	33	55	95
Operating Expenses:
Cost of goods and services sold	$ 0	$ 7	$ 12	$ 20

XML

Condensed Consolidated Statements of Income (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Total operating revenues	$ 6,159	$ 6,201	$ 18,158	$ 17,403
Alternative revenue programs
Total operating revenues	5	0	(23)	9
SOUTHERN Co GAS
Total operating revenues	492	565	2,861	2,841
Excise taxes collected	9	9	83	75
SOUTHERN Co GAS | Alternative revenue programs
Total operating revenues	$ 5	$ 0	$ (23)	$ 9

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Net income (loss)	$ 1,222	$ 1,109	$ 2,031	$ 427
Qualifying hedges:
Changes in fair value, net of tax	(11)	25	(19)	54
Reclassification adjustment for amounts included in net income, net of tax	14	(17)	60	(59)
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	8	1	11	3
Total other comprehensive income (loss)	11	9	52	(2)
Comprehensive Income (Loss)	1,233	1,118	2,083	425
Less:
Dividends on preferred and preference stock of subsidiaries	4	10	12	32
Comprehensive income attributable to noncontrolling interests	54	30	71	48
Comprehensive Income (Loss) Attributable to Parent	1,175	1,078	2,000	345
ALABAMA POWER CO
Net income (loss)	377	330	868	743
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	1	1	3	3
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	1	1	3	3
Comprehensive Income (Loss)	378	331	871	746
Less:
Dividends on preferred and preference stock of subsidiaries	4	5	11	14
GEORGIA POWER CO
Net income (loss)	664	584	621	1,201
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	1	1	3	2
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	1	1	3	2
Comprehensive Income (Loss)	665	585	624	1,203
Less:
Dividends on preferred and preference stock of subsidiaries	0	4	0	13
GULF POWER CO
Net income (loss)	63	63	147	121
Qualifying hedges:
Changes in fair value, net of tax	0	0	0	(1)
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	0	0	0	(1)
Comprehensive Income (Loss)	63	63	147	120
Less:
Dividends on preferred and preference stock of subsidiaries	0	0	0	4
MISSISSIPPI POWER CO
Net income (loss)	47	40	87	(2,033)
Qualifying hedges:
Changes in fair value, net of tax	0	(1)	(1)	0
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	(1)	0	1
Comprehensive Income (Loss)	47	39	87	(2,032)
Less:
Dividends on preferred and preference stock of subsidiaries	0	0	1	1
SOUTHERN POWER CO
Net income (loss)	146	154	306	324
Qualifying hedges:
Changes in fair value, net of tax	(11)	25	(19)	58
Reclassification adjustment for amounts included in net income, net of tax	11	(20)	46	(68)
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)	0	5	28	(10)
Comprehensive Income (Loss)	146	159	334	314
Less:
Comprehensive income attributable to noncontrolling interests	54	30	71	48
Comprehensive Income (Loss) Attributable to Parent	92	129	263	266
SOUTHERN Co GAS
Net income (loss)	46	15	294	303
Qualifying hedges:
Changes in fair value, net of tax	0	0	2	(3)
Reclassification adjustment for amounts included in net income, net of tax	0	0	2	0
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	6	0	5	0
Total other comprehensive income (loss)	6	0	9	(3)
Comprehensive Income (Loss)	$ 52	$ 15	$ 303	$ 300

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Qualifying hedges:
Changes in fair value, tax	$ (4)	$ 15	$ (6)	$ 32
Reclassification adjustment for amounts included in net income, tax	5	(10)	21	(36)
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, tax	3	1	4	2
ALABAMA POWER CO
Qualifying hedges:
Reclassification adjustment for amounts included in net income, tax	0	1	1	2
GEORGIA POWER CO
Qualifying hedges:
Reclassification adjustment for amounts included in net income, tax	0	0	1	1
GULF POWER CO
Qualifying hedges:
Changes in fair value, tax	0	0	0	(1)
MISSISSIPPI POWER CO
Qualifying hedges:
Changes in fair value, tax	0	0	(1)	0
Reclassification adjustment for amounts included in net income, tax	0	0	0	0
SOUTHERN POWER CO
Qualifying hedges:
Changes in fair value, tax	(4)	15	(7)	35
Reclassification adjustment for amounts included in net income, tax	4	(12)	16	(42)
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	0	0	1	(2)
Reclassification adjustment for amounts included in net income, tax	0	0	1	0
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, tax	$ 2	$ 0	$ 2	$ (1)

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Operating Activities:
Net income (loss)	$ 2,031	$ 427
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	2,647	2,564
Deferred income taxes	(286)	15
Allowance for equity funds used during construction	(99)	(133)
Pension, postretirement, and other employee benefits	(60)	(64)
Settlement of asset retirement obligations	(160)	(137)
Estimated loss on Plant Vogtle Units 3 and 4	1,105	3,155
Stock based compensation expense	108	95
Estimated loss on plants under construction	1,081	3,148
Gain on dispositions, net	(324)	(22)
Impairment charges	197	0
Gain on dispositions, net	(317)	(19)
Goodwill impairment	42
Other, net	(21)	(80)
Changes in certain current assets and liabilities —
-Receivables	37	423
-Prepayments	14	(39)
-Natural gas for sale	87	0
-Other current assets	(90)	(66)
-Accounts payable	(248)	(467)
-Accrued taxes	839	157
-Accrued compensation	(138)	(230)
-Retail fuel cost over recovery	36	(211)
-Other current liabilities	(67)	(129)
Net cash provided from operating activities	5,584	5,251
Investing Activities:
Business acquisitions, net of cash acquired	(64)	(1,016)
Property additions	(5,793)	(5,242)
Nuclear decommissioning trust fund purchases	(846)	(585)
Nuclear decommissioning trust fund sales	840	580
Asset dispositions	2,773	66
Cost of removal, net of salvage	(252)	(208)
Change in construction payables, net	91	120
Investment in unconsolidated subsidiaries	(93)	(134)
Payments pursuant to LTSAs	(157)	(189)
Other investing activities	1	(77)
Net cash provided from (used for) investing activities	(3,500)	(6,685)
Financing Activities:
Increase (decrease) in notes payable, net	(1,225)	(515)
Proceeds —
Long-term debt	1,950	4,068
Common stock	878	613
Preferred stock	0	250
Short-term borrowings	3,150	1,263
Redemptions and repurchases —
Long-term debt	(4,498)	(1,981)
Preferred and preference stock	0	(150)
Short-term borrowings	(1,800)	(409)
Distributions to noncontrolling interests	(86)	(89)
Capital contributions from noncontrolling interests	1,333	79
Payment of common stock dividends	(1,805)	(1,716)
Other financing activities	(237)	(113)
Net cash provided from (used for) financing activities	(2,340)	1,300
Net Change in Cash, Cash Equivalents, and Restricted Cash	(256)	(134)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	2,147	1,992
Cash, Cash Equivalents, and Restricted Cash at End of Period	1,891	1,858
Cash paid (received) during the period for —
Interest, net of amounts capitalized	1,402	1,286
Income taxes, net	137	(187)
Noncash transactions — Accrued property additions at end of period	1,125	805
ALABAMA POWER CO
Operating Activities:
Net income (loss)	868	743
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	683	666
Deferred income taxes	104	260
Allowance for equity funds used during construction	(43)	(27)
Settlement of asset retirement obligations	(31)	(20)
Other, net	(6)	59
Changes in certain current assets and liabilities —
-Receivables	(207)	(163)
-Prepayments	(26)	(28)
-Materials and supplies	(69)	(29)
-Other current assets	66	33
-Accounts payable	(194)	(125)
-Accrued taxes	225	159
-Accrued compensation	(41)	(48)
-Retail fuel cost over recovery	0	(76)
-Other current liabilities	60	7
Net cash provided from operating activities	1,389	1,411
Investing Activities:
Property additions	(1,529)	(1,211)
Nuclear decommissioning trust fund purchases	(207)	(174)
Nuclear decommissioning trust fund sales	207	174
Cost of removal, net of salvage	(78)	(82)
Change in construction payables, net	30	105
Other investing activities	(23)	(29)
Net cash provided from (used for) investing activities	(1,600)	(1,217)
Proceeds —
Preferred stock	0	250
Capital contributions from parent company	495	337
Senior notes	500	550
Redemptions and repurchases —
Senior notes	0	(200)
Pollution control revenue bonds	0	(36)
Payment of common stock dividends	(602)	(536)
Other financing activities	(24)	(26)
Net cash provided from (used for) financing activities	369	339
Net Change in Cash, Cash Equivalents, and Restricted Cash	158	533
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	544	420
Cash, Cash Equivalents, and Restricted Cash at End of Period	702	953
Cash paid (received) during the period for —
Interest, net of amounts capitalized	220	217
Income taxes, net	30	146
Noncash transactions — Accrued property additions at end of period	275	189
GEORGIA POWER CO
Operating Activities:
Net income (loss)	621	1,201
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	854	821
Deferred income taxes	(185)	328
Allowance for equity funds used during construction	(50)	(29)
Pension, postretirement, and other employee benefits	(46)	(42)
Settlement of asset retirement obligations	(82)	(95)
Estimated loss on Plant Vogtle Units 3 and 4	1,060	0
Other, net	9	(51)
Changes in certain current assets and liabilities —
-Receivables	(205)	(254)
-Fossil fuel stock	70	(2)
-Prepaid income taxes	231	(5)
-Other current assets	(36)	(24)
-Accounts payable	109	(161)
-Accrued taxes	26	(52)
-Accrued compensation	(32)	(60)
-Retail fuel cost over recovery	0	(84)
-Other current liabilities	(111)	(11)
Net cash provided from operating activities	2,233	1,480
Investing Activities:
Property additions	(2,276)	(1,907)
Nuclear decommissioning trust fund purchases	(638)	(411)
Nuclear decommissioning trust fund sales	633	406
Asset dispositions	138	63
Cost of removal, net of salvage	(71)	(54)
Change in construction payables, net of joint owner portion	72	180
Payments pursuant to LTSAs	(52)	(59)
Other investing activities	(19)	(52)
Net cash provided from (used for) investing activities	(2,213)	(1,834)
Financing Activities:
Increase (decrease) in notes payable, net	102	(391)
Proceeds —
Short-term borrowings	0	700
Capital contributions from parent company	2,335	412
Senior notes	0	1,350
Other long-term debt	0	370
Redemptions and repurchases —
Senior notes	(1,000)	(450)
Pollution control revenue bonds	(469)	(65)
Other long-term debt	(100)	0
Short-term borrowings	(150)	(300)
Payment of common stock dividends	(1,043)	(961)
Premiums on redemption and repurchases of senior notes	(152)	0
Other financing activities	(15)	(48)
Net cash provided from (used for) financing activities	(492)	617
Net Change in Cash, Cash Equivalents, and Restricted Cash	(472)	263
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	852	3
Cash, Cash Equivalents, and Restricted Cash at End of Period	380	266
Cash paid (received) during the period for —
Interest, net of amounts capitalized	315	284
Income taxes, net	141	369
Noncash transactions — Accrued property additions at end of period	670	470
GULF POWER CO
Operating Activities:
Net income (loss)	147	121
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	147	100
Deferred income taxes	(45)	57
Loss on Plant Scherer Unit 3	0	33
Other, net	(10)	(5)
Changes in certain current assets and liabilities —
-Receivables	(5)	(65)
-Other current assets	9	18
-Accrued taxes	35	21
-Accrued compensation	(9)	(10)
-Over recovered regulatory clause revenues	39	(8)
-Other current liabilities	10	10
Net cash provided from operating activities	318	272
Investing Activities:
Property additions	(207)	(142)
Cost of removal, net of salvage	(18)	(16)
Change in construction payables, net	5	(9)
Other investing activities	(18)	(6)
Net cash provided from (used for) investing activities	(238)	(173)
Financing Activities:
Increase (decrease) in notes payable, net	5	(268)
Proceeds —
Common stock	0	175
Capital contributions from parent company	40	7
Senior notes	0	300
Redemptions and repurchases —
Preferred and preference stock	0	(150)
Senior notes	0	(85)
Payment of common stock dividends	(115)	(94)
Other financing activities	(1)	(3)
Net cash provided from (used for) financing activities	(71)	(118)
Net Change in Cash, Cash Equivalents, and Restricted Cash	9	(19)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	28	56
Cash, Cash Equivalents, and Restricted Cash at End of Period	37	37
Cash paid (received) during the period for —
Interest, net of amounts capitalized	26	24
Income taxes, net	28	19
Noncash transactions — Accrued property additions at end of period	31	25
MISSISSIPPI POWER CO
Operating Activities:
Net income (loss)	87	(2,033)
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	129	144
Deferred income taxes	420	(1,159)
Allowance for equity funds used during construction	0	(72)
Estimated loss on Plant Vogtle Units 3 and 4	45	3,155
Estimated loss on plants under construction	21	3,148
Other, net	5	(26)
Changes in certain current assets and liabilities —
-Receivables	(46)	438
-Fossil fuel stock	(2)	21
-Other current assets	(5)	(9)
-Accounts payable	(3)	(21)
-Accrued taxes	57	20
-Accrued compensation	(9)	(12)
-Over recovered regulatory clause revenues	20	(47)
-Other current liabilities	(18)	(31)
Net cash provided from operating activities	656	361
Investing Activities:
Property additions	(117)	(411)
Change in construction payables, net	(9)	(47)
Payments pursuant to LTSAs	(28)	(10)
Other investing activities	(16)	(15)
Net cash provided from (used for) investing activities	(170)	(483)
Financing Activities:
Increase (decrease) in notes payable, net	(4)	(23)
Proceeds —
Short-term borrowings	300	113
Capital contributions from parent company	(2)	1,002
Senior notes	600	0
Long-term debt to parent company	0	40
Redemptions and repurchases —
Pollution control revenue bonds	(43)	0
Other long-term debt	(900)	(300)
Short-term borrowings	(300)	(109)
Long-term debt to parent company	0	(591)
Other financing activities	(6)	(3)
Net cash provided from (used for) financing activities	(355)	129
Net Change in Cash, Cash Equivalents, and Restricted Cash	131	7
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	248	224
Cash, Cash Equivalents, and Restricted Cash at End of Period	379	231
Cash paid (received) during the period for —
Interest, net of amounts capitalized	57	45
Income taxes, net	(483)	(209)
Noncash transactions — Accrued property additions at end of period	23	32
SOUTHERN POWER CO
Operating Activities:
Net income (loss)	306	324
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	394	404
Deferred income taxes	(337)	240
Amortization of investment tax credits	(43)	(42)
Income taxes receivable, non-current	(12)	(42)
Impairment charges	155	0
Other, net	10	(4)
Changes in certain current assets and liabilities —
-Receivables	(41)	(77)
-Prepaid income taxes	5	24
-Other current assets	1	14
-Accounts payable	(27)	(31)
-Accrued taxes	256	79
-Other current liabilities	(1)	5
Net cash provided from operating activities	666	894
Investing Activities:
Business acquisitions, net of cash acquired	(64)	(1,016)
Property additions	(226)	(218)
Change in construction payables, net	3	(166)
Payments pursuant to LTSAs	(57)	(99)
Other investing activities	20	7
Net cash provided from (used for) investing activities	(324)	(1,492)
Financing Activities:
Increase (decrease) in notes payable, net	(68)	(89)
Proceeds —
Short-term borrowings	200	0
Other long-term debt	0	43
Redemptions and repurchases —
Senior notes	(350)	0
Other long-term debt	(420)	(4)
Return of capital	(650)	0
Distributions to noncontrolling interests	(86)	(89)
Capital contributions from noncontrolling interests	1,333	79
Payment of common stock dividends	(234)	(238)
Other financing activities	(15)	(27)
Net cash provided from (used for) financing activities	(290)	(325)
Net Change in Cash, Cash Equivalents, and Restricted Cash	52	(923)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	140	1,112
Cash, Cash Equivalents, and Restricted Cash at End of Period	192	189
Cash paid (received) during the period for —
Interest, net of amounts capitalized	138	144
Income taxes, net	(102)	(343)
Noncash transactions — Accrued property additions at end of period	37	16
SOUTHERN Co GAS
Operating Activities:
Net income (loss)	294	303
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	374	370
Deferred income taxes	(83)	265
Mark-to-market adjustments	23	(32)
Gain on dispositions, net	(317)	0
Goodwill impairment	42	0
Other, net	(41)	(46)
Changes in certain current assets and liabilities —
-Receivables	445	531
-Natural gas for sale	87	0
-Prepaid income taxes	(23)	(7)
-Other current assets	21	(42)
-Accounts payable	(59)	(169)
-Accrued taxes	(64)	(24)
-Accrued compensation	2	(11)
-Other current liabilities	35	8
Net cash provided from operating activities	736	1,146
Investing Activities:
Property additions	(1,029)	(1,093)
Asset dispositions	2,631	0
Cost of removal, net of salvage	(67)	(45)
Change in construction payables, net	(14)	49
Investment in unconsolidated subsidiaries	(90)	(128)
Other investing activities	18	28
Net cash provided from (used for) investing activities	1,449	(1,189)
Financing Activities:
Increase (decrease) in notes payable, net	(1,382)	(323)
Proceeds —
First mortgage bonds	100	200
Capital contributions from parent company	35	79
Senior notes	0	450
Redemptions and repurchases —
Long-term debt	(200)	0
Return of capital	(400)	0
Payment of common stock dividends	(351)	(332)
Other financing activities	(3)	(29)
Net cash provided from (used for) financing activities	(2,201)	45
Net Change in Cash, Cash Equivalents, and Restricted Cash	(16)	2
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	78	24
Cash, Cash Equivalents, and Restricted Cash at End of Period	62	26
Cash paid (received) during the period for —
Interest, net of amounts capitalized	175	146
Income taxes, net	682	17
Noncash transactions — Accrued property additions at end of period	$ 121	$ 112

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Interest capitalized	$ 53	$ 72
ALABAMA POWER CO
Interest capitalized	15	10
GEORGIA POWER CO
Interest capitalized	19	17
GULF POWER CO
Interest capitalized	0	0
MISSISSIPPI POWER CO
Interest paid	57	73
Interest capitalized	0	28
SOUTHERN POWER CO
Interest capitalized	14	7
SOUTHERN Co GAS
Interest capitalized	$ 5	$ 9

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 1,847	$ 2,130
Receivables —
Customer accounts receivable	1,730	1,806
Energy marketing receivables	498	607
Unbilled revenues	738	810
Under recovered fuel clause revenues	105	171
Other accounts and notes receivable	690	698
Accumulated provision for uncollectible accounts	(33)	(44)
Materials and supplies	1,418	1,438
Fossil fuel for generation	390	594
Natural gas for sale	486	595
Prepaid expenses	354	452
Other regulatory assets, current	522	604
Assets held for sale, current	407	12
Other current assets	232	199
Total current assets	9,384	10,072
Property, Plant, and Equipment:
In service	100,672	103,542
Less: Accumulated depreciation	30,739	31,457
Plant in service, net of depreciation	69,933	72,085
Nuclear fuel, at amortized cost	844	883
Construction work in progress	7,655	6,904
Total property, plant, and equipment	78,432	79,872
Other Property and Investments:
Goodwill	5,315	6,268
Equity investments in unconsolidated subsidiaries	1,569	1,513
Other intangible assets, net of amortization	674	873
Nuclear decommissioning trusts, at fair value	1,872	1,832
Leveraged leases	794	775
Miscellaneous property and investments	258	249
Total other property and investments	10,482	11,510
Deferred Charges and Other Assets:
Deferred charges related to income taxes	792	825
Unamortized loss on reacquired debt	328	206
Other regulatory assets, deferred	6,196	6,943
Assets held for sale	4,667	0
Other deferred charges and assets	1,436	1,577
Total deferred charges and other assets	13,419	9,551
Total Assets	111,717	111,005
Current Liabilities:
Securities due within one year	3,013	3,892
Notes payable	2,564	2,439
Energy marketing trade payables	521	546
Accounts payable —
Accounts payable	2,246	2,530
Customer deposits	524	542
Accrued taxes —
Accrued taxes	1,060	636
Accrued interest	422	488
Accrued compensation	800	959
Asset retirement obligations, current	348	351
Other regulatory liabilities, current	349	337
Liabilities held for sale, current	355	0
Other current liabilities	763	874
Total current liabilities	12,965	13,594
Long-term Debt	41,425	44,462
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	6,035	6,842
Deferred credits related to income taxes	6,651	7,256
Accumulated deferred ITCs	2,377	2,267
Employee benefit obligations	2,017	2,256
Asset retirement obligations, deferred	5,817	4,473
Accrued environmental remediation	269	389
Other cost of removal obligations	2,330	2,684
Other regulatory liabilities, deferred	153	239
Liabilities held for sale	2,835	0
Other deferred credits and liabilities	454	691
Total deferred credits and other liabilities	28,938	27,097
Total Liabilities	83,328	85,153
Redeemable Preferred Stock of Subsidiaries	324	324
Common Stockholders' Equity:
Common stock	5,140	5,038
Paid-in capital	10,905	10,469
Treasury, at cost	(39)	(36)
Retained earnings (accumulated deficit)	9,048	8,885
Accumulated other comprehensive income (loss)	(177)	(189)
Total Common Stockholders' Equity	24,877	24,167
Noncontrolling interests	3,188	1,361
Total stockholders' equity	28,065	25,528
Total Liabilities and Stockholders' Equity	111,717	111,005
ALABAMA POWER CO
Current Assets:
Cash and cash equivalents	702	544
Receivables —
Customer accounts receivable	455	355
Unbilled revenues	159	162
Under recovered fuel clause revenues	48	0
Affiliated	68	43
Other accounts and notes receivable	54	55
Accumulated provision for uncollectible accounts	(9)	(9)
Materials and supplies	536	458
Fossil fuel for generation	117	184
Prepaid expenses	59	85
Other regulatory assets, current	141	124
Other current assets	8	5
Total current assets	2,338	2,006
Property, Plant, and Equipment:
In service	29,568	27,326
Less: Accumulated depreciation	9,932	9,563
Plant in service, net of depreciation	19,636	17,763
Nuclear fuel, at amortized cost	316	339
Construction work in progress	1,457	908
Total property, plant, and equipment	21,409	19,010
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	63	67
Nuclear decommissioning trusts, at fair value	938	903
Miscellaneous property and investments	127	124
Total other property and investments	1,128	1,094
Deferred Charges and Other Assets:
Deferred charges related to income taxes	236	239
Deferred under recovered regulatory clause revenues	88	54
Other regulatory assets, deferred	1,209	1,272
Other deferred charges and assets	202	189
Total deferred charges and other assets	1,735	1,754
Total Assets	26,610	23,864
Current Liabilities:
Securities due within one year	321	0
Accounts payable —
Affiliated	341	327
Other	425	585
Customer deposits	96	92
Accrued taxes —
Accrued income taxes	97	9
Other accrued taxes	132	45
Accrued interest	81	77
Accrued compensation	169	205
Asset retirement obligations, current	111	7
Other regulatory liabilities, current	57	1
Other current liabilities	46	52
Total current liabilities	1,876	1,400
Long-term Debt	7,803	7,628
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	2,882	2,760
Deferred credits related to income taxes	2,051	2,082
Accumulated deferred ITCs	107	112
Employee benefit obligations	283	304
Asset retirement obligations, deferred	3,090	1,702
Other cost of removal obligations	542	609
Other regulatory liabilities, deferred	52	84
Other deferred credits and liabilities	48	63
Total deferred credits and other liabilities	9,055	7,716
Total Liabilities	18,734	16,744
Redeemable Preferred Stock	291	291
Common Stockholders' Equity:
Common stock	1,222	1,222
Paid-in capital	3,490	2,986
Retained earnings (accumulated deficit)	2,902	2,647
Accumulated other comprehensive income (loss)	(29)	(26)
Total Common Stockholders' Equity	7,585	6,829
Total Liabilities and Stockholders' Equity	26,610	23,864
GEORGIA POWER CO
Current Assets:
Cash and cash equivalents	380	852
Receivables —
Customer accounts receivable	747	544
Unbilled revenues	245	255
Under recovered fuel clause revenues	105	165
Joint owner accounts receivable	208	262
Affiliated	39	24
Other accounts and notes receivable	96	76
Accumulated provision for uncollectible accounts	(3)	(3)
Materials and supplies	494	504
Fossil fuel for generation	244	314
Prepaid expenses	77	216
Other regulatory assets, current	199	205
Other current assets	91	14
Total current assets	2,922	3,428
Property, Plant, and Equipment:
In service	35,671	34,861
Less: Accumulated depreciation	12,029	11,704
Plant in service, net of depreciation	23,642	23,157
Nuclear fuel, at amortized cost	528	544
Construction work in progress	4,655	4,613
Total property, plant, and equipment	28,825	28,314
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	50	53
Nuclear decommissioning trusts, at fair value	933	929
Miscellaneous property and investments	61	59
Total other property and investments	1,044	1,041
Deferred Charges and Other Assets:
Deferred charges related to income taxes	519	516
Other regulatory assets, deferred	3,041	2,932
Other deferred charges and assets	510	548
Total deferred charges and other assets	4,070	3,996
Total Assets	36,861	36,779
Current Liabilities:
Securities due within one year	511	857
Notes payable	102	150
Accounts payable —
Affiliated	515	493
Other	909	834
Customer deposits	275	270
Accrued taxes —
Accrued taxes	345	344
Accrued interest	108	123
Accrued compensation	185	219
Asset retirement obligations, current	193	270
Other regulatory liabilities, current	151	191
Other current liabilities	180	198
Total current liabilities	3,474	3,949
Long-term Debt	9,863	11,073
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	2,999	3,175
Deferred credits related to income taxes	3,218	3,248
Accumulated deferred ITCs	264	248
Employee benefit obligations	650	659
Asset retirement obligations, deferred	2,401	2,368
Other deferred credits and liabilities	141	128
Total deferred credits and other liabilities	9,673	9,826
Total Liabilities	23,010	24,848
Common Stockholders' Equity:
Common stock	398	398
Paid-in capital	9,670	7,328
Retained earnings (accumulated deficit)	3,792	4,215
Accumulated other comprehensive income (loss)	(9)	(10)
Total Common Stockholders' Equity	13,851	11,931
Total Liabilities and Stockholders' Equity	36,861	36,779
GULF POWER CO
Current Assets:
Cash and cash equivalents	37	28
Receivables —
Customer accounts receivable	100	76
Unbilled revenues	69	67
Under recovered fuel clause revenues	0	27
Affiliated	20	14
Other accounts and notes receivable	5	7
Accumulated provision for uncollectible accounts	(1)	(1)
Materials and supplies	61	57
Fossil fuel for generation	58	63
Other regulatory assets, current	47	56
Other current assets	13	21
Total current assets	409	415
Property, Plant, and Equipment:
In service	5,313	5,196
Less: Accumulated depreciation	1,540	1,461
Plant in service, net of depreciation	3,773	3,735
Construction work in progress	152	91
Total property, plant, and equipment	3,925	3,826
Deferred Charges and Other Assets:
Deferred charges related to income taxes	30	31
Other regulatory assets, deferred	495	502
Other deferred charges and assets	46	23
Total deferred charges and other assets	571	556
Total Assets	4,905	4,797
Current Liabilities:
Notes payable	50	45
Accounts payable —
Affiliated	64	52
Other	67	75
Customer deposits	35	35
Accrued taxes —
Accrued taxes	45	10
Accrued interest	20	9
Accrued compensation	30	39
Deferred capacity expense, current	22	22
Asset retirement obligations, current	43	37
Other regulatory liabilities, current	69	0
Other current liabilities	20	27
Total current liabilities	465	351
Long-term Debt	1,285	1,285
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	542	537
Deferred credits related to income taxes	380	458
Employee benefit obligations	96	102
Deferred capacity expense	81	97
Asset retirement obligations, deferred	121	105
Other cost of removal obligations	218	221
Other regulatory liabilities, deferred	51	43
Other deferred credits and liabilities	62	67
Total deferred credits and other liabilities	1,551	1,630
Total Liabilities	3,301	3,266
Common Stockholders' Equity:
Common stock	678	678
Paid-in capital	636	594
Retained earnings (accumulated deficit)	291	259
Accumulated other comprehensive income (loss)	(1)	0
Total Common Stockholders' Equity	1,604	1,531
Total Liabilities and Stockholders' Equity	4,905	4,797
MISSISSIPPI POWER CO
Current Assets:
Cash and cash equivalents	379	248
Receivables —
Customer accounts receivable	49	36
Unbilled revenues	43	41
Income taxes receivable, current	3	4
Affiliated	35	16
Other accounts and notes receivable	47	12
Materials and supplies	52	44
Fossil fuel for generation	19	17
Other regulatory assets, current	110	125
Other current assets	4	9
Total current assets	741	552
Property, Plant, and Equipment:
In service	4,819	4,773
Less: Accumulated depreciation	1,389	1,325
Plant in service, net of depreciation	3,430	3,448
Construction work in progress	106	84
Total property, plant, and equipment	3,536	3,532
Other Property and Investments:
Total other property and investments	24	30
Deferred Charges and Other Assets:
Deferred charges related to income taxes	34	35
Other regulatory assets, deferred	466	437
Accumulated deferred income taxes	0	247
Other deferred charges and assets	16	33
Total deferred charges and other assets	516	752
Total Assets	4,817	4,866
Current Liabilities:
Securities due within one year	204	989
Notes payable	0	4
Accounts payable —
Affiliated	55	59
Other	90	96
Accrued taxes —
Accrued income taxes	75	40
Other accrued taxes	74	101
Accrued interest	21	16
Accrued compensation	30	39
Accrued plant closure costs	30	35
Asset retirement obligations, current	41	37
Other current liabilities	56	47
Total current liabilities	676	1,463
Long-term Debt	1,532	1,097
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	193	0
Deferred credits related to income taxes	420	372
Employee benefit obligations	111	116
Asset retirement obligations, deferred	136	137
Other cost of removal obligations	181	178
Other regulatory liabilities, deferred	75	79
Other deferred credits and liabilities	17	33
Total deferred credits and other liabilities	1,133	915
Total Liabilities	3,341	3,475
Redeemable Preferred Stock	33	33
Common Stockholders' Equity:
Common stock	38	38
Paid-in capital	4,528	4,529
Retained earnings (accumulated deficit)	(3,119)	(3,205)
Accumulated other comprehensive income (loss)	(4)	(4)
Total Common Stockholders' Equity	1,443	1,358
Total Liabilities and Stockholders' Equity	4,817	4,866
SOUTHERN POWER CO
Current Assets:
Cash and cash equivalents	192	129
Receivables —
Customer accounts receivable	150	117
Affiliated	71	50
Other accounts and notes receivable	62	98
Materials and supplies	214	278
Prepaid income taxes	44	50
Assets held for sale, current	18	1
Other current assets	29	35
Total current assets	780	758
Property, Plant, and Equipment:
In service	13,603	13,755
Less: Accumulated depreciation	2,087	1,910
Plant in service, net of depreciation	11,516	11,845
Construction work in progress	586	511
Total property, plant, and equipment	12,102	12,356
Other Property and Investments:
Intangible assets, net of amortization	391	411
Total other property and investments	391	411
Deferred Charges and Other Assets:
Prepaid LTSAs	106	118
Accumulated deferred income taxes	1,281	925
Income taxes receivable, non-current	84	72
Assets held for sale	185	0
Other deferred charges and assets	426	566
Total deferred charges and other assets	2,082	1,681
Total Assets	15,355	15,206
Current Liabilities:
Securities due within one year	0	770
Notes payable	237	105
Accounts payable —
Affiliated	86	102
Other	88	103
Accrued taxes —
Accrued income taxes	233	0
Liabilities held for sale, current	4	0
Other current liabilities	165	152
Total current liabilities	813	1,232
Long-term Debt	5,029	5,071
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	111	199
Accumulated deferred ITCs	1,842	1,884
Other deferred credits and liabilities	259	322
Total deferred credits and other liabilities	2,212	2,405
Total Liabilities	8,054	8,708
Common Stockholders' Equity:
Common stock	0	0
Paid-in capital	2,604	3,662
Retained earnings (accumulated deficit)	1,478	1,478
Accumulated other comprehensive income (loss)	31	(2)
Total Common Stockholders' Equity	4,113	5,138
Noncontrolling interests	3,188	1,360
Total stockholders' equity	7,301	6,498
Total Liabilities and Stockholders' Equity	15,355	15,206
SOUTHERN Co GAS
Current Assets:
Cash and cash equivalents	56	73
Receivables —
Customer accounts receivable	180	400
Energy marketing receivables	498	607
Unbilled revenues	58	285
Affiliated	23	12
Other accounts and notes receivable	110	91
Accumulated provision for uncollectible accounts	(18)	(28)
Natural gas for sale	486	595
Prepaid expenses	62	53
Assets from risk management activities, net of collateral	87	135
Other regulatory assets, current	72	94
Other current assets	88	78
Total current assets	1,702	2,395
Property, Plant, and Equipment:
In service	14,771	15,833
Less: Accumulated depreciation	4,351	4,596
Plant in service, net of depreciation	10,420	11,237
Construction work in progress	660	491
Total property, plant, and equipment	11,080	11,728
Other Property and Investments:
Goodwill	5,015	5,967
Equity investments in unconsolidated subsidiaries	1,529	1,477
Other intangible assets, net of amortization	113	280
Miscellaneous property and investments	20	21
Total other property and investments	6,677	7,745
Deferred Charges and Other Assets:
Other regulatory assets, deferred	721	901
Other deferred charges and assets	218	218
Total deferred charges and other assets	939	1,119
Total Assets	20,398	22,987
Current Liabilities:
Securities due within one year	515	157
Notes payable	136	1,518
Energy marketing trade payables	521	546
Accounts payable —
Affiliated	37	21
Other	346	425
Customer deposits	136	128
Accrued taxes —
Accrued income taxes	0	40
Other accrued taxes	61	78
Accrued interest	66	51
Accrued compensation	71	74
Liabilities from risk management activities, net of collateral	28	69
Other regulatory liabilities, current	132	135
Other current liabilities	122	159
Total current liabilities	2,171	3,401
Long-term Debt	5,393	5,891
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	944	1,089
Deferred credits related to income taxes	930	1,063
Employee benefit obligations	412	415
Accrued environmental remediation	269	342
Other cost of removal obligations	1,577	1,646
Other deferred credits and liabilities	79	118
Total deferred credits and other liabilities	4,211	4,673
Total Liabilities	11,775	13,965
Common Stockholders' Equity:
Common stock	0	0
Paid-in capital	8,863	9,214
Retained earnings (accumulated deficit)	(273)	(212)
Accumulated other comprehensive income (loss)	33	20
Total Common Stockholders' Equity	8,623	9,022
Total Liabilities and Stockholders' Equity	$ 20,398	$ 22,987

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Other intangible assets, amortization	$ 225	$ 186
Common stock, par value (in dollars per share)	$ 5	$ 5
Common stock, shares authorized (in shares)	1,500,000,000.0	1,500,000,000.0
Common stock, shares issued (in shares)	1,000,000,000	1,000,000,000
Treasury shares at cost (in shares)	1,000,000	900,000
ALABAMA POWER CO
Common stock, par value (in dollars per share)	$ 40	$ 40
Common stock, shares authorized (in shares)	40,000,000	40,000,000
Common stock, shares outstanding (in shares)	30,537,500	30,537,500
GEORGIA POWER CO
Common stock, shares authorized (in shares)	20,000,000	20,000,000
Common stock, shares outstanding (in shares)	9,261,500	9,261,500
GULF POWER CO
Common stock, shares authorized (in shares)	20,000,000	20,000,000
Common stock, shares outstanding (in shares)	7,392,717	7,392,717
MISSISSIPPI POWER CO
Common stock, shares authorized (in shares)	1,130,000	1,130,000
Common stock, shares outstanding (in shares)	1,121,000	1,121,000
SOUTHERN POWER CO
Other intangible assets, amortization	$ 66	$ 47
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,000,000	1,000,000
Common stock, shares outstanding (in shares)	1,000	1,000
SOUTHERN Co GAS
Other intangible assets, amortization	$ 133	$ 120
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	100,000,000	100,000,000
Common stock, shares outstanding (in shares)	100	100

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Introduction

9 Months Ended

Sep. 30, 2018

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, 2017 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 September 30, 2018 and 2017. 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

See Note 1 to the financial statements of the registrants under "Recently Issued Accounting Standards" in Item 8 of the Form 10-K for additional information.

Revenue

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry-specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. ASC 606 became effective on January 1, 2018 and the registrants adopted it using the modified retrospective method applied to open contracts and only to the version of the contracts in effect as of January 1, 2018. In accordance with the modified retrospective method, the registrants' previously issued financial statements have not been restated to comply with ASC 606 and the registrants did not have a cumulative-effect adjustment to retained earnings. The adoption of ASC 606 had no significant impact on the timing of revenue recognition compared to previously reported results; however, it requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers, which are included in Note (C).

ASC 606 provided additional clarity on financial statement presentation that resulted in reclassifications into other revenues and other operations and maintenance from other income/(expense), net at Alabama Power and Georgia Power related to certain unregulated sales of products and services. In addition, contract assets related to certain fixed retail revenues at Georgia Power and Southern Company's unregulated distributed generation business have been reclassified from unbilled revenue in accordance with the guidance in ASC 606. These reclassifications did not affect the timing or amount of revenues recognized or cash flows. ASC 606 also provided additional guidance on revenue recognized over time, resulting in a change in the timing of revenue recognized from guaranteed and fixed billing arrangements at Southern Company Gas. The changes in natural gas revenues recognized in the third quarter and year-to-date 2018 relate primarily to the seasonal nature of natural gas usage.

The net impact of accounting for revenue under ASC 606 decreased Southern Company's and Southern Company Gas' consolidated net income by $4 million for the three months ended September 30, 2018 and increased Southern Company's and Southern Company Gas' consolidated net income by $1 million for the nine months ended September 30, 2018.

The specific impacts of applying ASC 606 to revenues from contracts with customers on the financial statements of Southern Company, Alabama Power, Georgia Power, and Southern Company Gas compared to previously recognized guidance is shown below.

	For the Three Months Ended September 30, 2018							For the Nine Months Ended September 30, 2018
Condensed Statements of Income	As Reported		Balances Without Adoption of ASC 606		Effect of Change			As Reported		Balances Without Adoption of ASC 606		Effect of Change
	(in millions)							(in millions)
Southern Company
Natural gas revenues	$	492	$	497	$	(5	)	$	2,806	$	2,805	$	1
Other revenues	199		198		1			1,007		1,003		4
Other operations and maintenance	1,404		1,387		17			4,217		4,178		39
Operating income	2,174		2,195		(21		)	3,613		3,647		(34		)
Other income (expense), net	57		41		16			195		160		35
Earnings (loss) before income taxes	1,845		1,850		(5		)	2,629		2,628		1
Income taxes (benefit)	623		624		(1		)	598		598		—
Consolidated net income (loss)	1,222		1,226		(4		)	2,031		2,030		1
Consolidated net income (loss) attributable to Southern Company	1,164		1,168		(4		)	1,948		1,947		1
Alabama Power
Other revenues	$	68	$	59	$	9		$	199	$	173	$	26
Other operations and maintenance	401		390		11			1,191		1,159		32
Operating income	561		563		(2		)	1,313		1,319		(6		)
Other income (expense), net	9		7		2			24		18		6
Georgia Power
Other revenues	$	121	$	97	$	24		$	349	$	287	$	62
Other operations and maintenance	460		437		23			1,325		1,268		57
Operating income (loss)	991		990		1			1,032		1,027		5
Other income (expense), net	30		31		(1		)	104		109		(5		)
Southern Company Gas
Natural gas revenues	$	487	$	492	$	(5	)	$	2,829	$	2,828	$	1
Operating income	374		379		(5		)	810		809		1
Earnings before income taxes	362		367		(5		)	769		768		1
Income taxes	316		317		(1		)	475		475		—
Net income (loss)	46		50		(4		)	294		293		1

	For the Nine Months Ended September 30, 2018
Condensed Statements of Cash Flows	As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)
Southern Company
Consolidated net income	$	2,031		$	2,030		$	1
Changes in certain current assets and liabilities:
Receivables	37			27			10
Other current assets	(90		)	(80		)	(10		)
Other current liabilities	(67		)	(68		)	1
Georgia Power
Changes in certain current assets and liabilities:
Receivables	$	(205	)	$	(242	)	$	37
Other current assets	(36		)	1			(37		)
Southern Company Gas
Net income	$	294		$	293		$	1
Changes in certain current assets and liabilities:
Other current liabilities	35			34			1

	At September 30, 2018
Condensed Balance Sheets	As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)
Southern Company
Unbilled revenues	$	738		$	776		$	(38	)
Other accounts and notes receivable	690			691			(1		)
Other current assets	232			193			39
Other current liabilities	763			764			(1		)
Retained earnings	9,048			9,047			1
Georgia Power
Unbilled revenues	$	245		$	310		$	(65	)
Other accounts and notes receivable	96			97			(1		)
Other current assets	91			25			66
Southern Company Gas
Other current liabilities	122			123			(1		)
Accumulated deficit	(273		)	(274		)	1

Other

In 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statements of cash flows. In addition, the net change in cash and cash equivalents during the period includes amounts generally described as restricted cash or restricted cash equivalents. The registrants adopted ASU 2016-18 effective January 1, 2018 with no material impact on their financial statements. Southern Company, Southern Power, and Southern Company Gas retrospectively applied ASU 2016-18 effective January 1, 2018 and have restated prior periods in the statements of cash flows by immaterial amounts. The change in restricted cash in the statements of cash flows was previously disclosed in operating activities for Southern Company and Southern Company Gas and in investing activities for Southern Company and Southern Power. See "Restricted Cash" herein for additional information.

In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the statements of income outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. The registrants adopted ASU 2017-07 effective January 1, 2018 with no material impact on their financial statements. ASU 2017-07 has been applied retrospectively for the presentation of the service cost component and the other components of net periodic benefit costs in the statements of income for Southern Company, the traditional electric operating companies, and Southern Company Gas. Since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017, no retrospective presentation of Southern Power's net periodic benefits costs is required. The requirement to limit capitalization to the service cost component of net periodic benefit costs has been applied on a prospective basis from the date of adoption for all registrants. The presentation changes resulted in a decrease in operating income and an increase in other income for the three and nine months ended September 30, 2018 and 2017 for Southern Company, the traditional electric operating companies, and Southern Company Gas.

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12). ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The registrants adopted ASU 2017-12 effective January 1, 2018 with no material impact on their financial statements. See Note (I) for disclosures required by ASU 2017-12.

On February 14, 2018, the FASB issued ASU No. 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (ASU 2018-02) to address the application of ASC 740, Income Taxes (ASC 740) to certain provisions of the Tax Reform Legislation. ASU 2018-02 specifically addresses the ASC 740 requirement that the effect of a change in tax laws or rates on deferred tax assets and liabilities be included in income from continuing operations, even when the tax effects were initially recognized directly in OCI at the previous rate, which strands the income tax rate differential in accumulated OCI. The amendments in ASU 2018-02 allow a reclassification from accumulated OCI to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. The registrants adopted ASU 2018-02 effective January 1, 2018 with no material impact on their financial statements.

Asset Retirement Obligations

See Note 1 to the financial statements of Southern Company and the traditional electric operating companies under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information regarding each company's AROs and the EPA's Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule).

As of September 30, 2018, details of the AROs, including those related to the CCR Rule, included in the condensed balance sheets of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power were as follows:

	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Balance at December 31, 2017	$	4,824		$	1,709		$	2,638		$	142		$	174
Liabilities incurred	2			—			—			—			—
Liabilities settled	(160		)	(31		)	(82		)	(23		)	(22		)
Accretion	153			72			70			3			4
Cash flow revisions	1,510			1,451			(32		)	42			21
Reclassification to held for sale	(164		)	—			—			—			—
Balance at September 30, 2018	$	6,165		$	3,201		$	2,594		$	164		$	177

In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related to the CCR Rule. Mississippi Power also recorded an increase of approximately $11 million to its AROs related to an ash pond at Plant Greene County, which is jointly-owned with Alabama Power. The revised cost estimates were based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power, including Plant Greene County. During the second quarter 2018, Alabama Power's management completed its analysis of these studies which indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology. As the level of work becomes more defined in the next 12 months, it is likely that these cost estimates will change and the change could be material.

Georgia Power continues to perform engineering studies related to its plans to close the ash ponds at all of its generating plants, including Plant Scherer Unit 3, which is jointly owned with Gulf Power, in compliance with federal and state CCR rules. Georgia Power also continues to refine its closure strategy and cost estimates for each ash pond and is preparing permit applications as required by the State of Georgia CCR rule. While Georgia Power and Gulf Power believe their recorded liabilities for ash pond closures appropriately reflect their obligations under the current closure strategies they have elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase their ARO liabilities. It is not currently possible to quantify the impacts of any increase related to a change in closure strategies and/or ongoing engineering studies for the current closure strategies, and the timing of future cash outflows is indeterminable at this time; however, the impact on Georgia Power's and Gulf Power's ARO liabilities is expected to be material. As permit applications advance, engineering studies continue, and the timing of individual ash pond closures develops further during the fourth quarter 2018, Georgia Power and Gulf Power will record any necessary changes to their ARO liabilities.

The traditional electric operating companies expect to continue to periodically update their ARO cost estimates, which could increase further, as additional information becomes available. 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 this matter cannot be determined at this time.

In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in an increase in Southern Company's and Alabama Power's ARO liability of approximately $300 million. See "Nuclear Decommissioning" below for additional information.

Georgia Power expects to complete updated decommissioning cost site studies for Plant Hatch and Plant Vogtle Units 1 and 2 in the fourth quarter 2018, which could result in additional changes to Southern Company's and Georgia Power's ARO liability. The ultimate outcome of these studies cannot be determined at this time.

The reclassification of a portion of the ARO liability to liabilities held for sale by Southern Company represents the AROs related to Gulf Power. See Note (J) under "Southern Company's Sale of Gulf Power" and "Assets Held for Sale" for additional information.

Nuclear Decommissioning

See Note 1 to the financial statements of Southern Company and Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated costs of decommissioning based on the 2018 site study are as follows:

Decommissioning periods:
Beginning year	2037
Completion year	2076
	(in millions)
Site study costs:
Radiated structures	$	1,621
Non-radiated structures	99
Total site study costs	$	1,720

The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.

For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and a trust earnings rate of 7.0%. The next site study is expected to be completed in 2023.

Amounts previously contributed to the external trust funds are currently projected to be adequate to meet the updated decommissioning obligations. Alabama Power will continue to provide site specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with the NRC and other applicable requirements.

Goodwill and Other Intangible Assets

The following table presents year-to-date changes in goodwill balances for Southern Company and Southern Company Gas:

	Goodwill
	Southern Company				Southern Company Gas
					Gas Distribution Operations			Gas Marketing Services			Total
	(in millions)
Balance at December 31, 2017	$	6,268			$	4,702		$	1,265		$	5,967
Impairment(a)	(42		)		—			(42		)	(42		)
Dispositions(b)	(910		)		(668		)	(242		)	(910		)
Balance at September 30, 2018	$	5,315		(c)	$	4,034		$	981		$	5,015

(a) On April 11, 2018, Southern Company Gas entered into a stock purchase agreement for the sale of Pivotal Home Solutions. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded in the first quarter 2018. See Note (J) under "Southern Company Gas" for additional information.

(b) Gas distribution operations reflects goodwill allocated to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold during the third quarter 2018. Gas marketing services reflects goodwill associated with Pivotal Home Solutions, which was sold on June 4, 2018. See Note (J) under "Southern Company Gas" for additional information.

(c) Total does not add due to rounding.

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.

Other intangible assets were as follows:

	At September 30, 2018							At December 31, 2017
	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(*)	$	223	$	(87	)	$	136	$	288	$	(83	)	$	205
Trade names(*)	70		(18		)	52		159		(17		)	142
Storage and transportation contracts	64		(49		)	15		64		(34		)	30
PPA fair value adjustments	456		(66		)	390		456		(47		)	409
Other	11		(5		)	6		17		(5		)	12
Total other intangible assets subject to amortization	$	824	$	(225	)	$	599	$	984	$	(186	)	$	798
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—			75		75		—			75
Total other intangible assets	$	899	$	(225	)	$	674	$	1,059	$	(186	)	$	873
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	456	$	(66	)	$	390	$	456	$	(47	)	$	409
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services(*)
Customer relationships	$	156	$	(78	)	$	78	$	221	$	(77	)	$	144
Trade names	26		(6		)	20		115		(9		)	106
Wholesale gas services
Storage and transportation contracts	64		(49		)	15		64		(34		)	30
Total other intangible assets subject to amortization	$	246	$	(133	)	$	113	$	400	$	(120	)	$	280

(*) Balances as of September 30, 2018 reflect Southern Company Gas' sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Nine Months Ended
	September 30, 2018
	(in millions)
Southern Company	$	21	$	70
Southern Power	$	6	$	19
Southern Company Gas	$	12	$	42

Restricted Cash

The registrants adopted ASU 2016-18 as of January 1, 2018. See "Recently Adopted Accounting Standards – Other" herein for additional information.

At December 31, 2017, Southern Power had restricted cash primarily related to certain acquisitions and construction projects. At both September 30, 2018 and December 31, 2017, 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 September 30, 2018 and/or December 31, 2017:

	Southern Company			Southern Company Gas
	(in millions)
At September 30, 2018
Cash and cash equivalents	$	1,847		$	56
Cash and cash equivalents classified as assets held for sale	37			—
Restricted cash:
Other accounts and notes receivable	6			6
Total cash, cash equivalents, and restricted cash	$	1,891	(*)	$	62

(*) Total does not add due to rounding.

	Southern Company		Southern Power		Southern Company Gas
	(in millions)
At December 31, 2017
Cash and cash equivalents	$	2,130	$	129	$	73
Restricted cash:
Other accounts and notes receivable	5		—		5
Deferred charges and other assets	12		11		—
Total cash, cash equivalents, and restricted cash	$	2,147	$	140	$	78

Natural Gas for Sale

Southern Company Gas' natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a WACOG basis.

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. Southern Company Gas had no inventory decrement at September 30, 2018. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's or Southern Company Gas' net income.

Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower of weighted average cost or current market price, with cost determined 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 had no material LOCOM adjustment in any period presented.

Hypothetical Liquidation at Book Value

Southern Power has consolidated renewable generation projects that are partially funded by a third-party tax equity investor. The related contractual provisions represent profit-sharing arrangements because the allocations of cash distributions and tax benefits are not based on fixed ownership percentages. Therefore, the noncontrolling interest is accounted for under a balance sheet approach utilizing the hypothetical liquidation at book value (HLBV) method. The HLBV method calculates each partner's share of income based on the change in net equity the partner can legally claim in a hypothetical liquidation at the end of the period compared to the beginning of the period.

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Contingencies and Regulatory Matters

9 Months Ended

Sep. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

CONTINGENCIES AND REGULATORY MATTERS

CONTINGENCIES AND REGULATORY MATTERS

See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.

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 predicted 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, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In June 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. In July 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition in September 2017. On March 29, 2018, the U.S. District Court for the Northern District of Georgia, Atlanta Division, issued an order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers of Southern Company and Mississippi Power and dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. On April 26, 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. On August 10, 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal.

In February 2017, Jean Vineyard filed a shareholder derivative lawsuit and, in May 2017, Judy Mesirov filed a shareholder derivative lawsuit, each in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. In August 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On April 25, 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.

In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On May 4, 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.

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

Alabama Power

On March 2, 2018, the Alabama Department of Environmental Management (ADEM) issued proposed administrative orders assessing a penalty of $1.25 million to Alabama Power for unpermitted discharge of fluids and/or pollutants to groundwater at five electric generating plants. The orders were finalized and Alabama Power paid the penalty on September 27, 2018. This matter is now concluded.

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 municipal franchise fees (all of which are remitted 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 August 2017. On June 18, 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. On August 27, 2018, Georgia Power filed a motion to stay the case and requested the trial court refer the case to the Georgia PSC for a declaratory ruling. Georgia Power believes the plaintiffs' claims have no merit and will continue to vigorously defend itself in this matter. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether any class will ultimately be certified; the scope of such a class, if certified; 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 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled to include, among other things, Southern Company as a defendant. The individual plaintiff alleged that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches unjustly enriched Mississippi Power and Southern Company. The plaintiffs sought unspecified actual damages and punitive damages; asked the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; asked the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and sought attorney's fees, costs, and interest. The plaintiffs also sought an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. In June 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. In July 2017, the plaintiffs filed notice of an appeal. On July 13, 2018, Mississippi Power and Southern Company reached a settlement agreement with the plaintiffs and the plaintiffs' appeal was dismissed with prejudice. The settlement had no material impact on Southern Company's or Mississippi Power's financial statements.

On May 18, 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in September 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. 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. Southern Company and Mississippi Power will vigorously defend themselves in this matter, the ultimate outcome of which cannot be determined at this time.

On May 14, 2018, Mississippi Power's claim for lost revenue resulting from the Deepwater Horizon oil spill in the Gulf of Mexico in 2010 was settled. The settlement proceeds of $18 million, net of expenses and income tax, are included in Southern Company's and Mississippi Power's earnings for the nine months ended September 30, 2018.

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 November 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 May 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, (State Court lawsuit) against XL Insurance America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from the hail storm and McCarthy's installation practices. On June 1, 2018, the court in the State Court lawsuit granted Roserock's motion for partial summary judgment, finding that the insurers were in breach of contract and in violation of the Texas Insurance Code for failing to pay any monies owed for the hail claim. In addition to the State Court lawsuit, lawsuits were filed between Roserock and McCarthy, as well as other parties, and that litigation has been consolidated in the U.S. District Court for the Western District of Texas. Southern Power intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.

Southern Company Gas

Nicor Energy Services Company, doing business as Pivotal Home Solutions, formerly a wholly-owned subsidiary of Southern Company Gas, was a defendant in a putative class action initially filed in 2017 in the state court in Indiana. The plaintiffs purported to represent a class of the customers who purchased products from Nicor Energy Services Company and alleged that the marketing, sale, and billing of the products violated the Indiana Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. In 2018, Nicor Energy Services Company was named in a second class action filed in the state court of Ohio asserting nearly identical allegations and legal claims. The plaintiffs sought, on behalf of the classes they purported to represent, actual and punitive damages, interest costs, attorney fees, and injunctive relief. To facilitate the sale of Pivotal Home Solutions, Southern Company Gas retained most of the financial responsibility for these lawsuits following the completion of the sale. On June 12, 2018, the parties settled these claims and Southern Company Gas recorded an $11 million charge, which is included in other operations and maintenance expenses for the nine months ended September 30, 2018.

Environmental Matters

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 all received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.

Georgia Power's environmental remediation liability was $25 million and $22 million as of September 30, 2018 and December 31, 2017, 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.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $48 million and $52 million as of September 30, 2018 and December 31, 2017, respectively. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power's substations. The schedule for completion of the remediation projects is subject to FDEP approval.

At September 30, 2018, Southern Company Gas' environmental remediation liability was $294 million based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. At December 31, 2017, Southern Company Gas' total environmental remediation liability was $388 million, of which $85 million related to Elizabethtown Gas, which was sold on July 1, 2018. 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. See Note (J) under "Southern Company Gas" for information regarding Southern Company Gas' sale of Elizabethtown Gas.

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, Gulf Power, or Southern Company Gas.

FERC Matters

Market-Based Rate Authority

See Note 3 to the financial statements of Southern Company, the traditional electric operating companies, and Southern Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies'and Southern Power's 2014 and 2017 triennial market power analyses.

On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companiesand Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companiesand Southern Power made the compliance filing required by the order. These proceedings are concluded.

Open Access Transmission Tariff

On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companiesclaiming that the current11.25%base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies'open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than8.65%and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companiesfiled their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. On September 6, 2018, the FERC issued an order establishing a refund effective date of May 10, 2018 in the event a refund is due and initiating an investigation and settlement procedures regarding the current base ROE. Through September 30, 2018, the estimated maximum potential refund is not expected to be material to Southern Company's or the traditional electric operating companies' results of operations. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At September 30, 2018, the amount of over-recovered wholesale MRA fuel costs included in other regulatory liabilities, current on the condensed balance sheet was approximately $7 million compared to an immaterial amount at December 31, 2017. Under-recovered wholesale MB fuel costs included in the balance sheets were immaterial at September 30, 2018 and December 31, 2017.

Cooperative Energy Power Supply Agreement

See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Cooperative Energy Power Supply Agreement" in Item 8 of the Form 10-K for additional information regarding Cooperative Energy's network integration transmission service agreement (NITSA) with SCS.

On March 23, 2018, the FERC accepted the amendment to the NITSA between Cooperative Energy and SCS, effective April 1, 2018.

Regulatory Matters

Alabama Power

See Note 3 to the financial statements of Southern Company and Alabama Power under "Regulatory Matters – Alabama Power" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through various regulatory clauses and accounting orders. The balance of each regulatory clause recovery on the balance sheet follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2018		December 31, 2017
		(in millions)
Rate CNP Compliance	Deferred under recovered regulatory clause revenues	$	—	$	17
	Under recovered regulatory clause revenues	7		—
Rate CNP PPA	Deferred under recovered regulatory clause revenues	30		12
Retail Energy Cost Recovery	Deferred under recovered regulatory clause revenues	58		25
	Under recovered regulatory clause revenues	41		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	24		38

On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. At September 30, 2018, Alabama Power's equity ratio was approximately 47%.

Rate RSE

The approved modifications to Rate RSE became effective June 2018 and are applicable for January 2019 billings and thereafter. The modifications include reducing the top of the allowed weighted common equity return (WCER) range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range.

Generally, if Alabama Power's actual WCER range is between 6.15% and 7.65%, customers will receive 25% of the amount between 6.15% and 6.65%, 40% of the amount between 6.65% and 7.15%, and 75% of the amount between 7.15% and 7.65%. Customers will receive all amounts in excess of an actual WCER of 7.65%.

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

In accordance with an established retail tariff that provides for an interim adjustment to customer billings to recognize the impact of a change in the statutory income tax rate, Alabama Power has returned $151 million through September 30, 2018 and anticipates returning a total of approximately $257 million to retail customers through bill credits by December 31, 2018 as a result of the change in the federal income tax rate under the Tax Reform Legislation.

Rate ECR

On May 1, 2018, the Alabama PSC approved an increase to Rate ECR from 2.015 cents per KWH to 2.353 cents per KWH effective July 2018 which is expected to result in additional collections of approximately $100 million through December 31, 2018. The approved increase in the Rate ECR factor will have no significant effect on Alabama Power's net income, but will increase operating cash flows related to fuel cost recovery in 2018. Absent any further order from the Alabama PSC, in January 2019, the rate will return to the originally authorized 5.910 cents per KWH.

Accounting Order

On May 1, 2018, the Alabama PSC approved an accounting order that authorizes Alabama Power to defer the benefits of federal excess deferred income taxes associated with the Tax Reform Legislation for the year ending December 31, 2018 as a regulatory liability and to use up to $30 million of such deferrals to offset under recovered amounts under Rate ECR. Any remaining amounts will be used for the benefit of customers as determined by the Alabama PSC. As of September 30, 2018, Alabama Power had applied the full $30 million to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 5 to the financial statements of Southern Company and Alabama Power under "Federal Tax Reform Legislation" and of Alabama Power under "Current and Deferred Income Taxes" in Item 8 of the Form 10-K for additional information.

Plant Greene County

Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information regarding the joint ownership agreement. On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP) with the Mississippi PSC, which proposes a four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively. Mississippi Power's proposed Plant Greene County unit retirements would require the completion of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will monitor Mississippi Power's proposed RMP and associated regulatory process as well as the proposed transmission and system reliability improvements. Alabama Power will review all the facts and circumstances and will evaluate all its alternatives prior to reaching a final determination on the ongoing operations of Plant Greene County. The ultimate outcome of this matter cannot be determined at this time.

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 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 "Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Nuclear Construction" and Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also see "Fuel Cost Recovery" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" and Georgia Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery.

Rate Plans

See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's 2013 ARP and the Georgia PSC's 2018 order related to the Tax Reform Legislation.

On April 3, 2018, the Georgia PSC approved a settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation (Georgia Power Tax Reform Settlement Agreement). Pursuant to the Georgia Power Tax Reform Settlement Agreement, to reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power will refund to customers a total of $330 million through bill credits. Georgia Power issued bill credits of approximately $130 million in October 2018 and will issue bill credits of approximately $95 million in June 2019 and $105 million in February 2020. In addition, Georgia Power is deferring as a regulatory liability (i) the revenue equivalent of the tax expense reduction resulting from legislation lowering the Georgia state income tax rate from 6.00% to 5.75% in 2019 and (ii) the entire benefit of approximately $700 million in federal and state excess accumulated deferred income taxes. At September 30, 2018, Georgia Power's related regulatory liability balance totaled$655 million.The amortization of these regulatory liabilities is expected to be addressed in Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. If there is not a base rate case in 2019, customers will receive $185 million in annual bill credits beginning in 2020, with any additional federal and state income tax savings deferred as a regulatory liability, until Georgia Power's next base rate case.

To address the negative cash flow and credit metric impacts of the Tax Reform Legislation, the Georgia PSC also approved an increase in Georgia Power's retail equity ratio to the lower of (i) Georgia Power's actual common equity weight in its capital structure or (ii) 55%, until Georgia Power's next base rate case. At September 30, 2018, Georgia Power's actual retail common equity ratio (on a 13-month average basis) was approximately 53%. Benefits from reduced federal income tax rates in excess of the amounts refunded to customers will be retained by Georgia Power to cover the carrying costs of the incremental equity in 2018 and 2019.

Fuel Cost Recovery

As of September 30, 2018 and December 31, 2017, Georgia Power's under recovered fuel balance totaled $105 million and $165 million, respectively, and is included as under recovered fuel clause revenues on Southern Company's and Georgia Power's condensed balance sheets. On August 16, 2018, the Georgia PSC approved the deferral of Georgia Power's next fuel case to no later than March 16, 2020, with rates to be effective June 1, 2020. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million.

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 or Georgia Power's revenues or net income, but will affect cash flow.

Storm Damage Recovery

See Note 3 to the financial statements of Southern Company under "Regulatory Matters–Georgia Power– Storm Damage Recovery" and Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.

Georgia Power is accruing$30 millionannually through December 31, 2019, as provided in the 2013 ARP, for incremental operations and maintenance costs of damage from major storms to its transmission and distribution facilities. As of September 30, 2018, the total balance in Georgia Power's regulatory asset related to storm damage was$311 million. During October 2018, Hurricane Michael caused significant damage to Georgia Power's transmission and distribution facilities. Georgia Power currently estimates the costs of repairing the damage will total approximately$125 million to $150 million, which will be charged to Georgia Power's storm damage reserve or capitalized. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. The ultimate outcome of this matter cannot be determined at this time.

Gulf Power

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's rates and charges for service to retail customers.

Storm Damage Cost Recovery

See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the Form 10-K for information on how Gulf Power maintains a reserve for property damage to cover the cost of damages from major storms to its transmission and distribution lines and the cost of uninsured damages to its generating facilities and other property.

On October 10, 2018, Hurricane Michael made landfall on the Gulf Coast of Florida causing substantial damage in Gulf Power's service territory. Gulf Power currently estimates the costs of repairing the damages to its transmission and distribution lines and uninsured facilities will total approximately $350 million to $400 million, which primarily will be charged to Gulf Power's property damage reserve or capitalized. At September 30, 2018, Gulf Power had a balance of approximately $48 million in its property damage reserve. In accordance with the 2017 Gulf Power Rate Case Settlement Agreement, Gulf Power can petition the Florida PSC to seek recovery of the costs associated with Hurricane Michael, along with replenishing the property damage reserve to approximately $40 million. Any recovery from customers would begin, on an interim basis, 60 days following the filing of the cost recovery petition. The ultimate outcome of this matter cannot be determined at this time.

Retail Base Rate Case

See Note 3 to the financial statements of Southern Company and Gulf Power under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" and "Retail Regulatory Matters – Retail Base Rate Cases," respectively, in Item 8 of the Form 10-K for additional information.

As a continuation of a settlement agreement approved by the Florida PSC in April 2017 (2017 Gulf Power Rate Case Settlement Agreement), on March 26, 2018, the Florida PSC approved a stipulation and settlement agreement among Gulf Power and three intervenors addressing the retail revenue requirement effects of the Tax Reform Legislation (Gulf Power Tax Reform Settlement Agreement).

The Gulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates implemented April 1, 2018 and also provided for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through a reduced fuel cost recovery rate over the remainder of 2018. Through September 30, 2018, approximately $53 million of this refund has been reflected in customer bills. As a result of the Gulf Power Tax Reform Settlement Agreement, the Florida PSC also approved an increase in Gulf Power's maximum equity ratio from 52.5% to 53.5% for all retail regulatory purposes.

As part of the Gulf Power Tax Reform Settlement Agreement, a limited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was initiated on April 30, 2018. On October 30, 2018, the Florida PSC approved a $9.6 million annual reduction in base rate revenues effective January 2019, which concluded this proceeding. Through September 30, 2018, Gulf Power has deferred $7 million of related 2018 tax benefits as a regulatory liability to be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rate.

Cost Recovery Clauses

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders, as approved by the Florida PSC. Regulatory clause recovery balances included in the balance sheets are as follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2018		December 31, 2017
		(in millions)
Fuel Cost Recovery	Under recovered regulatory clause revenues	$	—	$	22
Fuel Cost Recovery	Other regulatory liabilities, current	23		—
Purchased Power Capacity Recovery	Other regulatory liabilities, current	4		—
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	—		2
Environmental Cost Recovery(*)	Other regulatory liabilities, current	13		—
Environmental Cost Recovery(*)	Under recovered regulatory clause revenues	—		2
Energy Conservation Cost Recovery	Other regulatory liabilities, current	2		—

(*) At September 30, 2018 and December 31, 2017, the over and under recovered balances, respectively, included in the balance sheets represents the current portion of the regulatory assets associated with projected environmental expenditures of approximately $8 million and $13 million, respectively, net of the over recovered environmental cost recovery balance of approximately $21 million and $11 million, respectively.

On November 5, 2018, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2019. The net effect of the approved changes is a $38 million decrease in annual revenues effective in January 2019, the majority of which will be offset by related expense decreases.

Mississippi Power

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.

On May 8, 2018, the Mississippi PSC issued an order to begin an operations review of Mississippi Power, which began in August 2018, with the final report expected by February 28, 2019. Mississippi Power expects that the review will include, but not be limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time.

Performance Evaluation Plan

In 2013, the Mississippi Public Utilities Staff (MPUS) contested Mississippi Power's PEP lookback filing for 2012, which indicated a refund due to customers of $5 million. In each of 2014, 2015, 2016, and 2017, Mississippi Power submitted its annual PEP lookback filing for the prior year, which for 2013 and 2014 each indicated no surcharge or refund and for each of 2015 and 2016 indicated a $5 million surcharge. Additionally, in July 2016, in November 2016, and on November 15, 2017, Mississippi Power submitted its annual projected PEP filings for 2016, 2017, and 2018, respectively, which for 2016 and 2017 indicated no change in rates and for 2018 indicated a rate increase of 4%, or $38 million in annual revenues. The Mississippi PSC suspended each of these filings to allow more time for review.

On February 7, 2018, Mississippi Power submitted its revised 2018 projected PEP filing to the Mississippi PSC, which reflected the impacts of the Tax Reform Legislation, requesting an increase in annual retail revenues of $26 million based on a performance-adjusted ROE of 9.33% and an increased equity ratio of 55%.

On March 22, 2018, Mississippi Power submitted its annual PEP lookback filing for 2017, which reflected no surcharge or refund.

On July 27, 2018, Mississippi Power and the MPUS entered into a settlement agreement with respect to the 2018 PEP filing and all unresolved PEP filings for prior years (PEP Settlement Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement became effective with the first billing cycle of September 2018. The PEP Settlement Agreement provides for an increase of approximately $21.6 million in annual base retail revenues, which excludes certain compensation costs contested by the MPUS, as well as approximately $2 million which was subsequently approved for recovery through the 2018 Energy Efficiency Cost Rider as discussed below. Under the PEP Settlement Agreement, Mississippi Power is deferring the contested compensation costs for 2018 and 2019 as a regulatory asset, which totaled $3 million as of September 30, 2018 and is included in other regulatory assets, deferred on Mississippi Power's condensed balance sheet. The Mississippi PSC is currently expected to rule on the appropriate treatment for such costs in connection with Mississippi Power's next base rate case, which is scheduled to be filed in the fourth quarter 2019 (2019 Base Rate Case). The ultimate outcome of this matter cannot be determined at this time.

Pursuant to the PEP Settlement Agreement, Mississippi Power's performance-adjusted allowed ROE is 9.31% and its allowed equity ratio remains at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power retained $44 million of excess accumulated deferred income taxes resulting from the Tax Reform Legislation, which had been proposed to be amortized beginning in 2018, until the conclusion of the 2019 Base Rate Case. Further, Mississippi Power will seek equity contributions sufficient to restore its equity ratio (which was 45% at September 30, 2018) to 50% by December 31, 2018. In the event Mississippi Power's actual average equity ratio for 2018 is more than 1% higher or lower than the 50% target, Mississippi Power will defer the corresponding difference in its revenue requirement as a regulatory asset or liability for resolution in the 2019 Base Rate Case. As of September 30, 2018, Mississippi Power has recorded $5 million in other regulatory liabilities, deferred on Mississippi Power's condensed balance sheet related to the estimated December 31, 2018 average equity ratio differential from target applicable to PEP.

Pursuant to the PEP Settlement Agreement, PEP proceedings are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolved all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power recognized revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.

Energy Efficiency

On May 8, 2018, the Mississippi PSC issued an order approving Mississippi Power's revised annual projected Energy Efficiency Cost Rider 2018 compliance filing, which increased annual retail revenues by approximately $3 million effective with the first billing cycle for June 2018.

Ad Valorem Tax Adjustment

On May 8, 2018, the Mississippi PSC also approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2018, which included an annual rate increase of 0.8%, or $7 million, in annual retail revenues effective with the first billing cycle for June 2018, primarily due to increased assessments.

Environmental Compliance Overview Plan

On August 3, 2018, Mississippi Power and the MPUS entered into a settlement agreement with respect to the 2018 ECO Plan filing (ECO Settlement Agreement), which provides for an increase of approximately $17 million in annual base retail revenues and was approved by the Mississippi PSC on August 7, 2018. Rates under the ECO Settlement Agreement became effective with the first billing cycle of September 2018 and will continue in effect until modified by the Mississippi PSC. These revenues are expected to be sufficient to recover the costs included in Mississippi Power's request for 2018, as well as the remaining deferred amounts that were originally expected to be recovered in 2019. In accordance with the ECO Settlement Agreement, ECO Plan proceedings are suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power is not required to make any ECO Plan filings for 2018, 2019, and 2020, with any necessary true-ups to be reflected in the 2019 Base Rate Case. The ECO Settlement Agreement contains the same terms as the PEP Settlement Agreement described herein with respect to allowed ROE and equity ratio. As of September 30, 2018, Mississippi Power has recorded $2 million in other regulatory liabilities, deferred on Mississippi Power's condensed balance sheet related to the estimated December 31, 2018 average equity ratio differential from target applicable to the ECO Plan.

Fuel Cost Recovery

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form10-K for additional information regarding Mississippi Power's retail fuel cost recovery.

At September 30, 2018, the amount of over-recovered retail fuel costs included on Mississippi Power's condensed balance sheet in customer accounts receivable was approximately $13 million compared to $6 million under recovered at December 31, 2017.

Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on Mississippi Power's revenues or net income, but will affect cash flow.

Southern Company Gas

See Note 3 to the financial statements of Southern Company and Southern Company Gas under "Regulatory Matters – Southern Company Gas" and "Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Southern Company Gas' regulatory matters.

Riders

On April 19, 2018, the Illinois Commission approved Nicor Gas' variable income tax adjustment rider. This rider provides for refund or recovery of changes in income tax expense that result from income tax rates that differ from those used in Nicor Gas' last rate case. Customer refunds, via bill credits, began on July 1, 2018 related to the impacts of the Tax Reform Legislation from January 25, 2018 through May 4, 2018. The impact of the Tax Reform Legislation subsequent to May 4, 2018 was addressed in Nicor Gas' approved rehearing request discussed herein under "Settled Base Rate Cases."

Natural Gas Cost Recovery

Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company's or Southern Company Gas' revenues or net income, but will affect cash flows.

Base Rate Cases

Settled Base Rate Cases

On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation. The Georgia PSC maintained Atlanta Gas Light's previously authorized earnings band based on a ROE between 10.55% and 10.95% and increased the allowed equity ratio by4% to an equity ratio of 55% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. Additionally, Atlanta Gas Light is required to file a traditional base rate case on or before June 1, 2019 for rates effective January 1, 2020.

On May 2, 2018, the Illinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately$44 million in annual base rate revenues became effective May 5, 2018. Nicor Gas' previously-authorized capital structure and ROE of9.8% were not addressed in the rehearing and remain unchanged. The impact of the Tax Reform Legislation prior to May 5, 2018 was addressed in the variable income tax rider discussed herein under "Riders."

On October 15, 2018, the Tennessee Public Utility Commission (PUC) approved a $1 million increase in Chattanooga Gas' annual base rate revenues, which was based on a projected test year ending June 30, 2019 and a ROE of 9.80%. The new rates became effective November 1, 2018.

Other

The Virginia Commission issued an order effective January 1, 2018 requiring utilities in the state to defer as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of the flowback of excess deferred income taxes. Through September 30, 2018, Virginia Natural Gas had deferred a total of $9 million. On August 30, 2018, Virginia Natural Gas filed an annual information form, which was subsequently revised on October 25, 2018, proposing to reduce annual base rates effective January 1, 2019 due to lower tax expense as a result of the lower corporate income tax rate and the impact of the flowback of excess deferred income taxes. This filing also proposes for Virginia Natural Gas to issue customer refunds, via bill credits, for the related amounts deferred as a regulatory asset. The Virginia Commission is expected to rule on the filing during the fourth quarter 2018. If approved as filed, Virginia Natural Gas' annual base rate revenues would be reduced by $14 million. The ultimate outcome of this matter cannot be determined at this time.

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. See Note 3 to the financial statements of Southern Company and Southern Company Gas under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" and "Regulatory Matters – Regulatory Infrastructure Programs," respectively, in Item 8 of the Form 10-K for additional information.

Atlanta Gas Light's Pipeline Replacement Program

One of the capital projects under Atlanta Gas Light's Pipeline Replacement Program experienced construction issues and Atlanta Gas Light was required to complete mitigation work prior to placing it in service. In the first quarter 2018, Atlanta Gas Light recovered $7 million from the final settlement of contractor litigation claims. Mitigation costs recovered through the legal process are retained by Atlanta Gas Light. For additional information on the Pipeline Replacement Program settlement, see Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters – PRP Settlement" in Item 8 of the Form 10-K.

Nuclear Construction

See Note 3 to the financial statements of Southern Company and Georgia Power under "Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, VCM reports, and the NCCR tariff.

In 2009, the Georgia PSC certified construction of 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 Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired in July 2017 when Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement. Under the Vogtle Services Agreement, Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

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

In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor.

Cost and Schedule

In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. 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 September 30, 2018(b)	(4.3		)
Remaining estimate to complete(a)	$	4.1

(a) Excludes financing costs expected to be capitalized through AFUDC of approximately $350 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 $3.2 billion, of which $1.8 billion had been incurred through September 30, 2018.

The table above reflects the $0.7 billion increase to the base capital cost forecast reported in the second quarter 2018 and is based on the cost reforecast performed prior to the nineteenth VCM filing, which primarily resulted from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.

Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power did not seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs) in the nineteenth VCM report that was filed with the Georgia PSC on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) in the second quarter 2018, which includes the total increase in the base capital cost forecast and construction contingency estimate.

As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets required to maintain the current project schedule continue to increase significantly through the remainder of 2018 and into 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers 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 resolution of Inspections, Tests, Analyses, and Acceptance Criteria (ITAAC) and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Joint Owner Contracts

In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective August 31, 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.

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

Amendments to the Vogtle Joint Ownership Agreements

In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners, and (ii) a term sheet (MEAG Term Sheet and, together with the Vogtle Owner Term Sheet, Term Sheets) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 (Project J) under certain circumstances. Pursuant to the Vogtle Owner Term Sheet, the Vogtle Joint Ownership Agreements will be modified as follows: (i) each Vogtle Owner will pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which forms the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million of additional construction costs; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests.

If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion. In this event, Georgia Power will have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Vogtle Owner. If Georgia Power accepts the offer to purchase a portion of another Vogtle Owner's ownership interest in Plant Vogtle Units 3 and 4, the ownership interest(s) to be conveyed from the tendering Vogtle Owner(s) to Georgia Power would be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Vogtle Owner(s) and by Georgia Power as of the commercial operation date of Plant Vogtle Unit 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Vogtle Owner in accordance with the second and third items described in the paragraph above would be treated as payments made by the applicable Vogtle Owner.

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

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

Georgia Power is working with the other Vogtle Owners to clarify any interpretive issues related to the operation of certain of the above provisions of the Vogtle Owner Term Sheet.

Under the Vogtle Owner Term Sheet, the provisions of the Vogtle Joint Ownership Agreements requiring that Vogtle Owners holding 90% of the ownership interests in Plant Vogtle Units 3 and 4 vote to continue construction following certain adverse events (Project Adverse Events) will be modified. Pursuant to the Vogtle Joint Ownership Agreements and the Vogtle Owner Term Sheet, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain Project Adverse Events occur, including: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Vogtle Owner Term Sheet provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more over the most recently approved schedule. Under the Vogtle Owner Term Sheet, Georgia Power may cancel the project at any time in its sole discretion.

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

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

Purchase of PTCs During Commercial Operation

In addition, under the terms of the Vogtle Owner Term Sheet, Georgia Power agreed to purchase additional PTCs from OPC, Dalton, MEAG SPVM, MEAG SPVP, and MEAG SPVJ (to the extent any MEAG SPVJ PTC rights remain after any purchases required under the MEAG Term Sheet as described below) at varying purchase prices dependent upon the actual cost to complete construction of Plant Vogtle Units 3 and 4 as compared to the EAC included in the nineteenth VCM report. The purchases will be at the option of the applicable Vogtle Owner and will occur during the month after such PTCs are earned.

Potential Funding to MEAG Project J

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

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

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

Under the terms of the MEAG Term Sheet, Georgia Power may decline to provide any funding in the form of advances, including in the event of a failure to receive any required Georgia PSC or DOE approvals, and cancel the project in lieu of providing such funding.

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. As of September 30, 2018, Georgia Power had recovered approximately $1.8 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. Georgia Power expects to file on November 9, 2018 to increase the NCCR tariff by approximately $90 million annually, effective January 1, 2019, pending Georgia PSC approval.

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) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying 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 $25 million in 2017 and are estimated to have negative earnings impacts of approximately $100 million in 2018 and an aggregate of $680 million from 2019 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.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. On March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's final decision and denial of Georgia Watch's motion for reconsideration. Georgia Power believes the two appeals have no merit; however, an adverse outcome in either 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.

The Georgia PSC has approved eighteen VCM reports covering the periods through December 31, 2017, including total construction capital costs incurred through that date of $4.9 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds). On August 31, 2018, Georgia Power filed its nineteenth VCM report with the Georgia PSC, which requested approval of $578 million of construction capital costs incurred from January 1, 2018 through June 30, 2018.

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

DOE Financing

As of September 30, 2018, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In September 2018, the DOE extended the conditional commitment to March 31, 2019. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions. See Note 6 to the financial statements of Southern Company and Georgia Power under "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 (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and conditions to borrowing.

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

Kemper County Energy Facility

For additional information on the Kemper County energy facility, see Note 3 to the financial statements of Southern Company and Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K.

As the mining permit holder for the Kemper County energy facility, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. Mine reclamation began in the first quarter 2018. See Note 1 to the financial statements of Southern Company and Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and of Mississippi Power under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.

As of September 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the third quarter 2018 and$45 million($34 millionafter tax) foryear-to-date 2018, primarily resulting from the abandonment and related closure activities 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 to cost up to$20 millionpre-tax (excluding salvage, net of dismantlement costs), may be incurred through the first half of 2020. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at$2 millionfor the remainder of 2018,$8 millionin 2019, and$4 millionannually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.

Reserve Margin Plan

On August 6, 2018, Mississippi Power filed its proposed RMP, as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costs related to the Kemper County energy facility. Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being thetwo-year and seven-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the four-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adverse impact on customer rates.

Other Matters

Investments in Leveraged Leases

See Note 1 to the financial statements of Southern Company under "Leveraged Leases" in Item 8 of the Form 10-K for additional information regarding the leveraged lease agreements of a subsidiary of Southern Company Holdings Inc. (Southern Holdings) and concerns about the financial and operational performance of one of the lessees and the associated generation assets.

The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. As a result of operational improvements in the first half of 2018, the June 2018 lease payment was paid in full and the December 2018 lease payment is currently expected to be paid in full. However, operational issues and the resulting cash liquidity challenges persist and significant concerns continue regarding the lessee's ability to make the remaining semi-annual lease payments. These operational challenges may also impact the expected residual value of the assets at the end of the lease term in 2047. If any future lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders would represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable, which would result in a reduction in net income of approximately $86 million after tax based on the lease receivable balance as of September 30, 2018. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired as of September 30, 2018. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments. The ultimate outcome of this matter cannot be determined at this time.

Natural Gas Storage

A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At September 30, 2018, the facility's property, plant, and equipment had a net book value of $110 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.

The cavern continues to maintain its pressures and overall structural integrity. Southern Company Gas intends to monitor the cavern and comply with the Louisiana DNR order through 2020 and place the cavern back in service in 2021. These events were considered in connection with Southern Company Gas' 2017 long-lived asset impairment analysis, which determined there was no impairment. Any future changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements and a material impact on Southern Company Gas' financial statements.

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Revenue from Contracts with Customers

9 Months Ended

Sep. 30, 2018

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, such as leases, derivatives, and certain cost recovery mechanisms. See Note (A) under "Recently Adopted Accounting Standards – Revenue" for additional information on the adoption of ASC 606 for revenue from contracts with customers.

The majority of the revenues of the traditional electric operating companies and Southern Company Gas are generated from contracts with retail electric and natural gas distribution customers. Revenues from this integrated service to deliver electricity or gas when and if called upon by the customer is recognized as a single performance obligation satisfied over time and is recognized at a tariff rate as electricity or gas is delivered to the customer during the month. The traditional electric operating companies and Southern Company Gas exclude taxes imposed on the customer and collected on behalf of governmental agencies to be remitted to these agencies from the transaction price in determining the revenue related to contracts with a customer.

The traditional electric operating companies and Southern Power also have contracts with multiple performance obligations, such as capacity and energy in a wholesale PPA, where the contract's total transaction price is allocated to each performance obligation based on the standalone selling price. The standalone selling price is primarily determined by the price charged to customers for the specific goods or services transferred with the performance obligations. Generally, the registrants recognize revenue as the performance obligations are satisfied over time as electricity or natural gas is delivered to the customer or as generation capacity is available to the customer. At Southern Company Gas, the performance obligations related to wholesale gas services are satisfied, and revenue is recognized, at a point in time when natural gas is delivered to the customer.

The registrants generally have a right to consideration in an amount that corresponds directly with the value to the customer of the entity's performance completed to date and may recognize revenue in the amount to which the entity has a right to invoice and has elected to recognize revenue for its sales of electricity, capacity, and natural gas using the invoice practical expedient. In addition, payment for goods and services rendered is typically due in the subsequent month following satisfaction of the registrants' performance obligation.

The following tables disaggregate revenue sources for the three and nine months ended September 30, 2018:

	For the Three Months Ended September 30, 2018		For the Nine Months Ended September 30, 2018
	(in millions)
Southern Company
Operating revenues
Retail electric revenues(a)
Residential	$	2,148	$	5,266
Commercial	1,527		4,084
Industrial	901		2,471
Other	29		92
Natural gas distribution revenues	433		2,299
Alternative revenue programs(b)	5		(23		)
Total retail electric and gas distribution revenues	$	5,043	$	14,189
Wholesale energy revenues(c)(d)	516		1,444
Wholesale capacity revenues(d)	177		479
Other natural gas revenues(e)	54		530
Other revenues(f)	369		1,516
Total operating revenues	$	6,159	$	18,158

(a) Retail electric revenues include $17 million and $54 million of leases for the three and nine months ended September 30, 2018, respectively, and a (net reduction) or net increase of $(98) million and $4 million for the three and nine months ended September 30, 2018, respectively, from certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 3 to the financial statements of Southern Company under "Regulatory Matters" in Item 8 of the Form 10-K for additional information on cost recovery mechanisms.

(b) See Note 1 to the financial statements of Southern Company under "Revenues" in Item 8 of the Form 10-K for additional information on alternative revenue programs at the natural gas distribution utilities. Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(c) Wholesale energy revenues include $63 million and $217 million for the three and nine months ended September 30, 2018, respectively, of revenues accounted for as derivatives, primarily related to physical energy sales in the wholesale electricity market. See Note (I) for additional information on energy-related derivative contracts.

(d) Wholesale energy and wholesale capacity revenues include $130 million and $31 million, respectively, for the three months ended September 30, 2018 and $318 million and $92 million, respectively, for the nine months ended September 30, 2018 of PPA contracts accounted for as leases.

(e) 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 $1.6 billion and $4.8 billion for the three and nine months ended September 30, 2018, respectively, of which $0.9 billion and $2.7 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.

(f) Other revenues include $92 million and $274 million for the three and nine months ended September 30, 2018, respectively, of revenues not accounted for under ASC 606.

	Alabama Power		Georgia Power		Gulf Power		Mississippi Power
	(in millions)
For the Three Months Ended September 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	721	$	1,142	$	200	$	85
Commercial	464		877		103		82
Industrial	392		385		37		86
Other	7		21		1		1
Total retail electric revenues	$	1,584	$	2,425	$	341	$	254
Wholesale energy revenues(c)	62		33		48		92
Wholesale capacity revenues	26		14		7		1
Other revenues(b)(d)	68		121		18		11
Total operating revenues	$	1,740	$	2,593	$	414	$	358
For the Nine Months Ended September 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	1,848	$	2,671	$	537	$	209
Commercial	1,238		2,343		291		212
Industrial	1,103		1,036		100		233
Other	19		62		4		6
Total retail electric revenues	$	4,208	$	6,112	$	932	$	660
Wholesale energy revenues(c)	234		99		104		259
Wholesale capacity revenues	75		41		20		6
Other revenues(b)(d)	199		349		50		31
Total operating revenues	$	4,716	$	6,601	$	1,106	$	956

(a) Retail revenues at Alabama Power, Georgia Power, Gulf Power, and Mississippi Power include a net increase or (net reduction) of $(12) million, $(47) million, $(36) million, and $(3) million, respectively, for the three months ended September 30, 2018 and $113 million, $(35) million, $(63) million, and $(11) million, respectively, for the nine months ended September 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 3 to the financial statements of Alabama Power, Georgia Power, Gulf Power, and Mississippi Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information on cost recovery mechanisms.

(b) Retail revenues and other revenues at Georgia Power include $17 million and $34 million, respectively, for the three months ended September 30, 2018 and $54 million and $100 million, respectively, for the nine months ended September 30, 2018 of revenues accounted for as leases.

(c) Wholesale energy revenues at Alabama Power and Georgia Power include $6 million and $8 million, respectively, for the three months ended September 30, 2018 and $14 million and $21 million, respectively, for the nine months ended September 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market. See Note (I) for additional information on energy-related derivative contracts.

(d) Other revenues at Alabama Power, Georgia Power, and Gulf Power include $27 million, $28 million, and $2 million, respectively, for the three months ended September 30, 2018 and $79 million, $80 million, and $5 million, respectively, for the nine months ended September 30, 2018 of revenues not accounted for under ASC 606.

	For the Three Months Ended September 30, 2018		For the Nine Months Ended September 30, 2018
	(in millions)
Southern Power
PPA capacity revenues(a)	$	168	$	450
PPA energy revenues(a)	336		892
Non-PPA revenues(b)	126		347
Other revenues	5		10
Total operating revenues	$	635	$	1,699

(a) PPA capacity revenues and PPA energy revenues include $47 million and $139 million, respectively, for the three months ended September 30, 2018 and $141 million and $342 million, respectively, for the nine months ended September 30, 2018 related to PPAs accounted for as leases. See Note 1 to the financial statements of Southern Power under "Revenues" in Item 8 of the Form 10-K for additional information on capacity revenues accounted for as leases.

(b) Non-PPA revenues include $47 million and $176 million for the three and nine months ended September 30, 2018, respectively, of revenues from short-term sales related to physical energy sales from uncovered capacity in the wholesale electricity market. See Note 1 to the financial statements of Southern Power under "Revenues" in Item 8 of the Form 10-K and Note (I) for additional information on energy-related derivative contracts.

	For the Three Months Ended September 30, 2018			For the Nine Months Ended September 30, 2018
	(in millions)
Southern Company Gas
Operating revenues
Natural gas distribution revenues
Residential	$	149		$	1,082
Commercial	45			313
Transportation	203			708
Industrial	4			28
Other	32			168
Alternative revenue programs(a)	5			(23		)
Total natural gas distribution revenues	$	438		$	2,276
Gas marketing services(b)	44			403
Wholesale gas services(c)	(10		)	121
Gas midstream operations	20			60
Other revenues	—			1
Total operating revenues	$	492		$	2,861

(a) See Note 1 to the financial statements of Southern Company Gas under "Revenues" in Item 8 of the Form 10-K for additional information on alternative revenue programs at the natural gas distribution utilities. Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(b) Gas marketing services includes $4 million for the nine months ended September 30, 2018 of revenues not accounted for under ASC 606.

(c) 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 $1.6 billion and $4.8 billion for the three and nine months ended September 30, 2018, respectively, of which $0.9 billion and $2.7 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues and Note (I) for additional information on energy-related derivative contracts.

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 September 30, 2018:

	Receivables		Contract Assets		Contract Liabilities
	(in millions)
Southern Company	$	2,778	$	99	$	34
Alabama Power	649		1		14
Georgia Power	924		70		3
Gulf Power	186		—		—
Mississippi Power	96		—		—
Southern Power	142		—		17
Southern Company Gas	523		—		1

As of September 30, 2018, Alabama Power had contract liabilities for outstanding performance obligations primarily related to extended service agreements. Georgia Power had contract assets primarily related to 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. Southern Power's contract liabilities relate to collections recognized in advance of revenue for certain levelized PPAs with Georgia Power. Southern Company's unregulated distributed generation business had $27 million and $17 million of contract assets and contract liabilities, respectively, remaining for outstanding performance obligations.

Remaining Performance Obligations

The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. These contracts primarily relate to PPAs whereby the traditional electric operating companies and Southern Power provide electricity and generation capacity to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain fixed price contracts. Revenues from contracts with customers related to these performance obligations remaining at September 30, 2018 are expected to be recognized as follows:

	2018		2019		2020		2021		2022		2023 and Thereafter
	(in millions)
Southern Company(*)	$	168	$	406	$	322	$	322	$	310	$	2,112
Alabama Power	6		22		22		26		23		161
Georgia Power	10		41		38		40		30		113
Gulf Power	5		22		—		—		—		—
Mississippi Power	1		3		3		1		—		—
Southern Power(*)	75		310		283		277		276		2,005

(*) Excludes amounts related to held for sale assets. See Note (J) under "Southern Company's Sale of Gulf Power" and "Southern Power – Sale of Florida Plants" for additional information.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2018

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

As of September 30, 2018, 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 September 30, 2018:	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)(b)	$	271	$	150	$	—	$	—	$	421
Foreign currency derivatives	—		122		—		—		122
Nuclear decommissioning trusts(c)	828		1,007		—		37		1,872
Non-qualified deferred compensation trusts:
Domestic equity	—		11		—		—		11
Foreign equity	—		6		—		—		6
Pooled funds – fixed income	—		13		—		—		13
Cash equivalents	15		—		—		—		15
Other	9		—		—		—		9
Cash equivalents	1,309		—		—		—		1,309
Total	$	2,432	$	1,309	$	—	$	37	$	3,778
Liabilities:
Energy-related derivatives(a)(b)	$	416	$	159	$	—	$	—	$	575
Interest rate derivatives	—		72		—		—		72
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		22		—		22
Total	$	416	$	254	$	22	$	—	$	692

	Fair Value Measurements Using:
As of September 30, 2018:	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	$	—	$	7	$	—	$	—	$	7
Nuclear decommissioning trusts:(d)
Domestic equity	469		89		—		—		558
Foreign equity	60		56		—		—		116
U.S. Treasury and government agency securities	—		18		—		—		18
Corporate bonds	26		154		—		—		180
Mortgage and asset backed securities	—		22		—		—		22
Private equity	—		—		—		37		37
Other	7		—		—		—		7
Cash equivalents	513		—		—		—		513
Total	$	1,075	$	346	$	—	$	37	$	1,458
Liabilities:
Energy-related derivatives	$	—	$	10	$	—	$	—	$	10
Georgia Power
Assets:
Energy-related derivatives	$	—	$	8	$	—	$	—	$	8
Nuclear decommissioning trusts:(d)(e)
Domestic equity	250		1		—		—		251
Foreign equity	—		134		—		—		134
U.S. Treasury and government agency securities	—		236		—		—		236
Municipal bonds	—		82		—		—		82
Corporate bonds	—		163		—		—		163
Mortgage and asset backed securities	—		42		—		—		42
Other	16		9		—		—		25
Cash equivalents	350		—		—		—		350
Total	$	616	$	675	$	—	$	—	$	1,291
Liabilities:
Energy-related derivatives	$	—	$	22	$	—	$	—	$	22
Interest rate derivatives	—		6		—		—		6
Total	$	—	$	28	$	—	$	—	$	28
Gulf Power
Assets:
Cash equivalents	$	27	$	—	$	—	$	—	$	27
Liabilities:
Energy-related derivatives	$	—	$	8	$	—	$	—	$	8

	Fair Value Measurements Using:
As of September 30, 2018:	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	346		—		—		—		346
Total	$	346	$	3	$	—	$	—	$	349
Liabilities:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9
Southern Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Foreign currency derivatives	—		122		—		—		122
Total	$	—	$	125	$	—	$	—	$	125
Liabilities:
Energy-related derivatives	$	—	$	7	$	—	$	—	$	7
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		22		—		22
Total	$	—	$	30	$	22	$	—	$	52
Southern Company Gas
Assets:
Energy-related derivatives(a)(b)	$	271	$	129	$	—	$	—	$	400
Non-qualified deferred compensation trusts:
Domestic equity	—		11		—		—		11
Foreign equity	—		6		—		—		6
Pooled funds – fixed income	—		13		—		—		13
Cash equivalents	4		—		—		—		4
Cash equivalents	26		—		—		—		26
Total	$	301	$	159	$	—	$	—	$	460
Liabilities:
Energy-related derivatives(a)(b)	$	416	$	101	$	—	$	—	$	517

(a) Excludes $5 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value.

(b) Excludes cash collateral of $189 million.

(c) For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.

(d) Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies.

(e) Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of September 30, 2018, approximately $37 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.

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 for the three and nine months ended September 30, 2018 and 2017 by the amounts shown in the table below. The increases were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.

	Three Months Ended September 30, 2018		Three Months Ended September 30, 2017		Nine Months Ended September 30, 2018		Nine Months Ended September 30, 2017
	(in millions)
Southern Company	$	58	$	50	$	68	$	168
Alabama Power	39		25		49		87
Georgia Power	19		25		19		81

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 (I) 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 1 to the financial statements of Southern Company, Alabama Power, and Georgia Power 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 date 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.

"Other investments" include investments that are not traded in the open market. The fair value of these investments has been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.

As of September 30, 2018, the fair value measurements of private equity investments held in the nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:

As of September 30, 2018:	Fair Value		Unfunded Commitments
	(in millions)
Southern Company	$	37	$	47
Alabama Power	$	37	$	47

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. Liquidations are expected to occur at various times over the next 10 years.

As of September 30, 2018, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Carrying Amount		Fair Value
	(in millions)
Long-term debt, including securities due within one year:
Southern Company	$	45,524	$	45,500
Alabama Power	8,120		8,321
Georgia Power	10,227		10,159
Gulf Power	1,285		1,290
Mississippi Power	1,736		1,702
Southern Power	5,029		5,058
Southern Company Gas	5,908		5,935

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, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas.

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Stockholders' Equity

9 Months Ended

Sep. 30, 2018

Equity [Abstract]

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY

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 8 to the financial statements of Southern Company 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 September 30, 2018	Three Months Ended September 30, 2017	Nine Months Ended September 30, 2018	Nine Months Ended September 30, 2017
	(in millions)
As reported shares	1,023	1,003	1,016	998
Effect of stock-based compensation	6	7	5	7
Diluted shares	1,029	1,010	1,021	1,005

Stock-based compensation awards that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for the three and nine months ended September 30, 2018 and 2017.

Changes in Stockholders' Equity

The following table presents year-to-date changes in stockholders' equity of Southern Company:

	Number of Common Shares			Common Stockholders' Equity			Preferred and Preference Stock of Subsidiaries						Total Stockholders' Equity
	Issued	Treasury								Noncontrolling Interests(a)
	(in thousands)			(in millions)
Balance at December 31, 2017	1,008,532	(929	)	$	24,167		$	—		$	1,361		$	25,528
Consolidated net income attributable to Southern Company	—	—		1,948			—			—			1,948
Other comprehensive income	—	—		52			—			—			52
Stock issued	21,342	—		878			—			—			878
Stock-based compensation	—	—		74			—			—			74
Cash dividends on common stock	—	—		(1,805		)	—			—			(1,805		)
Contributions from noncontrolling interests	—	—		—			—			154			154
Distributions to noncontrolling interests	—	—		—			—			(87		)	(87		)
Net income attributable to noncontrolling interests	—	—		—			—			71			71
Sale of noncontrolling interests(b)	—	—		(410		)	—			1,690			1,280
Other	—	(57	)	(27		)	—			(1		)	(28		)
Balance at September 30, 2018	1,029,874	(986	)	$	24,877		$	—		$	3,188		$	28,065
Balance at December 31, 2016	991,213	(819	)	$	24,758		$	609		$	1,245		$	26,612
Consolidated net income attributable to Southern Company	—	—		347			—			—			347
Other comprehensive income (loss)	—	—		(2		)	—			—			(2		)
Stock issued	13,308	—		613			—			—			613
Stock-based compensation	—	—		97			—			—			97
Cash dividends on common stock	—	—		(1,716		)	—			—			(1,716		)
Preference stock redemption	—	—		—			(150		)	—			(150		)
Contributions from noncontrolling interests	—	—		—			—			77			77
Distributions to noncontrolling interests	—	—		—			—			(87		)	(87		)
Net income attributable to noncontrolling interests	—	—		—			—			45			45
Reclassification from redeemable noncontrolling interests	—	—		—			—			114			114
Other	—	(75	)	(15		)	3			1			(11		)
Balance at September 30, 2017	1,004,521	(894	)	$	24,082		$	462		$	1,395		$	25,939

(a) Primarily related to Southern Power and excludes redeemable noncontrolling interests. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(b) See Note (J) under "Southern Power – Sale of Solar Facility Interests" for additional information.

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Financing

9 Months Ended

Sep. 30, 2018

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 September 30, 2018 was approximately $1.5 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, $82 million at Gulf Power, and $40 million at Mississippi Power). In addition, at September 30, 2018, the traditional electric operating companies had approximately $573 million (comprised of approximately $120 million at Alabama Power, $345 million at Georgia Power, $58 million at Gulf Power, and $50 million at Mississippi Power) of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2018, Alabama Power purchased and held its approximately $120 million of outstanding pollution control revenue bonds required to be remarketed. See Note 6 to the financial statements of each registrant 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 September 30, 2018:

	Expires												Executable Term Loans		Expires Within One Year
Company	2018		2019		2020		2022		Total		Unused		One Year		Term Out		No Term Out
	(in millions)
Southern Company(a)	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—	$	—	$	—
Alabama Power	—		33		500		800		1,333		1,333		—		—		33
Georgia Power	—		—		—		1,750		1,750		1,736		—		—		—
Gulf Power	20		25		235		—		280		280		45		45		—
Mississippi Power	—		100		—		—		100		100		—		—		—
Southern Power Company(b)	—		—		—		750		750		728		—		—		—
Southern Company Gas(c)	—		—		—		1,900		1,900		1,895		—		—		—
Other	—		30		—		—		30		30		—		—		30
Southern Company Consolidated	$	20	$	188	$	735	$	7,200	$	8,143	$	8,101	$	45	$	45	$	63

(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 2019, of which $22 million remains unused at September 30, 2018.

(c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.

Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

DOE Loan Guarantee Borrowings

See Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding Georgia Power's Loan Guarantee Agreement.

On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) in connection with the DOE's consent to Georgia Power's entry into the Vogtle Services Agreement and the related intellectual property licenses (IP Licenses). Under the terms of the Loan Guarantee Agreement, upon termination of the Vogtle 3 and 4 Agreement, further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement. Under the terms of the LGA Amendment, Georgia Power will not request any advances unless and until certain conditions are satisfied, including (i) receipt of the DOE's approval of the Bechtel Agreement (together with the Vogtle Services Agreement and the IP Licenses, the Replacement EPC Arrangements) and (ii) Georgia Power's entry into a further amendment to the Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements.

In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In September 2018, the DOE extended the conditional commitment to March 31, 2019. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions.

As of September 30, 2018, Georgia Power had $2.6 billion of borrowings outstanding under the multi-advance term loan facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB.

Under the 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 (including any decision not to continue construction of Plant Vogtle Units 3 and 4) occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility 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 bankruptcy if Georgia Power does not maintain access to intellectual property rights under the IP Licenses; (ii) a decision by Georgia Power not to continue construction of Plant Vogtle Units 3 and 4; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (iv) 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 Facility. 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 Facility. 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 Facility 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. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Credit Facility, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.

Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2018:

Company	Senior Note Issuances		Senior Note Maturities, Redemptions, and Repurchases		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Issuances		Other Long-Term Debt Redemptions and Maturities(a)
	(in millions)
Southern Company(b)	$	750	$	1,000	$	—	$	—	$	—
Alabama Power	500		—		—		—		—
Georgia Power	—		1,000		469		—		107
Mississippi Power	600		—		43		—		900
Southern Power	—		350		—		—		420
Southern Company Gas	—		—		200		100		—
Other	—		—		—		—		10
Elimination(c)	—		—		—		—		(1		)
Southern Company Consolidated	$	1,850	$	2,350	$	712	$	100	$	1,436

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

(b) Represents the Southern Company parent entity.

(c) Represents reductions in affiliate capital lease obligations at Georgia Power, which are eliminated in Southern Company's Consolidated Financial Statements.

Except as otherwise described herein, Southern Company and its subsidiaries used the proceeds of debt issuances for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital. The subsidiaries also used the proceeds for their construction programs.

Southern Company

In March 2018, Southern Company entered into a $900 million short-term floating rate bank loan bearing interest based on one-month LIBOR, which was repaid in August 2018.

In April 2018, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, bearing interest at a rate agreed upon by Southern Company and the bank from time to time and payable on no less than 30 days' demand by the bank.

In June 2018, Southern Company repaid at maturity two$100 million short-term floating rate bank term loans.

In August 2018, Southern Company issued $750 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due February 14, 2020 bearing interest based on three-month LIBOR, entered into a $1.5 billion short-term floating rate bank loan bearing interest based on one-month LIBOR, and repaid $250 million borrowed in August 2017 pursuant to a short-term uncommitted bank credit arrangement.

Alabama Power

In June 2018, Alabama Power issued $500 million aggregate principal amount of Series 2018A 4.30% Senior Notes due July 15, 2048.

Georgia Power

In January 2018, Georgia Power repaid its outstanding $150 million and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively.

In April 2018, Georgia Power redeemed all $250 million aggregate principal amount of its Series 2008B 5.40% Senior Notes due June 1, 2018.

In May 2018, through cash tender offers, Georgia Power repurchased and retired $89 million of the $250 million aggregate principal amount outstanding of its Series 2007A 5.65% Senior Notes due March 1, 2037, $326 million of the $500 million aggregate principal amount outstanding of its Series 2009A 5.95% Senior Notes due February 1, 2039, and $335 million of the $600 million aggregate principal amount outstanding of its Series 2010B 5.40% Senior Notes due June 1, 2040, for an aggregate purchase price, excluding accrued and unpaid interest, of $902 million.

During 2018, Georgia Power purchased and held the following pollution control revenue bonds, which may be reoffered to the public at a later date:

• $104.6 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013

• $173 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009

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

• $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

• $71.735 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2013

Mississippi Power

In March 2018, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $100 million was repaid in the third quarter 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.

In July 2018, Mississippi Power purchased and held approximately $43 million aggregate principal amount of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002. Mississippi Power may reoffer these bonds to the public at a later date.

Subsequent to September 30, 2018, Mississippi Power completed the redemption of all 8,867 outstanding shares ($886,700 aggregate par value) of its 4.40% Series Preferred Stock, all 8,643 outstanding shares ($864,300 aggregate par value) of its 4.60% Series Preferred Stock, all 16,700 outstanding shares ($1.67 million aggregate par value) of its 4.72% Series Preferred Stock, all 1,200,000 outstanding depositary shares ($30 million aggregate stated value) each representing a ¹/₄^th interest in a share of its 5.25% Series Preferred Stock, all $30 million aggregate principal amount outstanding of its Series G 5.40% Senior Notes due July 1, 2035, and all $125 million aggregate principal amount outstanding of its Series 2009A 5.55% Senior Notes due March 1, 2019.

Southern Power

In May 2018, Southern Power entered into two short-term floating rate bank loans, each for an aggregate principal amount of $100 million, which bear interest based on one-month LIBOR.

In the second quarter 2018, Southern Power repaid $420 million aggregate principal amount of long-term floating rate bank loans and $350 million aggregate principal amount of Series 2015A 1.50% Senior Notes due June 1, 2018.

During the nine months ended September 30, 2018, Southern Power received approximately $148 million of third-party tax equity related to the Gaskell West 1 and Cactus Flats facilities. See Note (J) under "Southern Power" for additional information.

Southern Company Gas

On January 4, 2018, Southern Company Gas issued a floating rate promissory note to Southern Company in an aggregate principal amount of $100 million bearing interest based on one-month LIBOR. On March 28, 2018, Southern Company Gas repaid this promissory note.

Prior to its sale, in the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of gas facility revenue bonds to be redeemed.

In May 2018, Southern Company Gas Capital borrowed $95 million pursuant to a short-term uncommitted bank credit arrangement, guaranteed by Southern Company Gas, bearing interest at a rate agreed upon by Southern Company Gas Capital and the bank from time to time and payable on no less than 30 days' demand by the bank. The proceeds of the loan were used to repay short-term debt. In July 2018, Southern Company Gas Capital repaid this loan.

In July 2018, Nicor Gas agreed to issue $300 million aggregate principal amount of first mortgage bonds in a private placement, $100 million of which was issued in August 2018 and $200 million of which was issued in November 2018.

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Retirement Benefits

9 Months Ended

Sep. 30, 2018

Retirement Benefits [Abstract]

RETIREMENT BENEFITS

RETIREMENT BENEFITS

On January 1, 2018, the qualified defined benefit pension plan of Southern Company Gas was merged into the qualified defined benefit pension plan of Southern Company. Following the plan merger, Southern Company has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The Southern Company qualified defined benefit 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 Southern Company qualified defined benefit pension plan are anticipated for the year ending December 31, 2018.

In addition, the Southern Company Gas non-qualified retirement plans were merged into the Southern Company non-qualified retirement plan (defined benefit and defined contribution). Following the non-qualified retirement plan mergers, Southern Company continues to provide certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis.

Furthermore, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas also provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. 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.

As indicated in Note (A), the registrants adopted ASU 2017-07 as of January 1, 2018. ASU 2017-07 requires that an employer report the service cost component of net periodic benefit costs in the same line item or items as other compensation costs and requires the other components of net periodic benefit costs to be separately presented in the statements of income outside of income from operations. The presentation requirements of ASU 2017-07 have been applied retrospectively with the service cost component of net periodic benefit costs included in operations and maintenance and all other components of net periodic benefit costs included in other income (expense), net in the statements of income for the three and nine months ended September 30, 2017.

With respect to the presentation requirements, the registrants have used the practical expedient provided by ASU 2017-07, which permits an employer to use the amounts disclosed in its retirement benefits footnote for prior comparative periods as the estimation basis for applying the retrospective presentation requirements to those periods. The amounts of the other components of net periodic benefit costs reclassified for the prior period are presented in the following tables.

See Note 2 to the financial statements of each registrant in Item 8 of the Form 10-K for additional information.

Components of the net periodic benefit costs for the three and nine months ended September 30, 2018 and 2017 are presented in the following tables.

Three Months Ended September 30, 2018	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	90		$	19		$	22		$	4		$	5		$	3		$	8
Interest cost	116			26			34			5			5			1			10
Expected return on plan assets	(236		)	(51		)	(74		)	(10		)	(11		)	(3		)	(18		)
Amortization:
Prior service costs	1			—			1			—			—			—			(1		)
Regulatory asset	—			—			—			—			—			—			4
Net (gain)/loss	53			13			18			2			3			—			3
Net periodic pension cost (income)	$	24		$	7		$	1		$	1		$	2		$	1		$	6
Postretirement Benefits
Service cost	$	6		$	1		$	2		$	—		$	—		$	1		$	—
Interest cost	19			5			7			1			—			—			2
Expected return on plan assets	(17		)	(7		)	(6		)	—			—			—			(1		)
Amortization:
Prior service costs	2			1			—			—			—			—			—
Regulatory asset	—			—			—			—			—			—			2
Net (gain)/loss	3			—			2			—			—			—			—
Net periodic postretirement benefit cost	$	13		$	—		$	5		$	1		$	—		$	1		$	3

Nine Months Ended September 30, 2018	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	269		$	58		$	65		$	12		$	13		$	7		$	24
Interest cost	348			76			104			15			15			4			29
Expected return on plan assets	(707		)	(155		)	(222		)	(30		)	(31		)	(8		)	(53		)
Amortization:
Prior service costs	3			1			2			—			—			—			(2		)
Regulatory asset	—			—			—			—			—			—			11
Net (gain)/loss	160			40			52			7			8			1			9
Net periodic pension cost (income)	$	73		$	20		$	1		$	4		$	5		$	4		$	18
Postretirement Benefits
Service cost	$	18		$	4		$	5		$	1		$	1		$	1		$	1
Interest cost	56			13			21			2			2			—			7
Expected return on plan assets	(51		)	(20		)	(19		)	(1		)	(1		)	—			(5		)
Amortization:
Prior service costs	5			3			1			—			—			—			—
Regulatory asset	—			—			—			—			—			—			5
Net (gain)/loss	10			1			6			—			—			—			—
Net periodic postretirement benefit cost	$	38		$	1		$	14		$	2		$	2		$	1		$	8

Three Months Ended September 30, 2017(*)	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	73		$	15		$	19		$	3		$	4		$	6
Interest cost	114			25			34			5			5			10
Expected return on plan assets	(224		)	(49		)	(71		)	(10		)	(9		)	(18		)
Amortization:
Prior service costs	3			1			—			—			—			—
Net (gain)/loss	41			10			15			2			1			5
Net periodic pension cost (income)	$	7		$	2		$	(3	)	$	—		$	1		$	3
Postretirement Benefits
Service cost	$	6		$	1		$	2		$	—		$	—		$	1
Interest cost	19			4			6			1			1			3
Expected return on plan assets	(16		)	(5		)	(6		)	—			—			(2		)
Amortization:
Prior service costs	2			1			—			—			—			(1		)
Net (gain)/loss	3			—			3			—			—			1
Net periodic postretirement benefit cost	$	14		$	1		$	5		$	1		$	1		$	2

(*) Excludes Southern Power since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017.

Nine Months Ended September 30, 2017(*)	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	220		$	47		$	56		$	10		$	11		$	17
Interest cost	341			73			103			15			15			30
Expected return on plan assets	(673		)	(147		)	(212		)	(29		)	(29		)	(53		)
Amortization:
Prior service costs	9			2			2			—			1			(1		)
Net (gain)/loss	122			31			43			5			5			15
Net periodic pension cost (income)	$	19		$	6		$	(8	)	$	1		$	3		$	8
Postretirement Benefits
Service cost	$	18		$	4		$	5		$	1		$	1		$	2
Interest cost	59			13			21			2			3			8
Expected return on plan assets	(49		)	(19		)	(18		)	(1		)	(1		)	(5		)
Amortization:
Prior service costs	5			3			1			—			—			(2		)
Net (gain)/loss	10			1			6			—			—			3
Net periodic postretirement benefit cost	$	43		$	2		$	15		$	2		$	3		$	6

(*) Excludes Southern Power since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017.

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Income Taxes

9 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for additional tax information.

Federal Tax Reform Legislation

Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the registrants consider all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. Each of the registrants is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note (B) under "Regulatory Matters" for additional information.

Current and Deferred Income Taxes

Tax Credit Carryforwards

Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $2.4 billion as of September 30, 2018 compared to $2.1 billion as of December 31, 2017.

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 2018 abandonment loss related to certain Kemper County energy facility expenditures as well as the projected taxable gains on the various sale transactions described in Note (J) and "Legal Entity Reorganizations" herein. The expected utilization of tax credit carryforwards could be further delayed by numerous factors, including the acquisition of additional renewable projects, increased generation at existing wind facilities, the purchase of rights to additional PTCs during construction of Plant Vogtle Units 3 and 4 pursuant to the MEAG Term Sheet, and changes in taxable income projections. See Note (B) under "Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4. The ultimate outcome of these matters cannot be determined at this time.

Valuation Allowances

	Georgia Power		Mississippi Power		Southern Company Gas		Southern Company
	(in millions)
Federal	$	6	$	—	$	11	$	19
State (net of federal benefit)	33		124		1		171
Balance at September 30, 2018	$	39	$	124	$	12	$	190

Southern Company had valuation allowances, net of related federal benefits, of $190 million at September 30, 2018 compared to $148 million at December 31, 2017. The increase was primarily due to Georgia Power's projected inability to utilize certain state tax credit carryforwards.

Effective Tax Rate

Each registrant's effective tax rate for the nine months ended September 30, 2018 varied significantly as compared to the corresponding period in 2017 due to the 14% lower 2018 federal tax rate resulting from the Tax Reform Legislation.

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 federal income tax benefits from ITCs and PTCs.

Southern Company's effective tax rate was 22.7% for the nine months ended September 30, 2018 compared to 42.6% for the corresponding period in 2017. The effective tax rate decrease was primarily due to the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation, the net state income tax benefits related to changes in state apportionment rates arising from the reorganization of Southern Power's legal entities as discussed further herein, and the $3.1 billion pre-tax loss on the Kemper IGCC, net of the non-deductible AFUDC equity portion, recorded in 2017, partially offset by the $1.1 billion pre-tax loss related to Plant Vogtle Units 3 and 4 and the income taxes recorded related to the Southern Company Gas Dispositions in 2018. See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) under "Kemper County Energy Facility" for additional information regarding the Kemper IGCC and Note (B) under "Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4. See Note (B) under "Regulatory Matters" for additional information on the flowback of excess deferred income taxes and Note (J) under "Southern Company Gas" for additional information on the Southern Company Gas Dispositions.

Southern Company recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Company uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.

Alabama Power

Alabama Power's effective tax rate was 23.9% for the nine months ended September 30, 2018 compared to 39.9% for the corresponding period in 2017. The effective tax rate decrease was primarily due to the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation. See Note (B) under "Regulatory Matters – Alabama Power" for additional information.

Georgia Power

Georgia Power's effective tax rate was 25.5% for the nine months ended September 30, 2018 compared to 37.0% for the corresponding period in 2017. The effective tax rate decrease was primarily due to the reduction in the federal corporate income tax rate and the $1.1 billion pre-tax loss related to the estimated probable loss on Plant Vogtle Units 3 and 4 recorded in 2018, partially offset by the valuation allowance on certain state tax credit carryforwards. See Note (B) under "Nuclear Construction" for additional information.

Gulf Power

Gulf Power's effective tax benefit rate was (0.5)% for the nine months ended September 30, 2018 compared to an effective tax rate of 39.4% for the corresponding period in 2017. The effective tax rate decrease was primarily due to the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation. See Note (B) under "Regulatory Matters – Gulf Power" for additional information.

Mississippi Power

Mississippi Power's effective tax rate was 20.8% for the nine months ended September 30, 2018 compared to a benefit rate of (30.3)% for the corresponding period in 2017. The effective tax rate increase was primarily due to the $3.1 billion pre-tax loss on the Kemper IGCC, net of the non-deductible AFUDC equity portion, recorded in 2017, partially offset by the reduction in the federal corporate income tax rate as a result of the Tax Reform Legislation. See Note (B) under "Regulatory Matters – Mississippi Power" for additional information.

Southern Power

Southern Power's effective tax benefit rate was (220.3)% for the nine months ended September 30, 2018 compared to (66.5)% for the corresponding period in 2017. The effective tax rate decrease was primarily due to lower earnings before income taxes resulting from a $119 million asset impairment charge as a result of the pending sale of Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) and a $36 million asset impairment charge on wind turbine equipment held for development projects, as well as the reduction in the federal corporate income tax rate and the net state income tax benefits related to certain changes in apportionment rates arising from the reorganization of Southern Power's legal entities as described below. See Note (J) under "Southern Power" for additional information.

Southern Power recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Power uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.

Southern Company Gas

Southern Company Gas' effective tax rate was 61.8% for the nine months ended September 30, 2018 compared to 43.4% for the corresponding period in 2017. This increase was primarily related to income taxes recorded related to the Southern Company Gas Dispositions, partially offset by the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation, as well as the 2017 increases in deferred tax expense related to the enactment of the State of Illinois income tax legislation and new income tax apportionment factors in several states. See Note (B) under "Regulatory Matters – Southern Company Gas" and Note (J) under "Southern Company Gas" for additional information.

Legal Entity Reorganizations

In April 2018, Southern Power completed the final stage of a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization resulted in net state tax benefits related to certain changes in apportionment rates totaling approximately $54 million, which were recorded in the first half of 2018.

In September 2018, Southern Power also completed a legal reorganization of eight operating wind facilities under a new holding company, SP Wind, which resulted in net state tax benefits totaling approximately $11 million related to certain changes in apportionment rates.

Unrecognized Tax Benefits

See Note 5 to the financial statements of each registrant under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information.

The registrants had no unrecognized tax benefits as of September 30, 2018. It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

The IRS has finalized its audits of Southern Company's consolidated income tax returns through 2016, as well as the pre-Merger Southern Company Gas tax returns. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2012.

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Derivatives

9 Months Ended

Sep. 30, 2018

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 (D) for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. The 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.

The registrants adopted ASU 2017-12 as of January 1, 2018. See Note (A) under "Recently Adopted Accounting Standards – Other" for additional information.

Energy-Related Derivatives

Southern Company, 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 is expected to continue to mitigate price volatility. The Florida PSC approved a moratorium on Gulf Power's fuel-hedging program until January 1, 2021. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. 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 which are 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 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 September 30, 2018, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, 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(*)	595	2022	2029
Alabama Power	82	2022	—
Georgia Power	165	2022	—
Gulf Power	9	2020	—
Mississippi Power	69	2022	—
Southern Power	15	2020	—
Southern Company Gas(*)	255	2021	2029

(*) Southern Company's and 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 4.3 billion mmBtu and short natural gas positions of 4 billion mmBtu as of September 30, 2018, 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 gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 13 million mmBtu for Southern Company, 2 million mmBtu for Alabama Power, 4 million mmBtu for Georgia Power, 1 million mmBtu for Gulf Power, 2 million mmBtu for Mississippi Power, and 4 million mmBtu for Southern Power.

For cash flow hedges of energy-related derivatives, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending September 30, 2019 are immaterial for all registrants.

Interest Rate Derivatives

Southern Company and certain subsidiaries may also 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 September 30, 2018, 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 September 30, 2018
	(in millions)					(in millions)
Fair Value Hedges of Existing Debt
Southern Company(*)	$	300	2.75%	3-month LIBOR + 0.92%	June 2020	$	(6	)
Southern Company(*)	1,500		2.35%	1-month LIBOR + 0.87%	July 2021	(60		)
Georgia Power	500		1.95%	3-month LIBOR + 0.76%	December 2018	(3		)
Georgia Power	200		4.25%	3-month LIBOR + 2.46%	December 2019	(3		)
Southern Company Consolidated	$	2,500				$	(72	)

(*) 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 next 12-month period ending September 30, 2019 are $(19) million for Southern Company and immaterial for all other registrants. Southern Company and certain subsidiaries have deferred gains and losses expected to be amortized into earnings through 2046.

Foreign Currency Derivatives

Southern Company and certain subsidiaries may also 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 September 30, 2018, the following foreign currency derivatives were outstanding:

	Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at September 30, 2018
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	48
Southern Power	564		3.78%	500		1.85%	June 2026	51
Total	$	1,241		€	1,100			$	99

The estimated pre-tax gains (losses) related to foreign currency derivatives that will be reclassified from accumulated OCI to earnings for the next 12-month period ending September 30, 2019 are $(23) million for Southern Company and Southern Power.

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 September 30, 2018						As of December 31, 2017
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	$	15		$	17		$	10		$	43
Other deferred charges and assets/Other deferred credits and liabilities	5			26			7			24
Assets held for sale, current/Liabilities held for sale, current	—			6			—			—
Assets held for sale/Liabilities held for sale	—			2			—			—
Total derivatives designated as hedging instruments for regulatory purposes	$	20		$	51		$	17		$	67
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	3		$	6		$	3		$	14
Other deferred charges and assets/Other deferred credits and liabilities	1			1			—			—
Interest rate derivatives:
Other current assets/Other current liabilities	—			22			1			4
Other deferred charges and assets/Other deferred credits and liabilities	—			50			—			34
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	122			—			129			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	126		$	102		$	133		$	75
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	263		$	317		$	380		$	437
Other deferred charges and assets/Other deferred credits and liabilities	134			198			170			215
Total derivatives not designated as hedging instruments	$	397		$	515		$	550		$	652
Gross amounts recognized	$	543		$	668		$	700		$	794
Gross amounts offset(a)	$	(303	)	$	(491	)	$	(405	)	$	(598	)
Net amounts recognized in the Balance Sheets(b)	$	240		$	177		$	295		$	196

	As of September 30, 2018						As of December 31, 2017
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	$	5		$	4		$	2		$	6
Other deferred charges and assets/Other deferred credits and liabilities	2			6			2			4
Total derivatives designated as hedging instruments for regulatory purposes	$	7		$	10		$	4		$	10
Gross amounts recognized	$	7		$	10		$	4		$	10
Gross amounts offset	$	(4	)	$	(4	)	$	(4	)	$	(4	)
Net amounts recognized in the Balance Sheets	$	3		$	6		$	—		$	6
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	5		$	9		$	2		$	9
Other deferred charges and assets/Other deferred credits and liabilities	2			13			4			10
Total derivatives designated as hedging instruments for regulatory purposes	$	7		$	22		$	6		$	19
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	5		$	—		$	4
Other deferred charges and assets/Other deferred credits and liabilities	—			1			—			1
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	6		$	—		$	5
Gross amounts recognized	$	7		$	28		$	6		$	24
Gross amounts offset	$	(7	)	$	(7	)	$	(6	)	$	(6	)
Net amounts recognized in the Balance Sheets	$	—		$	21		$	—		$	18
Gulf Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	—		$	6		$	—		$	14
Other deferred charges and assets/Other deferred credits and liabilities	—			2			—			7
Total derivatives designated as hedging instruments for regulatory purposes	$	—		$	8		$	—		$	21
Gross amounts recognized	$	—		$	8		$	—		$	21
Net amounts recognized in the Balance Sheets	$	—		$	8		$	—		$	21

	As of September 30, 2018						As of December 31, 2017
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	$	2		$	3		$	1		$	6
Other deferred charges and assets/Other deferred credits and liabilities	1			6			1			3
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	9		$	2		$	9
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	—		$	1		$	—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	—		$	1		$	—
Gross amounts recognized	$	3		$	9		$	3		$	9
Gross amounts offset	$	(3	)	$	(3	)	$	(2	)	$	(2	)
Net amounts recognized in the Balance Sheets	$	—		$	6		$	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	$	2		$	6		$	3		$	11
Other deferred charges and assets/Other deferred credits and liabilities	1			1			—			—
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	122			—			129			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	125		$	30		$	132		$	34
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	—		$	—		$	—		$	2
Gross amounts recognized	$	125		$	30		$	132		$	36
Gross amounts offset	$	(2	)	$	(2	)	$	(3	)	$	(3	)
Net amounts recognized in the Balance Sheets	$	123		$	28		$	129		$	33

	As of September 30, 2018						As of December 31, 2017
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	$	3		$	1		$	5		$	8
Other deferred charges and assets/Other deferred credits and liabilities	—			1			—			—
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	2		$	5		$	8
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	$	1		$	—		$	—		$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	262		$	316		$	379		$	434
Other deferred charges and assets/Other deferred credits and liabilities	134			198			170			215
Total derivatives not designated as hedging instruments	$	396		$	514		$	549		$	649
Gross amounts of recognized	$	400		$	516		$	554		$	660
Gross amounts offset(a)	$	(287	)	$	(475	)	$	(390	)	$	(583	)
Net amounts recognized in the Balance Sheets(b)	$	113		$	41		$	164		$	77

(a) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $189 million and $193 million as of September 30, 2018 and December 31, 2017, respectively.

(b) Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $5 million and $11 million as of September 30, 2018 and December 31, 2017, respectively.

At September 30, 2018 and December 31, 2017, 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 September 30, 2018
Derivative Category and Balance Sheet Location	Southern Company(*)			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas(*)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(9	)	$	(2	)	$	(4	)	$	(6	)	$	(2	)	$	(1	)
Other regulatory assets, deferred	(20		)	(4		)	(11		)	(2		)	(5		)	—
Assets held for sale, current	(6		)	—			—			—			—			—
Assets held for sale	(2		)	—			—			—			—			—
Other regulatory liabilities, current	8			3			—			—			—			5
Total energy-related derivative gains (losses)	$	(29	)	$	(3	)	$	(15	)	$	(8	)	$	(7	)	$	4

(*) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $3 million at September 30, 2018.

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2017
Derivative Category and Balance Sheet Location	Southern Company(*)			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas(*)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(34	)	$	(4	)	$	(7	)	$	(14	)	$	(5	)	$	(4	)
Other regulatory assets, deferred	(18		)	(3		)	(6		)	(7		)	(2		)	—
Other regulatory liabilities, current	7			—			—			—			—			7
Other regulatory liabilities, deferred	1			1			—			—			—			—
Total energy-related derivative gains (losses)	$	(44	)	$	(6	)	$	(13	)	$	(21	)	$	(7	)	$	3

(*) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million at December 31, 2017.

For the three and nine months ended September 30, 2018 and 2017, 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 September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Southern Company
Energy-related derivatives	$	(5	)	$	(6	)	$	7		$	(26	)
Interest rate derivatives	—			(1		)	(2		)	(2		)
Foreign currency derivatives	(10		)	46			(31		)	114
Total	$	(15	)	$	39		$	(26	)	$	86
Southern Power
Energy-related derivatives	$	(5	)	$	(6	)	$	5		$	(21	)
Foreign currency derivatives	(10		)	46			(31		)	114
Total	$	(15	)	$	40		$	(26	)	$	93
Southern Company Gas
Energy-related derivatives	$	—		$	—		$	2		$	(4	)

For the three and nine months ended September 30, 2018 and 2017, 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 nine months ended September 30, 2017, there was no material ineffectiveness recorded in earnings for any registrant. Upon the adoption of ASU 2017-12, beginning in 2018, ineffectiveness was no longer separately measured and recorded in earnings. See Note (A) for additional information.

For the three and nine months ended September 30, 2018 and 2017, 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 September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Southern Company
Cost of natural gas	$	104		$	134		$	1,053		$	1,085
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	—			—			(2		)	—
Depreciation and amortization	787			767			2,338			2,236
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	—			(6		)	2			(12		)
Interest expense, net of amounts capitalized	(458		)	(407		)	(1,386		)	(1,248		)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(5		)	(5		)	(16		)	(15		)
Foreign currency derivatives	(6		)	(5		)	(18		)	(17		)
Gain (loss) on fair value hedges(b)
Interest rate derivatives	(4		)	(5		)	(35		)	(6		)
Other income (expense), net	57			65			195			165
Gain (loss) on cash flow hedges(a)(c)
Foreign currency derivatives	(9		)	43			(46		)	139
Alabama Power
Interest expense, net of amounts capitalized	$	(82	)	$	(76	)	$	(240	)	$	(229	)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(1		)	(2		)	(4		)	(5		)
Georgia Power
Interest expense, net of amounts capitalized	$	(95	)	$	(105	)	$	(303	)	$	(310	)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(1		)	(1		)	(4		)	(3		)
Gain (loss) on fair value hedges(b)
Interest rate derivatives	—			—			(1		)	(1		)
Mississippi Power
Interest expense, net of amounts capitalized	$	(19	)	$	13		$	(59	)	$	(23	)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	—			—			(1		)	(1		)

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Southern Power
Depreciation and amortization	$	130		$	131		$	370		$	379
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	—			(6		)	2			(12		)
Interest expense, net of amounts capitalized	(45		)	(47		)	(138		)	(144		)
Gain (loss) on cash flow hedges(a)
Foreign currency derivatives	(6		)	(5		)	(18		)	(17		)
Other income (expense), net	17			3			22			3
Gain (loss) on cash flow hedges(a)(c)
Foreign currency derivatives	(9		)	43			(46		)	139
Southern Company Gas
Cost of natural gas	$	104		$	134		$	1,053		$	1,085
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	—			—			(2		)	—

(a) Amounts reflect gains or losses on cash flow hedges that were reclassified from accumulated OCI into income.

(b) For fair value hedges presented above, generally changes in the fair value of the derivative contracts are 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 nine months ended September 30, 2018 and 2017, the pre-tax effects of cash flow hedge accounting on income for interest rate derivatives were immaterial for Gulf Power and Southern Company Gas.

As of September 30, 2018 and December 31, 2017, 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 September 30, 2018			As of December 31, 2017			As of September 30, 2018		As of December 31, 2017
	(in millions)						(in millions)
Southern Company
Securities due within one year	$	(499	)	$	(746	)	$	1	$	3
Long-term debt	(2,526		)	(2,553		)	65		35
Georgia Power
Securities due within one year	$	(499	)	$	(746	)	$	1	$	3
Long-term debt	(497		)	(498		)	2		1

For the three and nine months ended September 30, 2018 and 2017, 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 September 30,						Nine Months Ended September 30,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2018			2017			2018			2017
		(in millions)						(in millions)
Energy-related derivatives:	Natural gas revenues(*)	$	(36	)	$	(17	)	$	(79	)	$	48
	Cost of natural gas	2			2			5			(2		)
Total derivatives in non-designated hedging relationships		$	(34	)	$	(15	)	$	(74	)	$	46

(*) Excludes gains (losses) recorded in natural gas revenues associated with weather derivatives of $15 million for the nine months ended September 30, 2017 and immaterial amounts for all other periods presented.

For the three and nine months ended September 30, 2018 and 2017, 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 September 30, 2018, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

For the registrants with interest rate derivatives at September 30, 2018, 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 September 30, 2018, 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.

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 September 30, 2018, 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 September 30, 2018, cash collateral held on deposit in broker margin accounts was $189 million.

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas 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. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's, the traditional electric operating companies', Southern Power's, and Southern Company Gas' exposure to counterparty credit risk. 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.

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

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Acquisitions and Dispositions

9 Months Ended

Sep. 30, 2018

Business Combinations [Abstract]

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS

Southern Company's Sale of Gulf Power

On May 20, 2018, Southern Company entered into a stock purchase agreement (Gulf Power SPA) with NextEra Energy and its wholly-owned subsidiary 700 Universe, LLC, which provides for the sale of all of the capital stock of Gulf Power for an aggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $1.3 billion), subject to (i) customary adjustments for indebtedness and working capital and (ii) reduction by the amount (if any) by which Gulf Power fails to meet a specified capital expenditure target.

The Gulf Power SPA contains customary representations, warranties, and covenants of Southern Company, 700 Universe, LLC, and NextEra Energy. These covenants include, among others, an obligation of Southern Company to cause Gulf Power to operate its business in the ordinary course until the sale is consummated and an obligation for each of the parties to use reasonable best efforts to obtain the governmental and regulatory approvals described below.

The completion of the sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) approval by the FERC and the Federal Communications Commission, (ii) the entry into certain ancillary agreements, including transmission-related agreements and a transition services agreement, among the parties and their affiliates, and (iii) other customary closing conditions.

The Gulf Power SPA may be terminated by either Southern Company or 700 Universe, LLC under certain circumstances, including if the sale is not consummated by June 28, 2019 (subject to extension to December 31, 2019, if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). The Gulf Power SPA further provides that, upon the termination thereof, (i) under certain specified circumstances, 700 Universe, LLC will be required to pay Southern Company a termination fee of $100 million or $200 million (such amount depending on the specific circumstances of such termination) and (ii) upon certain other specified circumstances Southern Company will be required to pay 700 Universe, LLC a termination fee of $100 million.

The sale of Gulf Power is expected to occur in the first quarter 2019. The assets and liabilities of Gulf Power are classified as assets held for sale and liabilities held for sale on Southern Company's balance sheet as of September 30, 2018. See "Assets Held for Sale" below for additional information. The ultimate outcome of this matter cannot be determined at this time.

Southern Power

See Note 11 to the financial statements of Southern Power and Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K for additional information.

Acquisitions During the Nine Months Ended September 30, 2018

During the nine months ended September 30, 2018, one of Southern Power's wholly-owned subsidiaries acquired and completed construction of the Gaskell West 1 solar facility. Acquisition-related costs were expensed as incurred and were not material.

Project Facility	Resource	Seller; Acquisition Date	Approximate Nameplate Capacity (MW)	Location	Southern Power Percentage Ownership		Actual COD	PPA Contract Period
Gaskell West 1	Solar	Recurrent Energy Development Holdings, LLC January 26, 2018	20	Kern County, CA	100% of Class B	(*)	March 2018	20 years

(*) Southern Power owns 100% of the class B membership interests under a tax equity partnership agreement.

The Gaskell West 1 facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service during March 2018.

Construction Projects in Progress and/or Completed

During the nine months ended September 30, 2018, Southern Power started, continued, or completed construction of the projects set forth in the table below. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $575 million and $640 million for the Mankato, Wild Horse Mountain, and Reading facilities. At September 30, 2018, construction costs included in CWIP related to these projects totaled $246 million. 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
Cactus Flats(a)	Wind	148	Concho County, TX	July 2018	12-15 years
Mankato	Natural Gas	385	Mankato, MN	First half 2019	20 years
Wild Horse 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 July 2017, Southern Power purchased 100% of the Cactus Flats facility and commenced construction. In July 2018, the facility was placed in service and, in August 2018, Southern Power closed on a tax equity partnership agreement and owns 100% of the class B membership interests.

(b) In May 2018, Southern Power purchased 100% of the Wild Horse Mountain facility and commenced construction. Southern Power may enter into a tax equity partnership agreement, in which case it would then own 100% of the class B membership interests.

(c) In August 2018, Southern Power purchased 100% of the membership interests from the joint development arrangement with Renewable Energy Systems Americas, Inc. and commenced construction. Southern Power may enter into a tax equity partnership agreement, in which case it would then own 100% of the class B membership interests.

Development Projects

During 2017, as part of its renewable development strategy, Southern Power purchased wind turbine equipment from Siemens Gamesa Renewable Energy Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction projects. Any wind projects using this equipment and reaching commercial operation by the end of 2021 are expected to qualify for 80% PTCs.

During 2016, Southern Power entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct wind projects. In addition, in 2016, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Any wind projects using this equipment and reaching commercial operation by the end of 2020 are expected to qualify for 100% PTCs.

In response to the previously disclosed decrease of planned expenditures for plant acquisitions and placeholder growth, Southern Power continues to refine the deployment of the wind turbine equipment to potential joint development and construction projects as well as the amount of MW capacity to be constructed. During the third quarter 2018, as a result of a review of various options for probable dispositions of wind turbine equipment not already deployed to development or construction projects, Southern Power recorded a $36 million asset impairment charge on the equipment.

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

Sale of Solar Facility Interests

In May 2018, Southern Power sold a 33% equity interest in SPSH, a limited partnership indirectly owning substantially all of Southern Power's solar facilities, to Global Atlantic Financial Group Limited (Global Atlantic) for approximately $1.2 billion, subject to customary working capital adjustments. The proceeds were used to repay $770 million of existing indebtedness, to return capital of $250 million to Southern Company, and for other general corporate purposes, including working capital. Since Southern Power retains control of the limited partnership through its wholly-owned general partner, the sale was recorded as an equity transaction and Southern Power will continue to consolidate the results of SPSH. On the date of the transaction, the noncontrolling interest was increased by $511 million to reflect 33% of the carrying value of the partnership. This difference, partially offset by the tax impact and other related transaction charges, also resulted in a $410 million decrease to Southern Power's common stockholder's equity.

Sale of Florida Plants

In May 2018, Southern Power entered into an equity interest purchase agreement with NextEra Energy to sell all of its equity interests in the Florida Plants, for an aggregate purchase price of $195 million, subject to customary working capital and timing adjustments.

The sale is subject to certain closing and timing conditions and approvals, including, but not limited to, approval by the FERC. The ultimate purchase price will decrease $110,000 per day for each day after December 31, 2018 through the closing of the transaction. Conversely, the ultimate purchase price will increase $110,000 per day for each day the closing occurs prior to December 31, 2018. The sale is expected to occur in the first quarter 2019. As a result of this pending transaction, Southern Power recorded an asset impairment charge of approximately $119 million ($89 million after tax) in the second quarter 2018. The assets and liabilities of the Florida Plants are classified as assets held for sale and liabilities held for sale on Southern Company's and Southern Power's balance sheets as of September 30, 2018. See "Assets Held for Sale" below for additional information. The ultimate outcome of this matter cannot be determined at this time.

Sale of Wind Facility Interests

On October 31, 2018, Southern Power entered into agreements with three financial investors for the sale of a noncontrolling interest for approximately $1.2 billion in tax equity in SP Wind, which owns a portfolio of eight operating wind facilities. The transaction is subject to Public Utility Commission of Texas approval and is expected to close by the end of 2018. Southern Power intends to use the proceeds to return capital of approximately $1.0 billion to Southern Company. The ultimate outcome of this matter cannot be determined at this time.

Sale of Mankato Plant

On November 5, 2018, Southern Power entered into an agreement with Northern States Power to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of $650 million, subject to customary working capital and timing adjustments. The ultimate purchase price will decrease $66,667 per day for each day after June 1, 2019, if the expansion has not achieved commercial operation, but such decrease will not exceed $15 million. This transaction is subject to the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and FERC and state commission approvals and is expected to close mid-2019. The ultimate outcome of this matter cannot be determined at this time.

Assets Subject to Lien

Under the terms of the PPA and the expansion PPA for the Mankato project, approximately $500 million of assets, primarily related to property, plant, and equipment, are subject to lien at September 30, 2018.

Southern Company Gas

Sale of Pivotal Home Solutions

On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $365 million, which includes the final working capital adjustment. This disposition resulted in an estimated net loss of $73 million, which includes $39 million of income tax expense, the calculation of which is expected to be finalized in the fourth quarter 2018. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded during the first quarter 2018. The after-tax loss included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Southern Company Gas and American Water Enterprises LLC entered into a transition services agreement whereby Southern Company Gas provided certain administrative and operational services through November 4, 2018.

Sale of Elizabethtown Gas and Elkton Gas

On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion and an additional $40 million for working capital, subject to a final working capital adjustment expected in the fourth quarter 2018. This disposition resulted in an estimated pre-tax gain of approximately $230 million and an after-tax gain of approximately $18 million, the calculations of which are expected to be finalized in the fourth quarter 2018. The after-tax gain included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Southern Company Gas and South Jersey Industries, Inc. entered into transition services agreements whereby Southern Company Gas will provide certain administrative and operational services through no later than January 31, 2020.

Sale of Florida City Gas

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 Energyfor a total cash purchase price of$530 million (less $3 million of indebtedness assumed at closing for customer deposits) and an additional $60 million for cash and other working capital, which includes the final working capital adjustment. This disposition resulted in an estimated pre-tax gain of approximately $121 million and an after-tax gain of approximately $20 million, the calculations of which are expected to be finalized in the fourth quarter 2018. The after-tax gain included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Southern Company Gas and NextEra Energy entered into a transition services agreement whereby Southern Company Gas will provide certain administrative and operational services through no later than July 29, 2020.

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 September 30, 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 May 2018, Southern Power ceased recognizing depreciation on the Florida Plants' property, plant, and equipment to be sold. Since the depreciation of the assets to be sold in the Gulf Power transaction continues to be reflected in customer rates and will be reflected in the carryover basis of the assets when sold, Southern Company will continue to record depreciation on those assets through the date the transaction closes. Likewise, since the depreciation of the assets sold in the Elizabethtown Gas, Elkton Gas, and Florida City Gas transactions continued to be reflected in customer rates and was reflected in the carryover basis of the assets when sold, Southern Company Gas continued to record depreciation on those assets through the respective date that each transaction closed.

The following table provides Southern Company's and Southern Power's major classes of assets and liabilities classified as held for sale at September 30, 2018:

	Southern Company		Southern Power
	(in millions)
Assets Held for Sale:
Current assets	$	407	$	18
Total property, plant, and equipment	4,093		168
Other non-current assets	574		17
Total Assets Held for Sale	$	5,074	$	203
Liabilities Held for Sale:
Current liabilities	$	355	$	4
Long-term debt	1,285		—
Accumulated deferred income taxes	542		—
Other non-current liabilities	1,008		—
Total Liabilities Held for Sale	$	3,190	$	4

Southern Company, Southern Power, and Southern Company Gas 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 the Florida Plants represent individually significant components of Southern Company and Southern Power, respectively; therefore, pre-tax profit for these components for the three and nine months ended September 30, 2018 and 2017 is presented below:

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2018		2017		2018		2017
	(in millions)				(in millions)
Earnings before income taxes:
Gulf Power	$	59	$	103	$	146	$	199
Southern Power's Florida Plants	$	18	$	11	$	40	$	28

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Variable Interest Entity and Equity Method Investments

9 Months Ended

Sep. 30, 2018

Regulated Operations [Abstract]

VARIABLE INTEREST ENTITY AND EQUITY METHOD INVESTMENTS

VARIABLE INTEREST ENTITY AND EQUITY METHOD INVESTMENTS

Southern Power

In May 2018, Southern Power sold a 33% limited partnership interest in SPSH to Global Atlantic. See Note (J) under "Southern Power" for additional information. A wholly-owned subsidiary of Southern Power is the general partner and holds a 1% ownership interest in SPSH and another wholly-owned subsidiary of Southern Power owns the remaining 66% ownership in SPSH. SPSH is a variable interest entity (VIE) because the arrangement is structured as a limited partnership and the 33% limited partner does not have substantive kick-out rights against the general partner. Southern Power previously consolidated SPSH and will continue to do so as the primary beneficiary of the VIE because it controls the most significant activities of the partnership, including operating and maintaining its assets.

At September 30, 2018, SPSH had total assets of $6.4 billion, total liabilities of $111 million, and noncontrolling interests related to other partners' interests of $1.2 billion. Cash distributions from SPSH are allocated 67% to Southern Power and 33% to Global Atlantic in accordance with their membership interests and the limited partnership agreement.

Transfers and sales of the assets in the VIE are subject to limited partner consent and the liabilities do not have recourse to the general credit of Southern Power. Liabilities consist of customary working capital items and do not include any long-term debt.

Southern Company Gas

See Note 4 to the financial statements of Southern Company Gas 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 September 30, 2018 and December 31, 2017 and related income from those investments for the three and nine-month periods ended September 30, 2018 and September 30, 2017 were as follows:

Investment Balance	September 30, 2018		December 31, 2017
	(in millions)
SNG	$	1,260	$	1,262
Atlantic Coast Pipeline	73		41
PennEast Pipeline	70		57
Other	126		117
Total	$	1,529	$	1,477

Earnings from Equity Method Investments	Three Months Ended September 30, 2018		Three Months Ended September 30, 2017		Nine Months Ended September 30, 2018		Nine Months Ended September 30, 2017
	(in millions)
SNG	$	29	$	28	$	95	$	86
PennEast Pipeline	2		1		4		5
Atlantic Coast Pipeline	1		1		4		4
Other	2		2		5		5
Total	$	34	$	32	$	108	$	100

Southern Natural Gas

Selected financial information of SNG for the three and nine months ended September 30, 2018 and September 30, 2017 is as follows:

Income Statement Information	Three Months Ended September 30, 2018		Three Months Ended September 30, 2017		Nine Months Ended September 30, 2018		Nine Months Ended September 30, 2017
	(in millions)
Revenues	$	145	$	146	$	451	$	445
Operating income	$	71	$	71	$	230	$	218
Net income	$	58	$	57	$	190	$	172

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Segment and Related Information

9 Months Ended

Sep. 30, 2018

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 four traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four 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 marketing services, wholesale gas services, and gas midstream operations. In July 2018, Southern Company Gas completed sales of three of its natural gas distribution utilities. See Note (J) under "Southern Company Gas" for additional information.

Southern Company's reportable business segments are the sale of electricity by the four 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 $134 million and $326 million for the three and nine months ended September 30, 2018, respectively, and $105 million and $295 million for the three and nine months ended September 30, 2017, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were $14 million and $22 million for the three and nine months ended September 30, 2018, respectively, and $9 million and $19 million for the three and nine months ended September 30, 2017, respectively. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $38 million and $96 million for the three and nine months ended September 30, 2018, respectively, and $38 million and $94 million for the three and nine months ended September 30, 2017, 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 technologies and services to electric utilities and large industrial, commercial, institutional, and municipal 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 nine months ended September 30, 2018 and 2017 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 September 30, 2018:
Operating revenues	$	5,014	$	635	$	(140	)	$	5,509	$	492	$	202		$	(44	)	$	6,159
Segment net income (loss)(a)(b)(c)(d)	1,148		92		—			1,240		46		(119		)	(3		)	1,164
Nine Months Ended September 30, 2018:
Operating revenues	$	13,117	$	1,699	$	(360	)	$	14,456	$	2,861	$	984		$	(143	)	$	18,158
Segment net income (loss)(a)(b)(c)(d)	1,711		235		—			1,946		294		(292		)	—			1,948
At September 30, 2018:
Goodwill	$	—	$	2	$	—		$	2	$	5,015	$	298		$	—		$	5,315
Total assets	75,069		15,355		(322		)	90,102		20,398		3,086			(1,869		)	111,717
Three Months Ended September 30, 2017:
Operating revenues	$	5,017	$	618	$	(112	)	$	5,523	$	565	$	153		$	(40	)	$	6,201
Segment net income (loss)(a)(b)	1,008		124		—			1,132		15		(80		)	2			1,069
Nine Months Ended September 30, 2017:
Operating revenues	$	12,960	$	1,597	$	(318	)	$	14,239	$	2,841	$	442		$	(119	)	$	17,403
Segment net income (loss)(a)(b)(e)	—		276		—			276		303		(232		)	—			347
At December 31, 2017:
Goodwill	$	—	$	2	$	—		$	2	$	5,967	$	299		$	—		$	6,268
Total assets	72,204		15,206		(325		)	87,085		22,987		2,552			(1,619		)	111,005

(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 $1 million ($1 million after tax) and $34 million ($21 million after tax) for the three months ended September 30, 2018 and 2017, respectively, and $1.1 billion ($0.8 billion after tax) and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2018 and 2017, respectively. See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) under "Nuclear Construction" and "Kemper County Energy Facility" for additional information.

(c) Segment net income (loss) for Southern Power includes pre-tax impairment charges of $36 million ($27 million after tax) and $155 million ($116 million after tax) for the three and nine months ended September 30, 2018, respectively. See Note (J) under "Southern Power – Development Projects" and " – Sale of Florida Plants" for additional information.

(d) Segment net income (loss) for Southern Company Gas includes a net gain on dispositions of $353 million ($40 million gain after tax) and $317 million ($35 million loss after tax) for the three and nine months ended September 30, 2018, respectively, related to the Southern Company Gas Dispositions and a goodwill impairment charge of $42 million for the nine months ended September 30, 2018 related to the sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.

(e) Segment net income (loss) for the traditional electric operating companies includes a pre-tax charge for the write-down of Gulf Power's ownership of Plant Scherer Unit 3 of $33 million ($20 million after tax) for the nine months ended September 30, 2017. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2018	$	4,605	$	693	$	211	$	5,509
Three Months Ended September 30, 2017	4,615		718		190		5,523
Nine Months Ended September 30, 2018	$	11,913	$	1,923	$	620	$	14,456
Nine Months Ended September 30, 2017	11,786		1,867		586		14,239

	Southern Company Gas' Revenues
Period	Gas Distribution Operations		Gas Marketing Services		Other			Total
	(in millions)
Three Months Ended September 30, 2018	$	438	$	44	$	10		$	492
Three Months Ended September 30, 2017	430		143		(8		)	565
Nine Months Ended September 30, 2018	$	2,276	$	403	$	182		$	2,861
Nine Months Ended September 30, 2017	2,119		597		125			2,841

Southern Company Gas

Southern Company Gas manages its business through four reportable segments – gas distribution operations, gas marketing services, wholesale gas services, and gas midstream operations. 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 seven states. In July 2018, Southern Company Gas sold three of its natural gas distribution utilities, Elizabethtown Gas, Elkton Gas, and Florida City Gas. See Note (J) under "Southern Company Gas" for additional information.

Gas marketing services includes natural gas marketing to end-use customers primarily in Georgia and Illinois. On June 4, 2018, Southern Company Gas sold Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.

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 midstream operations primarily consists of Southern Company Gas' pipeline investments, with storage and fuel operations also aggregated into this segment.

The all other column includes segments below the quantitative threshold for separate disclosure, including the subsidiaries that fall below the quantitative threshold for separate disclosure.

Business segment financial data for the three and nine months ended September 30, 2018 and 2017 was as follows:

	Gas Distribution Operations(a)(c)		Gas Marketing Services(b)(c)			Wholesale Gas Services(d)			Gas Midstream Operations		Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended September 30, 2018:
Operating revenues	$	441	$	44		$	(8	)	$	20	$	497	$	1		$	(6	)	$	492
Segment net income (loss)	74		(8		)	(18		)	16		64		(18		)	—			46
Nine Months Ended September 30, 2018:
Operating revenues	2,297		403			142			60		2,902		3			(44		)	2,861
Segment net income (loss)	290		(71		)	65			54		338		(44		)	—			294
Total assets at September 30, 2018:	16,850		1,522			855			2,297		21,524		10,146			(11,272		)	20,398
Three Months Ended September 30, 2017:
Operating revenues	$	472	$	143		$	(24	)	$	16	$	607	$	2		$	(44	)	$	565
Segment net income (loss)	52		1			(23		)	14		44		(29		)	—			15
Nine Months Ended September 30, 2017:
Operating revenues	2,255		597			95			53		3,000		7			(166		)	2,841
Segment net income (loss)	223		36			28			38		325		(22		)	—			303
Total assets at December 31, 2017:	19,358		2,147			1,096			2,241		24,842		12,184			(14,039		)	22,987

(a) Operating revenues for the three gas distribution operations dispositions were $8 million and $50 million for the three months ended September 30, 2018 and 2017, respectively, and $245 million and $274 million for the nine months ended September 30, 2018 and 2017, respectively. See Note (J) under "Southern Company Gas" for additional information.

(b) Operating revenues for the gas marketing services disposition were $32 million for the three months ended September 30, 2017 and $55 million and $95 million for the nine months ended September 30, 2018 and 2017, respectively. See Note (J) under "Southern Company Gas" for additional information.

(c) Segment net income for gas distribution operations includes a gain on dispositions of $351 million ($38 million after tax) for the three and nine months ended September 30, 2018. Segment net income for gas marketing services includes a gain on disposition of $2 million ($2 million after tax) for the three months ended September 30, 2018 and a loss on disposition of $34 million ($73 million loss after tax) and a goodwill impairment charge of $42 million for the nine months ended September 30, 2018 recorded in contemplation of the sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.

(d) 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 September 30, 2018	$	1,573	$	82	$	1,655	$	1,663	$	(8	)
Three Months Ended September 30, 2017	1,411		103		1,514		1,538		(24		)
Nine Months Ended September 30, 2018	$	4,847	$	352	$	5,199	$	5,057	$	142
Nine Months Ended September 30, 2017	4,781		362		5,143		5,048		95

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Introduction (Policies)

9 Months Ended

Sep. 30, 2018

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, 2017 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 September 30, 2018 and 2017. 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.

Reclassification

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

Recently Adopted Accounting Standards

See Note 1 to the financial statements of the registrants under "Recently Issued Accounting Standards" in Item 8 of the Form 10-K for additional information.

Revenue

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry-specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. ASC 606 became effective on January 1, 2018 and the registrants adopted it using the modified retrospective method applied to open contracts and only to the version of the contracts in effect as of January 1, 2018. In accordance with the modified retrospective method, the registrants' previously issued financial statements have not been restated to comply with ASC 606 and the registrants did not have a cumulative-effect adjustment to retained earnings. The adoption of ASC 606 had no significant impact on the timing of revenue recognition compared to previously reported results; however, it requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers, which are included in Note (C).

ASC 606 provided additional clarity on financial statement presentation that resulted in reclassifications into other revenues and other operations and maintenance from other income/(expense), net at Alabama Power and Georgia Power related to certain unregulated sales of products and services. In addition, contract assets related to certain fixed retail revenues at Georgia Power and Southern Company's unregulated distributed generation business have been reclassified from unbilled revenue in accordance with the guidance in ASC 606. These reclassifications did not affect the timing or amount of revenues recognized or cash flows. ASC 606 also provided additional guidance on revenue recognized over time, resulting in a change in the timing of revenue recognized from guaranteed and fixed billing arrangements at Southern Company Gas. The changes in natural gas revenues recognized in the third quarter and year-to-date 2018 relate primarily to the seasonal nature of natural gas usage.

The net impact of accounting for revenue under ASC 606 decreased Southern Company's and Southern Company Gas' consolidated net income by $4 million for the three months ended September 30, 2018 and increased Southern Company's and Southern Company Gas' consolidated net income by $1 million for the nine months ended September 30, 2018.

The specific impacts of applying ASC 606 to revenues from contracts with customers on the financial statements of Southern Company, Alabama Power, Georgia Power, and Southern Company Gas compared to previously recognized guidance is shown below.

	For the Three Months Ended September 30, 2018							For the Nine Months Ended September 30, 2018
Condensed Statements of Income	As Reported		Balances Without Adoption of ASC 606		Effect of Change			As Reported		Balances Without Adoption of ASC 606		Effect of Change
	(in millions)							(in millions)
Southern Company
Natural gas revenues	$	492	$	497	$	(5	)	$	2,806	$	2,805	$	1
Other revenues	199		198		1			1,007		1,003		4
Other operations and maintenance	1,404		1,387		17			4,217		4,178		39
Operating income	2,174		2,195		(21		)	3,613		3,647		(34		)
Other income (expense), net	57		41		16			195		160		35
Earnings (loss) before income taxes	1,845		1,850		(5		)	2,629		2,628		1
Income taxes (benefit)	623		624		(1		)	598		598		—
Consolidated net income (loss)	1,222		1,226		(4		)	2,031		2,030		1
Consolidated net income (loss) attributable to Southern Company	1,164		1,168		(4		)	1,948		1,947		1
Alabama Power
Other revenues	$	68	$	59	$	9		$	199	$	173	$	26
Other operations and maintenance	401		390		11			1,191		1,159		32
Operating income	561		563		(2		)	1,313		1,319		(6		)
Other income (expense), net	9		7		2			24		18		6
Georgia Power
Other revenues	$	121	$	97	$	24		$	349	$	287	$	62
Other operations and maintenance	460		437		23			1,325		1,268		57
Operating income (loss)	991		990		1			1,032		1,027		5
Other income (expense), net	30		31		(1		)	104		109		(5		)
Southern Company Gas
Natural gas revenues	$	487	$	492	$	(5	)	$	2,829	$	2,828	$	1
Operating income	374		379		(5		)	810		809		1
Earnings before income taxes	362		367		(5		)	769		768		1
Income taxes	316		317		(1		)	475		475		—
Net income (loss)	46		50		(4		)	294		293		1

	For the Nine Months Ended September 30, 2018
Condensed Statements of Cash Flows	As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)
Southern Company
Consolidated net income	$	2,031		$	2,030		$	1
Changes in certain current assets and liabilities:
Receivables	37			27			10
Other current assets	(90		)	(80		)	(10		)
Other current liabilities	(67		)	(68		)	1
Georgia Power
Changes in certain current assets and liabilities:
Receivables	$	(205	)	$	(242	)	$	37
Other current assets	(36		)	1			(37		)
Southern Company Gas
Net income	$	294		$	293		$	1
Changes in certain current assets and liabilities:
Other current liabilities	35			34			1

	At September 30, 2018
Condensed Balance Sheets	As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)
Southern Company
Unbilled revenues	$	738		$	776		$	(38	)
Other accounts and notes receivable	690			691			(1		)
Other current assets	232			193			39
Other current liabilities	763			764			(1		)
Retained earnings	9,048			9,047			1
Georgia Power
Unbilled revenues	$	245		$	310		$	(65	)
Other accounts and notes receivable	96			97			(1		)
Other current assets	91			25			66
Southern Company Gas
Other current liabilities	122			123			(1		)
Accumulated deficit	(273		)	(274		)	1

Other

In 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statements of cash flows. In addition, the net change in cash and cash equivalents during the period includes amounts generally described as restricted cash or restricted cash equivalents. The registrants adopted ASU 2016-18 effective January 1, 2018 with no material impact on their financial statements. Southern Company, Southern Power, and Southern Company Gas retrospectively applied ASU 2016-18 effective January 1, 2018 and have restated prior periods in the statements of cash flows by immaterial amounts. The change in restricted cash in the statements of cash flows was previously disclosed in operating activities for Southern Company and Southern Company Gas and in investing activities for Southern Company and Southern Power. See "Restricted Cash" herein for additional information.

In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the statements of income outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. The registrants adopted ASU 2017-07 effective January 1, 2018 with no material impact on their financial statements. ASU 2017-07 has been applied retrospectively for the presentation of the service cost component and the other components of net periodic benefit costs in the statements of income for Southern Company, the traditional electric operating companies, and Southern Company Gas. Since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017, no retrospective presentation of Southern Power's net periodic benefits costs is required. The requirement to limit capitalization to the service cost component of net periodic benefit costs has been applied on a prospective basis from the date of adoption for all registrants. The presentation changes resulted in a decrease in operating income and an increase in other income for the three and nine months ended September 30, 2018 and 2017 for Southern Company, the traditional electric operating companies, and Southern Company Gas.

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12). ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The registrants adopted ASU 2017-12 effective January 1, 2018 with no material impact on their financial statements. See Note (I) for disclosures required by ASU 2017-12.

On February 14, 2018, the FASB issued ASU No. 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (ASU 2018-02) to address the application of ASC 740, Income Taxes (ASC 740) to certain provisions of the Tax Reform Legislation. ASU 2018-02 specifically addresses the ASC 740 requirement that the effect of a change in tax laws or rates on deferred tax assets and liabilities be included in income from continuing operations, even when the tax effects were initially recognized directly in OCI at the previous rate, which strands the income tax rate differential in accumulated OCI. The amendments in ASU 2018-02 allow a reclassification from accumulated OCI to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. The registrants adopted ASU 2018-02 effective January 1, 2018 with no material impact on their financial statements.

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

Restricted Cash

The registrants adopted ASU 2016-18 as of January 1, 2018. See "Recently Adopted Accounting Standards – Other" herein for additional information.

At December 31, 2017, Southern Power had restricted cash primarily related to certain acquisitions and construction projects. At both September 30, 2018 and December 31, 2017, Southern Company Gas had restricted cash held as collateral for worker's compensation, life insurance, and long-term disability insurance.

Natural Gas For Sale

Natural Gas for Sale

Southern Company Gas' natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a WACOG basis.

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. Southern Company Gas had no inventory decrement at September 30, 2018. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's or Southern Company Gas' net income.

Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower of weighted average cost or current market price, with cost determined 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.

Hypothetical Liquidation at Book Value

Hypothetical Liquidation at Book Value

Southern Power has consolidated renewable generation projects that are partially funded by a third-party tax equity investor. The related contractual provisions represent profit-sharing arrangements because the allocations of cash distributions and tax benefits are not based on fixed ownership percentages. Therefore, the noncontrolling interest is accounted for under a balance sheet approach utilizing the hypothetical liquidation at book value (HLBV) method. The HLBV method calculates each partner's share of income based on the change in net equity the partner can legally claim in a hypothetical liquidation at the end of the period compared to the beginning of the period.

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 (I) 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 1 to the financial statements of Southern Company, Alabama Power, and Georgia Power 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 date 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.

"Other investments" include investments that are not traded in the open market. The fair value of these investments has been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.

Earnings per Share

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 8 to the financial statements of Southern Company 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.

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 (D) for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. The 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.

The registrants adopted ASU 2017-12 as of January 1, 2018. See Note (A) under "Recently Adopted Accounting Standards – Other" for additional information.

Energy-Related Derivatives

Southern Company, 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 is expected to continue to mitigate price volatility. The Florida PSC approved a moratorium on Gulf Power's fuel-hedging program until January 1, 2021. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. 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 which are 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 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 may also 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.

Interest Rate Derivatives

Southern Company and certain subsidiaries may also 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.

XML

Introduction (Tables)

9 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of New Accounting Pronouncements and Changes in Accounting Principles

The specific impacts of applying ASC 606 to revenues from contracts with customers on the financial statements of Southern Company, Alabama Power, Georgia Power, and Southern Company Gas compared to previously recognized guidance is shown below.

	For the Three Months Ended September 30, 2018							For the Nine Months Ended September 30, 2018
Condensed Statements of Income	As Reported		Balances Without Adoption of ASC 606		Effect of Change			As Reported		Balances Without Adoption of ASC 606		Effect of Change
	(in millions)							(in millions)
Southern Company
Natural gas revenues	$	492	$	497	$	(5	)	$	2,806	$	2,805	$	1
Other revenues	199		198		1			1,007		1,003		4
Other operations and maintenance	1,404		1,387		17			4,217		4,178		39
Operating income	2,174		2,195		(21		)	3,613		3,647		(34		)
Other income (expense), net	57		41		16			195		160		35
Earnings (loss) before income taxes	1,845		1,850		(5		)	2,629		2,628		1
Income taxes (benefit)	623		624		(1		)	598		598		—
Consolidated net income (loss)	1,222		1,226		(4		)	2,031		2,030		1
Consolidated net income (loss) attributable to Southern Company	1,164		1,168		(4		)	1,948		1,947		1
Alabama Power
Other revenues	$	68	$	59	$	9		$	199	$	173	$	26
Other operations and maintenance	401		390		11			1,191		1,159		32
Operating income	561		563		(2		)	1,313		1,319		(6		)
Other income (expense), net	9		7		2			24		18		6
Georgia Power
Other revenues	$	121	$	97	$	24		$	349	$	287	$	62
Other operations and maintenance	460		437		23			1,325		1,268		57
Operating income (loss)	991		990		1			1,032		1,027		5
Other income (expense), net	30		31		(1		)	104		109		(5		)
Southern Company Gas
Natural gas revenues	$	487	$	492	$	(5	)	$	2,829	$	2,828	$	1
Operating income	374		379		(5		)	810		809		1
Earnings before income taxes	362		367		(5		)	769		768		1
Income taxes	316		317		(1		)	475		475		—
Net income (loss)	46		50		(4		)	294		293		1

	For the Nine Months Ended September 30, 2018
Condensed Statements of Cash Flows	As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)
Southern Company
Consolidated net income	$	2,031		$	2,030		$	1
Changes in certain current assets and liabilities:
Receivables	37			27			10
Other current assets	(90		)	(80		)	(10		)
Other current liabilities	(67		)	(68		)	1
Georgia Power
Changes in certain current assets and liabilities:
Receivables	$	(205	)	$	(242	)	$	37
Other current assets	(36		)	1			(37		)
Southern Company Gas
Net income	$	294		$	293		$	1
Changes in certain current assets and liabilities:
Other current liabilities	35			34			1

	At September 30, 2018
Condensed Balance Sheets	As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)
Southern Company
Unbilled revenues	$	738		$	776		$	(38	)
Other accounts and notes receivable	690			691			(1		)
Other current assets	232			193			39
Other current liabilities	763			764			(1		)
Retained earnings	9,048			9,047			1
Georgia Power
Unbilled revenues	$	245		$	310		$	(65	)
Other accounts and notes receivable	96			97			(1		)
Other current assets	91			25			66
Southern Company Gas
Other current liabilities	122			123			(1		)
Accumulated deficit	(273		)	(274		)	1

Schedule of Change in Asset Retirement Obligation

As of September 30, 2018, details of the AROs, including those related to the CCR Rule, included in the condensed balance sheets of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power were as follows:

	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Balance at December 31, 2017	$	4,824		$	1,709		$	2,638		$	142		$	174
Liabilities incurred	2			—			—			—			—
Liabilities settled	(160		)	(31		)	(82		)	(23		)	(22		)
Accretion	153			72			70			3			4
Cash flow revisions	1,510			1,451			(32		)	42			21
Reclassification to held for sale	(164		)	—			—			—			—
Balance at September 30, 2018	$	6,165		$	3,201		$	2,594		$	164		$	177

Estimated Cost Of Decommissioning

In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated costs of decommissioning based on the 2018 site study are as follows:

Decommissioning periods:
Beginning year	2037
Completion year	2076
	(in millions)
Site study costs:
Radiated structures	$	1,621
Non-radiated structures	99
Total site study costs	$	1,720

Schedule of Goodwill

The following table presents year-to-date changes in goodwill balances for Southern Company and Southern Company Gas:

	Goodwill
	Southern Company				Southern Company Gas
					Gas Distribution Operations			Gas Marketing Services			Total
	(in millions)
Balance at December 31, 2017	$	6,268			$	4,702		$	1,265		$	5,967
Impairment(a)	(42		)		—			(42		)	(42		)
Dispositions(b)	(910		)		(668		)	(242		)	(910		)
Balance at September 30, 2018	$	5,315		(c)	$	4,034		$	981		$	5,015

(a) On April 11, 2018, Southern Company Gas entered into a stock purchase agreement for the sale of Pivotal Home Solutions. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded in the first quarter 2018. See Note (J) under "Southern Company Gas" for additional information.

(b) Gas distribution operations reflects goodwill allocated to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold during the third quarter 2018. Gas marketing services reflects goodwill associated with Pivotal Home Solutions, which was sold on June 4, 2018. See Note (J) under "Southern Company Gas" for additional information.

(c) Total does not add due to rounding.

Schedule of Other Intangible Assets, Finite-Lived

Other intangible assets were as follows:

	At September 30, 2018							At December 31, 2017
	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(*)	$	223	$	(87	)	$	136	$	288	$	(83	)	$	205
Trade names(*)	70		(18		)	52		159		(17		)	142
Storage and transportation contracts	64		(49		)	15		64		(34		)	30
PPA fair value adjustments	456		(66		)	390		456		(47		)	409
Other	11		(5		)	6		17		(5		)	12
Total other intangible assets subject to amortization	$	824	$	(225	)	$	599	$	984	$	(186	)	$	798
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—			75		75		—			75
Total other intangible assets	$	899	$	(225	)	$	674	$	1,059	$	(186	)	$	873
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	456	$	(66	)	$	390	$	456	$	(47	)	$	409
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services(*)
Customer relationships	$	156	$	(78	)	$	78	$	221	$	(77	)	$	144
Trade names	26		(6		)	20		115		(9		)	106
Wholesale gas services
Storage and transportation contracts	64		(49		)	15		64		(34		)	30
Total other intangible assets subject to amortization	$	246	$	(133	)	$	113	$	400	$	(120	)	$	280

(*) Balances as of September 30, 2018 reflect Southern Company Gas' sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

Schedule of Other Intangible Assets, Indefinite-Lived

Other intangible assets were as follows:

	At September 30, 2018							At December 31, 2017
	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(*)	$	223	$	(87	)	$	136	$	288	$	(83	)	$	205
Trade names(*)	70		(18		)	52		159		(17		)	142
Storage and transportation contracts	64		(49		)	15		64		(34		)	30
PPA fair value adjustments	456		(66		)	390		456		(47		)	409
Other	11		(5		)	6		17		(5		)	12
Total other intangible assets subject to amortization	$	824	$	(225	)	$	599	$	984	$	(186	)	$	798
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—			75		75		—			75
Total other intangible assets	$	899	$	(225	)	$	674	$	1,059	$	(186	)	$	873
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	456	$	(66	)	$	390	$	456	$	(47	)	$	409
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services(*)
Customer relationships	$	156	$	(78	)	$	78	$	221	$	(77	)	$	144
Trade names	26		(6		)	20		115		(9		)	106
Wholesale gas services
Storage and transportation contracts	64		(49		)	15		64		(34		)	30
Total other intangible assets subject to amortization	$	246	$	(133	)	$	113	$	400	$	(120	)	$	280

(*) Balances as of September 30, 2018 reflect Southern Company Gas' sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

Finite-lived Intangible Assets Amortization Expense

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Nine Months Ended
	September 30, 2018
	(in millions)
Southern Company	$	21	$	70
Southern Power	$	6	$	19
Southern Company Gas	$	12	$	42

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 September 30, 2018 and/or December 31, 2017:

	Southern Company			Southern Company Gas
	(in millions)
At September 30, 2018
Cash and cash equivalents	$	1,847		$	56
Cash and cash equivalents classified as assets held for sale	37			—
Restricted cash:
Other accounts and notes receivable	6			6
Total cash, cash equivalents, and restricted cash	$	1,891	(*)	$	62

(*) Total does not add due to rounding.

	Southern Company		Southern Power		Southern Company Gas
	(in millions)
At December 31, 2017
Cash and cash equivalents	$	2,130	$	129	$	73
Restricted cash:
Other accounts and notes receivable	5		—		5
Deferred charges and other assets	12		11		—
Total cash, cash equivalents, and restricted cash	$	2,147	$	140	$	78

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 September 30, 2018 and/or December 31, 2017:

	Southern Company			Southern Company Gas
	(in millions)
At September 30, 2018
Cash and cash equivalents	$	1,847		$	56
Cash and cash equivalents classified as assets held for sale	37			—
Restricted cash:
Other accounts and notes receivable	6			6
Total cash, cash equivalents, and restricted cash	$	1,891	(*)	$	62

(*) Total does not add due to rounding.

	Southern Company		Southern Power		Southern Company Gas
	(in millions)
At December 31, 2017
Cash and cash equivalents	$	2,130	$	129	$	73
Restricted cash:
Other accounts and notes receivable	5		—		5
Deferred charges and other assets	12		11		—
Total cash, cash equivalents, and restricted cash	$	2,147	$	140	$	78

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Contingencies and Regulatory Matters (Tables)

9 Months Ended

Sep. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Cost Recovery Clauses

The balance of each regulatory clause recovery on the balance sheet follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2018		December 31, 2017
		(in millions)
Rate CNP Compliance	Deferred under recovered regulatory clause revenues	$	—	$	17
	Under recovered regulatory clause revenues	7		—
Rate CNP PPA	Deferred under recovered regulatory clause revenues	30		12
Retail Energy Cost Recovery	Deferred under recovered regulatory clause revenues	58		25
	Under recovered regulatory clause revenues	41		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	24		38

Regulatory clause recovery balances included in the balance sheets are as follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2018		December 31, 2017
		(in millions)
Fuel Cost Recovery	Under recovered regulatory clause revenues	$	—	$	22
Fuel Cost Recovery	Other regulatory liabilities, current	23		—
Purchased Power Capacity Recovery	Other regulatory liabilities, current	4		—
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	—		2
Environmental Cost Recovery(*)	Other regulatory liabilities, current	13		—
Environmental Cost Recovery(*)	Under recovered regulatory clause revenues	—		2
Energy Conservation Cost Recovery	Other regulatory liabilities, current	2		—

(*) At September 30, 2018 and December 31, 2017, the over and under recovered balances, respectively, included in the balance sheets represents the current portion of the regulatory assets associated with projected environmental expenditures of approximately $8 million and $13 million, respectively, net of the over recovered environmental cost recovery balance of approximately $21 million and $11 million, respectively.

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 September 30, 2018(b)	(4.3		)
Remaining estimate to complete(a)	$	4.1

(a) Excludes financing costs expected to be capitalized through AFUDC of approximately $350 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)

9 Months Ended

Sep. 30, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following tables disaggregate revenue sources for the three and nine months ended September 30, 2018:

	For the Three Months Ended September 30, 2018		For the Nine Months Ended September 30, 2018
	(in millions)
Southern Company
Operating revenues
Retail electric revenues(a)
Residential	$	2,148	$	5,266
Commercial	1,527		4,084
Industrial	901		2,471
Other	29		92
Natural gas distribution revenues	433		2,299
Alternative revenue programs(b)	5		(23		)
Total retail electric and gas distribution revenues	$	5,043	$	14,189
Wholesale energy revenues(c)(d)	516		1,444
Wholesale capacity revenues(d)	177		479
Other natural gas revenues(e)	54		530
Other revenues(f)	369		1,516
Total operating revenues	$	6,159	$	18,158

(a) Retail electric revenues include $17 million and $54 million of leases for the three and nine months ended September 30, 2018, respectively, and a (net reduction) or net increase of $(98) million and $4 million for the three and nine months ended September 30, 2018, respectively, from certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 3 to the financial statements of Southern Company under "Regulatory Matters" in Item 8 of the Form 10-K for additional information on cost recovery mechanisms.

(b) See Note 1 to the financial statements of Southern Company under "Revenues" in Item 8 of the Form 10-K for additional information on alternative revenue programs at the natural gas distribution utilities. Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(c) Wholesale energy revenues include $63 million and $217 million for the three and nine months ended September 30, 2018, respectively, of revenues accounted for as derivatives, primarily related to physical energy sales in the wholesale electricity market. See Note (I) for additional information on energy-related derivative contracts.

(d) Wholesale energy and wholesale capacity revenues include $130 million and $31 million, respectively, for the three months ended September 30, 2018 and $318 million and $92 million, respectively, for the nine months ended September 30, 2018 of PPA contracts accounted for as leases.

(e) 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 $1.6 billion and $4.8 billion for the three and nine months ended September 30, 2018, respectively, of which $0.9 billion and $2.7 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.

(f) Other revenues include $92 million and $274 million for the three and nine months ended September 30, 2018, respectively, of revenues not accounted for under ASC 606.

	Alabama Power		Georgia Power		Gulf Power		Mississippi Power
	(in millions)
For the Three Months Ended September 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	721	$	1,142	$	200	$	85
Commercial	464		877		103		82
Industrial	392		385		37		86
Other	7		21		1		1
Total retail electric revenues	$	1,584	$	2,425	$	341	$	254
Wholesale energy revenues(c)	62		33		48		92
Wholesale capacity revenues	26		14		7		1
Other revenues(b)(d)	68		121		18		11
Total operating revenues	$	1,740	$	2,593	$	414	$	358
For the Nine Months Ended September 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	1,848	$	2,671	$	537	$	209
Commercial	1,238		2,343		291		212
Industrial	1,103		1,036		100		233
Other	19		62		4		6
Total retail electric revenues	$	4,208	$	6,112	$	932	$	660
Wholesale energy revenues(c)	234		99		104		259
Wholesale capacity revenues	75		41		20		6
Other revenues(b)(d)	199		349		50		31
Total operating revenues	$	4,716	$	6,601	$	1,106	$	956

(a) Retail revenues at Alabama Power, Georgia Power, Gulf Power, and Mississippi Power include a net increase or (net reduction) of $(12) million, $(47) million, $(36) million, and $(3) million, respectively, for the three months ended September 30, 2018 and $113 million, $(35) million, $(63) million, and $(11) million, respectively, for the nine months ended September 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 3 to the financial statements of Alabama Power, Georgia Power, Gulf Power, and Mississippi Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information on cost recovery mechanisms.

(b) Retail revenues and other revenues at Georgia Power include $17 million and $34 million, respectively, for the three months ended September 30, 2018 and $54 million and $100 million, respectively, for the nine months ended September 30, 2018 of revenues accounted for as leases.

(c) Wholesale energy revenues at Alabama Power and Georgia Power include $6 million and $8 million, respectively, for the three months ended September 30, 2018 and $14 million and $21 million, respectively, for the nine months ended September 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market. See Note (I) for additional information on energy-related derivative contracts.

(d) Other revenues at Alabama Power, Georgia Power, and Gulf Power include $27 million, $28 million, and $2 million, respectively, for the three months ended September 30, 2018 and $79 million, $80 million, and $5 million, respectively, for the nine months ended September 30, 2018 of revenues not accounted for under ASC 606.

	For the Three Months Ended September 30, 2018		For the Nine Months Ended September 30, 2018
	(in millions)
Southern Power
PPA capacity revenues(a)	$	168	$	450
PPA energy revenues(a)	336		892
Non-PPA revenues(b)	126		347
Other revenues	5		10
Total operating revenues	$	635	$	1,699

(a) PPA capacity revenues and PPA energy revenues include $47 million and $139 million, respectively, for the three months ended September 30, 2018 and $141 million and $342 million, respectively, for the nine months ended September 30, 2018 related to PPAs accounted for as leases. See Note 1 to the financial statements of Southern Power under "Revenues" in Item 8 of the Form 10-K for additional information on capacity revenues accounted for as leases.

(b) Non-PPA revenues include $47 million and $176 million for the three and nine months ended September 30, 2018, respectively, of revenues from short-term sales related to physical energy sales from uncovered capacity in the wholesale electricity market. See Note 1 to the financial statements of Southern Power under "Revenues" in Item 8 of the Form 10-K and Note (I) for additional information on energy-related derivative contracts.

	For the Three Months Ended September 30, 2018			For the Nine Months Ended September 30, 2018
	(in millions)
Southern Company Gas
Operating revenues
Natural gas distribution revenues
Residential	$	149		$	1,082
Commercial	45			313
Transportation	203			708
Industrial	4			28
Other	32			168
Alternative revenue programs(a)	5			(23		)
Total natural gas distribution revenues	$	438		$	2,276
Gas marketing services(b)	44			403
Wholesale gas services(c)	(10		)	121
Gas midstream operations	20			60
Other revenues	—			1
Total operating revenues	$	492		$	2,861

(a) See Note 1 to the financial statements of Southern Company Gas under "Revenues" in Item 8 of the Form 10-K for additional information on alternative revenue programs at the natural gas distribution utilities. Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(b) Gas marketing services includes $4 million for the nine months ended September 30, 2018 of revenues not accounted for under ASC 606.

(c) 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 $1.6 billion and $4.8 billion for the three and nine months ended September 30, 2018, respectively, of which $0.9 billion and $2.7 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues and Note (I) for additional information on energy-related derivative contracts.

Contract with Customer, Asset and Liability

The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers as of September 30, 2018:

	Receivables		Contract Assets		Contract Liabilities
	(in millions)
Southern Company	$	2,778	$	99	$	34
Alabama Power	649		1		14
Georgia Power	924		70		3
Gulf Power	186		—		—
Mississippi Power	96		—		—
Southern Power	142		—		17
Southern Company Gas	523		—		1

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

Revenues from contracts with customers related to these performance obligations remaining at September 30, 2018 are expected to be recognized as follows:

	2018		2019		2020		2021		2022		2023 and Thereafter
	(in millions)
Southern Company(*)	$	168	$	406	$	322	$	322	$	310	$	2,112
Alabama Power	6		22		22		26		23		161
Georgia Power	10		41		38		40		30		113
Gulf Power	5		22		—		—		—		—
Mississippi Power	1		3		3		1		—		—
Southern Power(*)	75		310		283		277		276		2,005

(*) Excludes amounts related to held for sale assets. See Note (J) under "Southern Company's Sale of Gulf Power" and "Southern Power – Sale of Florida Plants" for additional information.

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2018

Fair Value Disclosures [Abstract]

Assets and Liabilities Measured at Fair Value on a Recurring Basis

As of September 30, 2018, 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 September 30, 2018:	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)(b)	$	271	$	150	$	—	$	—	$	421
Foreign currency derivatives	—		122		—		—		122
Nuclear decommissioning trusts(c)	828		1,007		—		37		1,872
Non-qualified deferred compensation trusts:
Domestic equity	—		11		—		—		11
Foreign equity	—		6		—		—		6
Pooled funds – fixed income	—		13		—		—		13
Cash equivalents	15		—		—		—		15
Other	9		—		—		—		9
Cash equivalents	1,309		—		—		—		1,309
Total	$	2,432	$	1,309	$	—	$	37	$	3,778
Liabilities:
Energy-related derivatives(a)(b)	$	416	$	159	$	—	$	—	$	575
Interest rate derivatives	—		72		—		—		72
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		22		—		22
Total	$	416	$	254	$	22	$	—	$	692

	Fair Value Measurements Using:
As of September 30, 2018:	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	$	—	$	7	$	—	$	—	$	7
Nuclear decommissioning trusts:(d)
Domestic equity	469		89		—		—		558
Foreign equity	60		56		—		—		116
U.S. Treasury and government agency securities	—		18		—		—		18
Corporate bonds	26		154		—		—		180
Mortgage and asset backed securities	—		22		—		—		22
Private equity	—		—		—		37		37
Other	7		—		—		—		7
Cash equivalents	513		—		—		—		513
Total	$	1,075	$	346	$	—	$	37	$	1,458
Liabilities:
Energy-related derivatives	$	—	$	10	$	—	$	—	$	10
Georgia Power
Assets:
Energy-related derivatives	$	—	$	8	$	—	$	—	$	8
Nuclear decommissioning trusts:(d)(e)
Domestic equity	250		1		—		—		251
Foreign equity	—		134		—		—		134
U.S. Treasury and government agency securities	—		236		—		—		236
Municipal bonds	—		82		—		—		82
Corporate bonds	—		163		—		—		163
Mortgage and asset backed securities	—		42		—		—		42
Other	16		9		—		—		25
Cash equivalents	350		—		—		—		350
Total	$	616	$	675	$	—	$	—	$	1,291
Liabilities:
Energy-related derivatives	$	—	$	22	$	—	$	—	$	22
Interest rate derivatives	—		6		—		—		6
Total	$	—	$	28	$	—	$	—	$	28
Gulf Power
Assets:
Cash equivalents	$	27	$	—	$	—	$	—	$	27
Liabilities:
Energy-related derivatives	$	—	$	8	$	—	$	—	$	8

	Fair Value Measurements Using:
As of September 30, 2018:	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	346		—		—		—		346
Total	$	346	$	3	$	—	$	—	$	349
Liabilities:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9
Southern Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Foreign currency derivatives	—		122		—		—		122
Total	$	—	$	125	$	—	$	—	$	125
Liabilities:
Energy-related derivatives	$	—	$	7	$	—	$	—	$	7
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		22		—		22
Total	$	—	$	30	$	22	$	—	$	52
Southern Company Gas
Assets:
Energy-related derivatives(a)(b)	$	271	$	129	$	—	$	—	$	400
Non-qualified deferred compensation trusts:
Domestic equity	—		11		—		—		11
Foreign equity	—		6		—		—		6
Pooled funds – fixed income	—		13		—		—		13
Cash equivalents	4		—		—		—		4
Cash equivalents	26		—		—		—		26
Total	$	301	$	159	$	—	$	—	$	460
Liabilities:
Energy-related derivatives(a)(b)	$	416	$	101	$	—	$	—	$	517

(a) Excludes $5 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value.

(b) Excludes cash collateral of $189 million.

(c) For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.

(d) Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies.

(e) Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of September 30, 2018, approximately $37 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.

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 for the three and nine months ended September 30, 2018 and 2017 by the amounts shown in the table below. The increases were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.

	Three Months Ended September 30, 2018		Three Months Ended September 30, 2017		Nine Months Ended September 30, 2018		Nine Months Ended September 30, 2017
	(in millions)
Southern Company	$	58	$	50	$	68	$	168
Alabama Power	39		25		49		87
Georgia Power	19		25		19		81

Fair Value Measurements of Investments Calculated at Net Asset Value per Share as Well as the Nature and Risk of Those Investments

As of September 30, 2018, the fair value measurements of private equity investments held in the nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:

As of September 30, 2018:	Fair Value		Unfunded Commitments
	(in millions)
Southern Company	$	37	$	47
Alabama Power	$	37	$	47

Financial Instruments for Which Carrying Amount Did Not Equal Fair Value

As of September 30, 2018, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Carrying Amount		Fair Value
	(in millions)
Long-term debt, including securities due within one year:
Southern Company	$	45,524	$	45,500
Alabama Power	8,120		8,321
Georgia Power	10,227		10,159
Gulf Power	1,285		1,290
Mississippi Power	1,736		1,702
Southern Power	5,029		5,058
Southern Company Gas	5,908		5,935

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Stockholders' Equity (Tables)

9 Months Ended

Sep. 30, 2018

Equity [Abstract]

Earnings per Share

Shares used to compute diluted earnings per share were as follows:

	Three Months Ended September 30, 2018	Three Months Ended September 30, 2017	Nine Months Ended September 30, 2018	Nine Months Ended September 30, 2017
	(in millions)
As reported shares	1,023	1,003	1,016	998
Effect of stock-based compensation	6	7	5	7
Diluted shares	1,029	1,010	1,021	1,005

Changes in Stockholders' Equity

The following table presents year-to-date changes in stockholders' equity of Southern Company:

	Number of Common Shares			Common Stockholders' Equity			Preferred and Preference Stock of Subsidiaries						Total Stockholders' Equity
	Issued	Treasury								Noncontrolling Interests(a)
	(in thousands)			(in millions)
Balance at December 31, 2017	1,008,532	(929	)	$	24,167		$	—		$	1,361		$	25,528
Consolidated net income attributable to Southern Company	—	—		1,948			—			—			1,948
Other comprehensive income	—	—		52			—			—			52
Stock issued	21,342	—		878			—			—			878
Stock-based compensation	—	—		74			—			—			74
Cash dividends on common stock	—	—		(1,805		)	—			—			(1,805		)
Contributions from noncontrolling interests	—	—		—			—			154			154
Distributions to noncontrolling interests	—	—		—			—			(87		)	(87		)
Net income attributable to noncontrolling interests	—	—		—			—			71			71
Sale of noncontrolling interests(b)	—	—		(410		)	—			1,690			1,280
Other	—	(57	)	(27		)	—			(1		)	(28		)
Balance at September 30, 2018	1,029,874	(986	)	$	24,877		$	—		$	3,188		$	28,065
Balance at December 31, 2016	991,213	(819	)	$	24,758		$	609		$	1,245		$	26,612
Consolidated net income attributable to Southern Company	—	—		347			—			—			347
Other comprehensive income (loss)	—	—		(2		)	—			—			(2		)
Stock issued	13,308	—		613			—			—			613
Stock-based compensation	—	—		97			—			—			97
Cash dividends on common stock	—	—		(1,716		)	—			—			(1,716		)
Preference stock redemption	—	—		—			(150		)	—			(150		)
Contributions from noncontrolling interests	—	—		—			—			77			77
Distributions to noncontrolling interests	—	—		—			—			(87		)	(87		)
Net income attributable to noncontrolling interests	—	—		—			—			45			45
Reclassification from redeemable noncontrolling interests	—	—		—			—			114			114
Other	—	(75	)	(15		)	3			1			(11		)
Balance at September 30, 2017	1,004,521	(894	)	$	24,082		$	462		$	1,395		$	25,939

(a) Primarily related to Southern Power and excludes redeemable noncontrolling interests. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(b) See Note (J) under "Southern Power – Sale of Solar Facility Interests" for additional information.

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Financing (Tables)

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Credit Arrangements by Company

The following table outlines the committed credit arrangements by company as of September 30, 2018:

	Expires												Executable Term Loans		Expires Within One Year
Company	2018		2019		2020		2022		Total		Unused		One Year		Term Out		No Term Out
	(in millions)
Southern Company(a)	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—	$	—	$	—
Alabama Power	—		33		500		800		1,333		1,333		—		—		33
Georgia Power	—		—		—		1,750		1,750		1,736		—		—		—
Gulf Power	20		25		235		—		280		280		45		45		—
Mississippi Power	—		100		—		—		100		100		—		—		—
Southern Power Company(b)	—		—		—		750		750		728		—		—		—
Southern Company Gas(c)	—		—		—		1,900		1,900		1,895		—		—		—
Other	—		30		—		—		30		30		—		—		30
Southern Company Consolidated	$	20	$	188	$	735	$	7,200	$	8,143	$	8,101	$	45	$	45	$	63

(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 2019, of which $22 million remains unused at September 30, 2018.

(c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.

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 nine months of 2018:

Company	Senior Note Issuances		Senior Note Maturities, Redemptions, and Repurchases		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Issuances		Other Long-Term Debt Redemptions and Maturities(a)
	(in millions)
Southern Company(b)	$	750	$	1,000	$	—	$	—	$	—
Alabama Power	500		—		—		—		—
Georgia Power	—		1,000		469		—		107
Mississippi Power	600		—		43		—		900
Southern Power	—		350		—		—		420
Southern Company Gas	—		—		200		100		—
Other	—		—		—		—		10
Elimination(c)	—		—		—		—		(1		)
Southern Company Consolidated	$	1,850	$	2,350	$	712	$	100	$	1,436

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

(b) Represents the Southern Company parent entity.

(c) Represents reductions in affiliate capital lease obligations at Georgia Power, which are eliminated in Southern Company's Consolidated Financial Statements.

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Retirement Benefits (Tables)

9 Months Ended

Sep. 30, 2018

Retirement Benefits [Abstract]

Pension Plans and Postretirement Plans

Components of the net periodic benefit costs for the three and nine months ended September 30, 2018 and 2017 are presented in the following tables.

Three Months Ended September 30, 2018	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	90		$	19		$	22		$	4		$	5		$	3		$	8
Interest cost	116			26			34			5			5			1			10
Expected return on plan assets	(236		)	(51		)	(74		)	(10		)	(11		)	(3		)	(18		)
Amortization:
Prior service costs	1			—			1			—			—			—			(1		)
Regulatory asset	—			—			—			—			—			—			4
Net (gain)/loss	53			13			18			2			3			—			3
Net periodic pension cost (income)	$	24		$	7		$	1		$	1		$	2		$	1		$	6
Postretirement Benefits
Service cost	$	6		$	1		$	2		$	—		$	—		$	1		$	—
Interest cost	19			5			7			1			—			—			2
Expected return on plan assets	(17		)	(7		)	(6		)	—			—			—			(1		)
Amortization:
Prior service costs	2			1			—			—			—			—			—
Regulatory asset	—			—			—			—			—			—			2
Net (gain)/loss	3			—			2			—			—			—			—
Net periodic postretirement benefit cost	$	13		$	—		$	5		$	1		$	—		$	1		$	3

Nine Months Ended September 30, 2018	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	269		$	58		$	65		$	12		$	13		$	7		$	24
Interest cost	348			76			104			15			15			4			29
Expected return on plan assets	(707		)	(155		)	(222		)	(30		)	(31		)	(8		)	(53		)
Amortization:
Prior service costs	3			1			2			—			—			—			(2		)
Regulatory asset	—			—			—			—			—			—			11
Net (gain)/loss	160			40			52			7			8			1			9
Net periodic pension cost (income)	$	73		$	20		$	1		$	4		$	5		$	4		$	18
Postretirement Benefits
Service cost	$	18		$	4		$	5		$	1		$	1		$	1		$	1
Interest cost	56			13			21			2			2			—			7
Expected return on plan assets	(51		)	(20		)	(19		)	(1		)	(1		)	—			(5		)
Amortization:
Prior service costs	5			3			1			—			—			—			—
Regulatory asset	—			—			—			—			—			—			5
Net (gain)/loss	10			1			6			—			—			—			—
Net periodic postretirement benefit cost	$	38		$	1		$	14		$	2		$	2		$	1		$	8

Three Months Ended September 30, 2017(*)	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	73		$	15		$	19		$	3		$	4		$	6
Interest cost	114			25			34			5			5			10
Expected return on plan assets	(224		)	(49		)	(71		)	(10		)	(9		)	(18		)
Amortization:
Prior service costs	3			1			—			—			—			—
Net (gain)/loss	41			10			15			2			1			5
Net periodic pension cost (income)	$	7		$	2		$	(3	)	$	—		$	1		$	3
Postretirement Benefits
Service cost	$	6		$	1		$	2		$	—		$	—		$	1
Interest cost	19			4			6			1			1			3
Expected return on plan assets	(16		)	(5		)	(6		)	—			—			(2		)
Amortization:
Prior service costs	2			1			—			—			—			(1		)
Net (gain)/loss	3			—			3			—			—			1
Net periodic postretirement benefit cost	$	14		$	1		$	5		$	1		$	1		$	2

(*) Excludes Southern Power since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017.

Nine Months Ended September 30, 2017(*)	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	220		$	47		$	56		$	10		$	11		$	17
Interest cost	341			73			103			15			15			30
Expected return on plan assets	(673		)	(147		)	(212		)	(29		)	(29		)	(53		)
Amortization:
Prior service costs	9			2			2			—			1			(1		)
Net (gain)/loss	122			31			43			5			5			15
Net periodic pension cost (income)	$	19		$	6		$	(8	)	$	1		$	3		$	8
Postretirement Benefits
Service cost	$	18		$	4		$	5		$	1		$	1		$	2
Interest cost	59			13			21			2			3			8
Expected return on plan assets	(49		)	(19		)	(18		)	(1		)	(1		)	(5		)
Amortization:
Prior service costs	5			3			1			—			—			(2		)
Net (gain)/loss	10			1			6			—			—			3
Net periodic postretirement benefit cost	$	43		$	2		$	15		$	2		$	3		$	6

(*) Excludes Southern Power since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017.

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

Summary of Valuation Allowances

Valuation Allowances

	Georgia Power		Mississippi Power		Southern Company Gas		Southern Company
	(in millions)
Federal	$	6	$	—	$	11	$	19
State (net of federal benefit)	33		124		1		171
Balance at September 30, 2018	$	39	$	124	$	12	$	190

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Derivatives (Tables)

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Energy-Related Derivatives

At September 30, 2018, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, 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(*)	595	2022	2029
Alabama Power	82	2022	—
Georgia Power	165	2022	—
Gulf Power	9	2020	—
Mississippi Power	69	2022	—
Southern Power	15	2020	—
Southern Company Gas(*)	255	2021	2029

(*) Southern Company's and 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 4.3 billion mmBtu and short natural gas positions of 4 billion mmBtu as of September 30, 2018, which is also included in Southern Company's total volume.

Schedule of Interest Rate Derivatives

At September 30, 2018, 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 September 30, 2018
	(in millions)					(in millions)
Fair Value Hedges of Existing Debt
Southern Company(*)	$	300	2.75%	3-month LIBOR + 0.92%	June 2020	$	(6	)
Southern Company(*)	1,500		2.35%	1-month LIBOR + 0.87%	July 2021	(60		)
Georgia Power	500		1.95%	3-month LIBOR + 0.76%	December 2018	(3		)
Georgia Power	200		4.25%	3-month LIBOR + 2.46%	December 2019	(3		)
Southern Company Consolidated	$	2,500				$	(72	)

(*) Represents the Southern Company parent entity.

Schedule of Foreign Currency Derivatives

At September 30, 2018, the following foreign currency derivatives were outstanding:

	Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at September 30, 2018
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	48
Southern Power	564		3.78%	500		1.85%	June 2026	51
Total	$	1,241		€	1,100			$	99

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 September 30, 2018						As of December 31, 2017
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	$	15		$	17		$	10		$	43
Other deferred charges and assets/Other deferred credits and liabilities	5			26			7			24
Assets held for sale, current/Liabilities held for sale, current	—			6			—			—
Assets held for sale/Liabilities held for sale	—			2			—			—
Total derivatives designated as hedging instruments for regulatory purposes	$	20		$	51		$	17		$	67
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	3		$	6		$	3		$	14
Other deferred charges and assets/Other deferred credits and liabilities	1			1			—			—
Interest rate derivatives:
Other current assets/Other current liabilities	—			22			1			4
Other deferred charges and assets/Other deferred credits and liabilities	—			50			—			34
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	122			—			129			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	126		$	102		$	133		$	75
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	263		$	317		$	380		$	437
Other deferred charges and assets/Other deferred credits and liabilities	134			198			170			215
Total derivatives not designated as hedging instruments	$	397		$	515		$	550		$	652
Gross amounts recognized	$	543		$	668		$	700		$	794
Gross amounts offset(a)	$	(303	)	$	(491	)	$	(405	)	$	(598	)
Net amounts recognized in the Balance Sheets(b)	$	240		$	177		$	295		$	196

	As of September 30, 2018						As of December 31, 2017
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	$	5		$	4		$	2		$	6
Other deferred charges and assets/Other deferred credits and liabilities	2			6			2			4
Total derivatives designated as hedging instruments for regulatory purposes	$	7		$	10		$	4		$	10
Gross amounts recognized	$	7		$	10		$	4		$	10
Gross amounts offset	$	(4	)	$	(4	)	$	(4	)	$	(4	)
Net amounts recognized in the Balance Sheets	$	3		$	6		$	—		$	6
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	5		$	9		$	2		$	9
Other deferred charges and assets/Other deferred credits and liabilities	2			13			4			10
Total derivatives designated as hedging instruments for regulatory purposes	$	7		$	22		$	6		$	19
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	5		$	—		$	4
Other deferred charges and assets/Other deferred credits and liabilities	—			1			—			1
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	6		$	—		$	5
Gross amounts recognized	$	7		$	28		$	6		$	24
Gross amounts offset	$	(7	)	$	(7	)	$	(6	)	$	(6	)
Net amounts recognized in the Balance Sheets	$	—		$	21		$	—		$	18
Gulf Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	—		$	6		$	—		$	14
Other deferred charges and assets/Other deferred credits and liabilities	—			2			—			7
Total derivatives designated as hedging instruments for regulatory purposes	$	—		$	8		$	—		$	21
Gross amounts recognized	$	—		$	8		$	—		$	21
Net amounts recognized in the Balance Sheets	$	—		$	8		$	—		$	21

	As of September 30, 2018						As of December 31, 2017
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	$	2		$	3		$	1		$	6
Other deferred charges and assets/Other deferred credits and liabilities	1			6			1			3
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	9		$	2		$	9
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	—		$	1		$	—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	—		$	1		$	—
Gross amounts recognized	$	3		$	9		$	3		$	9
Gross amounts offset	$	(3	)	$	(3	)	$	(2	)	$	(2	)
Net amounts recognized in the Balance Sheets	$	—		$	6		$	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	$	2		$	6		$	3		$	11
Other deferred charges and assets/Other deferred credits and liabilities	1			1			—			—
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	122			—			129			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	125		$	30		$	132		$	34
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	—		$	—		$	—		$	2
Gross amounts recognized	$	125		$	30		$	132		$	36
Gross amounts offset	$	(2	)	$	(2	)	$	(3	)	$	(3	)
Net amounts recognized in the Balance Sheets	$	123		$	28		$	129		$	33

	As of September 30, 2018						As of December 31, 2017
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	$	3		$	1		$	5		$	8
Other deferred charges and assets/Other deferred credits and liabilities	—			1			—			—
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	2		$	5		$	8
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	$	1		$	—		$	—		$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	262		$	316		$	379		$	434
Other deferred charges and assets/Other deferred credits and liabilities	134			198			170			215
Total derivatives not designated as hedging instruments	$	396		$	514		$	549		$	649
Gross amounts of recognized	$	400		$	516		$	554		$	660
Gross amounts offset(a)	$	(287	)	$	(475	)	$	(390	)	$	(583	)
Net amounts recognized in the Balance Sheets(b)	$	113		$	41		$	164		$	77

(a) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $189 million and $193 million as of September 30, 2018 and December 31, 2017, respectively.

(b) Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $5 million and $11 million as of September 30, 2018 and December 31, 2017, respectively.

Pre-tax Effects of Unrealized Derivative Gains (Losses) Arising from Energy-Related Derivative Instruments

At September 30, 2018 and December 31, 2017, 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 September 30, 2018
Derivative Category and Balance Sheet Location	Southern Company(*)			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas(*)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(9	)	$	(2	)	$	(4	)	$	(6	)	$	(2	)	$	(1	)
Other regulatory assets, deferred	(20		)	(4		)	(11		)	(2		)	(5		)	—
Assets held for sale, current	(6		)	—			—			—			—			—
Assets held for sale	(2		)	—			—			—			—			—
Other regulatory liabilities, current	8			3			—			—			—			5
Total energy-related derivative gains (losses)	$	(29	)	$	(3	)	$	(15	)	$	(8	)	$	(7	)	$	4

(*) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $3 million at September 30, 2018.

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2017
Derivative Category and Balance Sheet Location	Southern Company(*)			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas(*)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(34	)	$	(4	)	$	(7	)	$	(14	)	$	(5	)	$	(4	)
Other regulatory assets, deferred	(18		)	(3		)	(6		)	(7		)	(2		)	—
Other regulatory liabilities, current	7			—			—			—			—			7
Other regulatory liabilities, deferred	1			1			—			—			—			—
Total energy-related derivative gains (losses)	$	(44	)	$	(6	)	$	(13	)	$	(21	)	$	(7	)	$	3

(*) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million at December 31, 2017.

Pre-tax Effects of Interest Rate Derivatives, Designated as Cash Flow Hedging Instruments

For the three and nine months ended September 30, 2018 and 2017, 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 September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Southern Company
Energy-related derivatives	$	(5	)	$	(6	)	$	7		$	(26	)
Interest rate derivatives	—			(1		)	(2		)	(2		)
Foreign currency derivatives	(10		)	46			(31		)	114
Total	$	(15	)	$	39		$	(26	)	$	86
Southern Power
Energy-related derivatives	$	(5	)	$	(6	)	$	5		$	(21	)
Foreign currency derivatives	(10		)	46			(31		)	114
Total	$	(15	)	$	40		$	(26	)	$	93
Southern Company Gas
Energy-related derivatives	$	—		$	—		$	2		$	(4	)

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location

For the three and nine months ended September 30, 2018 and 2017, 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 September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Southern Company
Cost of natural gas	$	104		$	134		$	1,053		$	1,085
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	—			—			(2		)	—
Depreciation and amortization	787			767			2,338			2,236
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	—			(6		)	2			(12		)
Interest expense, net of amounts capitalized	(458		)	(407		)	(1,386		)	(1,248		)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(5		)	(5		)	(16		)	(15		)
Foreign currency derivatives	(6		)	(5		)	(18		)	(17		)
Gain (loss) on fair value hedges(b)
Interest rate derivatives	(4		)	(5		)	(35		)	(6		)
Other income (expense), net	57			65			195			165
Gain (loss) on cash flow hedges(a)(c)
Foreign currency derivatives	(9		)	43			(46		)	139
Alabama Power
Interest expense, net of amounts capitalized	$	(82	)	$	(76	)	$	(240	)	$	(229	)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(1		)	(2		)	(4		)	(5		)
Georgia Power
Interest expense, net of amounts capitalized	$	(95	)	$	(105	)	$	(303	)	$	(310	)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(1		)	(1		)	(4		)	(3		)
Gain (loss) on fair value hedges(b)
Interest rate derivatives	—			—			(1		)	(1		)
Mississippi Power
Interest expense, net of amounts capitalized	$	(19	)	$	13		$	(59	)	$	(23	)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	—			—			(1		)	(1		)

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Southern Power
Depreciation and amortization	$	130		$	131		$	370		$	379
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	—			(6		)	2			(12		)
Interest expense, net of amounts capitalized	(45		)	(47		)	(138		)	(144		)
Gain (loss) on cash flow hedges(a)
Foreign currency derivatives	(6		)	(5		)	(18		)	(17		)
Other income (expense), net	17			3			22			3
Gain (loss) on cash flow hedges(a)(c)
Foreign currency derivatives	(9		)	43			(46		)	139
Southern Company Gas
Cost of natural gas	$	104		$	134		$	1,053		$	1,085
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	—			—			(2		)	—

(a) Amounts reflect gains or losses on cash flow hedges that were reclassified from accumulated OCI into income.

(b) For fair value hedges presented above, generally changes in the fair value of the derivative contracts are 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 September 30, 2018 and December 31, 2017, 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 September 30, 2018			As of December 31, 2017			As of September 30, 2018		As of December 31, 2017
	(in millions)						(in millions)
Southern Company
Securities due within one year	$	(499	)	$	(746	)	$	1	$	3
Long-term debt	(2,526		)	(2,553		)	65		35
Georgia Power
Securities due within one year	$	(499	)	$	(746	)	$	1	$	3
Long-term debt	(497		)	(498		)	2		1

Pre-tax Effect of Interest Rate and Energy Related Derivatives

For the three and nine months ended September 30, 2018 and 2017, 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 September 30,						Nine Months Ended September 30,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2018			2017			2018			2017
		(in millions)						(in millions)
Energy-related derivatives:	Natural gas revenues(*)	$	(36	)	$	(17	)	$	(79	)	$	48
	Cost of natural gas	2			2			5			(2		)
Total derivatives in non-designated hedging relationships		$	(34	)	$	(15	)	$	(74	)	$	46

(*) Excludes gains (losses) recorded in natural gas revenues associated with weather derivatives of $15 million for the nine months ended September 30, 2017 and immaterial amounts for all other periods presented.

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Acquisitions and Dispositions (Tables)

9 Months Ended

Sep. 30, 2018

Business Combinations [Abstract]

Schedule of Business Acquisitions

During the nine months ended September 30, 2018, one of Southern Power's wholly-owned subsidiaries acquired and completed construction of the Gaskell West 1 solar facility. Acquisition-related costs were expensed as incurred and were not material.

Project Facility	Resource	Seller; Acquisition Date	Approximate Nameplate Capacity (MW)	Location	Southern Power Percentage Ownership		Actual COD	PPA Contract Period
Gaskell West 1	Solar	Recurrent Energy Development Holdings, LLC January 26, 2018	20	Kern County, CA	100% of Class B	(*)	March 2018	20 years

(*) Southern Power owns 100% of the class B membership interests under a tax equity partnership agreement.

Schedule of Construction Projects

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Cactus Flats(a)	Wind	148	Concho County, TX	July 2018	12-15 years
Mankato	Natural Gas	385	Mankato, MN	First half 2019	20 years
Wild Horse 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 July 2017, Southern Power purchased 100% of the Cactus Flats facility and commenced construction. In July 2018, the facility was placed in service and, in August 2018, Southern Power closed on a tax equity partnership agreement and owns 100% of the class B membership interests.

(b) In May 2018, Southern Power purchased 100% of the Wild Horse Mountain facility and commenced construction. Southern Power may enter into a tax equity partnership agreement, in which case it would then own 100% of the class B membership interests.

(c) In August 2018, Southern Power purchased 100% of the membership interests from the joint development arrangement with Renewable Energy Systems Americas, Inc. and commenced construction. Southern Power may enter into a tax equity partnership agreement, in which case it would then own 100% of the class B membership interests.

Disposal Groups, Including Discontinued Operations

Gulf Power and the Florida Plants represent individually significant components of Southern Company and Southern Power, respectively; therefore, pre-tax profit for these components for the three and nine months ended September 30, 2018 and 2017 is presented below:

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2018		2017		2018		2017
	(in millions)				(in millions)
Earnings before income taxes:
Gulf Power	$	59	$	103	$	146	$	199
Southern Power's Florida Plants	$	18	$	11	$	40	$	28

The following table provides Southern Company's and Southern Power's major classes of assets and liabilities classified as held for sale at September 30, 2018:

	Southern Company		Southern Power
	(in millions)
Assets Held for Sale:
Current assets	$	407	$	18
Total property, plant, and equipment	4,093		168
Other non-current assets	574		17
Total Assets Held for Sale	$	5,074	$	203
Liabilities Held for Sale:
Current liabilities	$	355	$	4
Long-term debt	1,285		—
Accumulated deferred income taxes	542		—
Other non-current liabilities	1,008		—
Total Liabilities Held for Sale	$	3,190	$	4

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Variable Interest Entity and Equity Method Investments (Tables)

9 Months Ended

Sep. 30, 2018

Regulated Operations [Abstract]

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments as of September 30, 2018 and December 31, 2017 and related income from those investments for the three and nine-month periods ended September 30, 2018 and September 30, 2017 were as follows:

Investment Balance	September 30, 2018		December 31, 2017
	(in millions)
SNG	$	1,260	$	1,262
Atlantic Coast Pipeline	73		41
PennEast Pipeline	70		57
Other	126		117
Total	$	1,529	$	1,477

Selected financial information of SNG for the three and nine months ended September 30, 2018 and September 30, 2017 is as follows:

Income Statement Information	Three Months Ended September 30, 2018		Three Months Ended September 30, 2017		Nine Months Ended September 30, 2018		Nine Months Ended September 30, 2017
	(in millions)
Revenues	$	145	$	146	$	451	$	445
Operating income	$	71	$	71	$	230	$	218
Net income	$	58	$	57	$	190	$	172

Schedule of Other Nonoperating Income, by Component

Earnings from Equity Method Investments	Three Months Ended September 30, 2018		Three Months Ended September 30, 2017		Nine Months Ended September 30, 2018		Nine Months Ended September 30, 2017
	(in millions)
SNG	$	29	$	28	$	95	$	86
PennEast Pipeline	2		1		4		5
Atlantic Coast Pipeline	1		1		4		4
Other	2		2		5		5
Total	$	34	$	32	$	108	$	100

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Segment and Related Information (Tables)

9 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

Financial Data for Business Segments

Financial data for business segments and products and services for the three and nine months ended September 30, 2018 and 2017 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 September 30, 2018:
Operating revenues	$	5,014	$	635	$	(140	)	$	5,509	$	492	$	202		$	(44	)	$	6,159
Segment net income (loss)(a)(b)(c)(d)	1,148		92		—			1,240		46		(119		)	(3		)	1,164
Nine Months Ended September 30, 2018:
Operating revenues	$	13,117	$	1,699	$	(360	)	$	14,456	$	2,861	$	984		$	(143	)	$	18,158
Segment net income (loss)(a)(b)(c)(d)	1,711		235		—			1,946		294		(292		)	—			1,948
At September 30, 2018:
Goodwill	$	—	$	2	$	—		$	2	$	5,015	$	298		$	—		$	5,315
Total assets	75,069		15,355		(322		)	90,102		20,398		3,086			(1,869		)	111,717
Three Months Ended September 30, 2017:
Operating revenues	$	5,017	$	618	$	(112	)	$	5,523	$	565	$	153		$	(40	)	$	6,201
Segment net income (loss)(a)(b)	1,008		124		—			1,132		15		(80		)	2			1,069
Nine Months Ended September 30, 2017:
Operating revenues	$	12,960	$	1,597	$	(318	)	$	14,239	$	2,841	$	442		$	(119	)	$	17,403
Segment net income (loss)(a)(b)(e)	—		276		—			276		303		(232		)	—			347
At December 31, 2017:
Goodwill	$	—	$	2	$	—		$	2	$	5,967	$	299		$	—		$	6,268
Total assets	72,204		15,206		(325		)	87,085		22,987		2,552			(1,619		)	111,005

(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 $1 million ($1 million after tax) and $34 million ($21 million after tax) for the three months ended September 30, 2018 and 2017, respectively, and $1.1 billion ($0.8 billion after tax) and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2018 and 2017, respectively. See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) under "Nuclear Construction" and "Kemper County Energy Facility" for additional information.

(c) Segment net income (loss) for Southern Power includes pre-tax impairment charges of $36 million ($27 million after tax) and $155 million ($116 million after tax) for the three and nine months ended September 30, 2018, respectively. See Note (J) under "Southern Power – Development Projects" and " – Sale of Florida Plants" for additional information.

(d) Segment net income (loss) for Southern Company Gas includes a net gain on dispositions of $353 million ($40 million gain after tax) and $317 million ($35 million loss after tax) for the three and nine months ended September 30, 2018, respectively, related to the Southern Company Gas Dispositions and a goodwill impairment charge of $42 million for the nine months ended September 30, 2018 related to the sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.

(e) Segment net income (loss) for the traditional electric operating companies includes a pre-tax charge for the write-down of Gulf Power's ownership of Plant Scherer Unit 3 of $33 million ($20 million after tax) for the nine months ended September 30, 2017. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.

Business segment financial data for the three and nine months ended September 30, 2018 and 2017 was as follows:

	Gas Distribution Operations(a)(c)		Gas Marketing Services(b)(c)			Wholesale Gas Services(d)			Gas Midstream Operations		Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended September 30, 2018:
Operating revenues	$	441	$	44		$	(8	)	$	20	$	497	$	1		$	(6	)	$	492
Segment net income (loss)	74		(8		)	(18		)	16		64		(18		)	—			46
Nine Months Ended September 30, 2018:
Operating revenues	2,297		403			142			60		2,902		3			(44		)	2,861
Segment net income (loss)	290		(71		)	65			54		338		(44		)	—			294
Total assets at September 30, 2018:	16,850		1,522			855			2,297		21,524		10,146			(11,272		)	20,398
Three Months Ended September 30, 2017:
Operating revenues	$	472	$	143		$	(24	)	$	16	$	607	$	2		$	(44	)	$	565
Segment net income (loss)	52		1			(23		)	14		44		(29		)	—			15
Nine Months Ended September 30, 2017:
Operating revenues	2,255		597			95			53		3,000		7			(166		)	2,841
Segment net income (loss)	223		36			28			38		325		(22		)	—			303
Total assets at December 31, 2017:	19,358		2,147			1,096			2,241		24,842		12,184			(14,039		)	22,987

(a) Operating revenues for the three gas distribution operations dispositions were $8 million and $50 million for the three months ended September 30, 2018 and 2017, respectively, and $245 million and $274 million for the nine months ended September 30, 2018 and 2017, respectively. See Note (J) under "Southern Company Gas" for additional information.

(b) Operating revenues for the gas marketing services disposition were $32 million for the three months ended September 30, 2017 and $55 million and $95 million for the nine months ended September 30, 2018 and 2017, respectively. See Note (J) under "Southern Company Gas" for additional information.

(c) Segment net income for gas distribution operations includes a gain on dispositions of $351 million ($38 million after tax) for the three and nine months ended September 30, 2018. Segment net income for gas marketing services includes a gain on disposition of $2 million ($2 million after tax) for the three months ended September 30, 2018 and a loss on disposition of $34 million ($73 million loss after tax) and a goodwill impairment charge of $42 million for the nine months ended September 30, 2018 recorded in contemplation of the sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.

(d) 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 September 30, 2018	$	1,573	$	82	$	1,655	$	1,663	$	(8	)
Three Months Ended September 30, 2017	1,411		103		1,514		1,538		(24		)
Nine Months Ended September 30, 2018	$	4,847	$	352	$	5,199	$	5,057	$	142
Nine Months Ended September 30, 2017	4,781		362		5,143		5,048		95

Financial Data for Products and Services

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2018	$	4,605	$	693	$	211	$	5,509
Three Months Ended September 30, 2017	4,615		718		190		5,523
Nine Months Ended September 30, 2018	$	11,913	$	1,923	$	620	$	14,456
Nine Months Ended September 30, 2017	11,786		1,867		586		14,239

	Southern Company Gas' Revenues
Period	Gas Distribution Operations		Gas Marketing Services		Other			Total
	(in millions)
Three Months Ended September 30, 2018	$	438	$	44	$	10		$	492
Three Months Ended September 30, 2017	430		143		(8		)	565
Nine Months Ended September 30, 2018	$	2,276	$	403	$	182		$	2,861
Nine Months Ended September 30, 2017	2,119		597		125			2,841

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Introduction - Narrative (Details) - USD ($)	1 Months Ended	3 Months Ended		9 Months Ended
	Jun. 30, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Related Party Transaction [Line Items]
Net income (loss)		$ 1,222,000,000	$ 1,109,000,000	$ 2,031,000,000	$ 427,000,000
ALABAMA POWER CO
Related Party Transaction [Line Items]
Net income (loss)		377,000,000	330,000,000	$ 868,000,000	743,000,000
Increase in ARO due to new CCR rule	$ 1,200,000,000
Inflation rate assumption				4.50%
Trust earnings rate assumption				7.00%
MISSISSIPPI POWER CO
Related Party Transaction [Line Items]
Net income (loss)		47,000,000	40,000,000	$ 87,000,000	(2,033,000,000)
Increase in ARO due to new CCR rule	11,000,000
SOUTHERN Co GAS
Related Party Transaction [Line Items]
Net income (loss)		46,000,000	15,000,000	294,000,000	303,000,000
Inventory decrement		0		0
Wholesale Gas Services | SOUTHERN Co GAS
Related Party Transaction [Line Items]
Inventory write-down		0	$ 0	0	$ 0
Plant Farley | ALABAMA POWER CO
Related Party Transaction [Line Items]
Increase in ARO	$ 300,000,000
Accounting Standards Update 2014-09 | Effect of Change
Related Party Transaction [Line Items]
Net income (loss)		(4,000,000)		1,000,000
Accounting Standards Update 2014-09 | Effect of Change | SOUTHERN Co GAS
Related Party Transaction [Line Items]
Net income (loss)		$ (4,000,000)		$ 1,000,000

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Introduction - ASC 606 (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Condensed Statements of Income
Total operating revenues	$ 6,159	$ 6,201	$ 18,158	$ 17,403
Other operations and maintenance	1,404	1,341	4,217	4,100
Operating income (loss)	2,174	1,991	3,613	1,594
Other income (expense), net	57	65	195	165
Earnings (loss) before income taxes	1,845	1,699	2,629	744
Income taxes (benefit)	623	590	598	317
Consolidated net income (loss)	1,222	1,109	2,031	427
Consolidated net income (loss) attributable to Southern Company	1,164	1,069	1,948	347
Condensed Statements of Cash Flows
Net income (loss)	1,222	1,109	2,031	427
Changes in certain current assets and liabilities:
Receivables			37	423
Other current assets			(90)	(66)
Other current liabilities			(67)	(129)
Condensed Balance Sheets
Unbilled revenues	738		738		$ 810
Other accounts and notes receivable	690		690		698
Other current assets	232		232		199
Other current liabilities	763		763		874
Retained earnings (accumulated deficit)	9,048		9,048		8,885
Balances Without Adoption of ASC 606
Condensed Statements of Income
Other operations and maintenance	1,387		4,178
Operating income (loss)	2,195		3,647
Other income (expense), net	41		160
Earnings (loss) before income taxes	1,850		2,628
Income taxes (benefit)	624		598
Consolidated net income (loss)	1,226		2,030
Consolidated net income (loss) attributable to Southern Company	1,168		1,947
Condensed Statements of Cash Flows
Net income (loss)	1,226		2,030
Changes in certain current assets and liabilities:
Receivables			27
Other current assets			(80)
Other current liabilities			(68)
Condensed Balance Sheets
Unbilled revenues	776		776
Other accounts and notes receivable	691		691
Other current assets	193		193
Other current liabilities	764		764
Retained earnings (accumulated deficit)	9,047		9,047
ALABAMA POWER CO
Condensed Statements of Income
Total operating revenues	1,740	1,740	4,716	4,606
Other operations and maintenance	401	406	1,191	1,177
Operating income (loss)	561	601	1,313	1,403
Other income (expense), net	9	10	24	35
Earnings (loss) before income taxes	504	546	1,140	1,236
Income taxes (benefit)	127	216	272	493
Consolidated net income (loss)	377	330	868	743
Consolidated net income (loss) attributable to Southern Company	373	325	857	729
Condensed Statements of Cash Flows
Net income (loss)	377	330	868	743
Changes in certain current assets and liabilities:
Receivables			(207)	(163)
Other current assets			66	33
Other current liabilities			60	7
Condensed Balance Sheets
Unbilled revenues	159		159		162
Other accounts and notes receivable	54		54		55
Other current assets	8		8		5
Other current liabilities	46		46		52
Retained earnings (accumulated deficit)	2,902		2,902		2,647
ALABAMA POWER CO | Balances Without Adoption of ASC 606
Condensed Statements of Income
Other operations and maintenance	390		1,159
Operating income (loss)	563		1,319
Other income (expense), net	7		18
GEORGIA POWER CO
Condensed Statements of Income
Total operating revenues	2,593	2,546	6,601	6,426
Other operations and maintenance	460	430	1,325	1,248
Operating income (loss)	991	1,017	1,032	2,121
Other income (expense), net	30	22	104	95
Earnings (loss) before income taxes	926	934	833	1,906
Income taxes (benefit)	262	350	212	705
Consolidated net income (loss)	664	584	621	1,201
Consolidated net income (loss) attributable to Southern Company	664	580	621	1,188
Condensed Statements of Cash Flows
Net income (loss)	664	584	621	1,201
Changes in certain current assets and liabilities:
Receivables			(205)	(254)
Other current assets			(36)	(24)
Other current liabilities			(111)	(11)
Condensed Balance Sheets
Unbilled revenues	245		245		255
Other accounts and notes receivable	96		96		76
Other current assets	91		91		14
Other current liabilities	180		180		198
Retained earnings (accumulated deficit)	3,792		3,792		4,215
GEORGIA POWER CO | Balances Without Adoption of ASC 606
Condensed Statements of Income
Other operations and maintenance	437		1,268
Operating income (loss)	990		1,027
Other income (expense), net	31		109
Changes in certain current assets and liabilities:
Receivables			(242)
Other current assets			1
Condensed Balance Sheets
Unbilled revenues	310		310
Other accounts and notes receivable	97		97
Other current assets	25		25
SOUTHERN Co GAS
Condensed Statements of Income
Total operating revenues	492	565	2,861	2,841
Other operations and maintenance	216	206	730	675
Operating income (loss)	374	67	810	551
Other income (expense), net	6	19	21	30
Earnings (loss) before income taxes	362	67	769	536
Income taxes (benefit)	316	52	475	233
Consolidated net income (loss)	46	15	294	303
Consolidated net income (loss) attributable to Southern Company	46	15	294	303
Condensed Statements of Cash Flows
Net income (loss)	46	15	294	303
Changes in certain current assets and liabilities:
Receivables			445	531
Other current assets			21	(42)
Other current liabilities			35	8
Condensed Balance Sheets
Unbilled revenues	58		58		285
Other accounts and notes receivable	110		110		91
Other current assets	88		88		78
Other current liabilities	122		122		159
Retained earnings (accumulated deficit)	(273)		(273)		$ (212)
SOUTHERN Co GAS | Balances Without Adoption of ASC 606
Condensed Statements of Income
Operating income (loss)	379		809
Earnings (loss) before income taxes	367		768
Income taxes (benefit)	317		475
Consolidated net income (loss)	50		293
Condensed Statements of Cash Flows
Net income (loss)	50		293
Changes in certain current assets and liabilities:
Other current liabilities			34
Condensed Balance Sheets
Other current liabilities	123		123
Retained earnings (accumulated deficit)	(274)		(274)
SOUTHERN Co GAS
Condensed Statements of Income
Total operating revenues	492	565	2,861	2,841
Accounting Standards Update 2014-09 | Effect of Change
Condensed Statements of Income
Other operations and maintenance	17		39
Operating income (loss)	(21)		(34)
Other income (expense), net	16		35
Earnings (loss) before income taxes	(5)		1
Income taxes (benefit)	(1)		0
Consolidated net income (loss)	(4)		1
Consolidated net income (loss) attributable to Southern Company	(4)		1
Condensed Statements of Cash Flows
Net income (loss)	(4)		1
Changes in certain current assets and liabilities:
Receivables			10
Other current assets			(10)
Other current liabilities			1
Condensed Balance Sheets
Unbilled revenues	(38)		(38)
Other accounts and notes receivable	(1)		(1)
Other current assets	39		39
Other current liabilities	(1)		(1)
Retained earnings (accumulated deficit)	1		1
Accounting Standards Update 2014-09 | ALABAMA POWER CO | Effect of Change
Condensed Statements of Income
Other operations and maintenance	11		32
Operating income (loss)	(2)		(6)
Other income (expense), net	2		6
Accounting Standards Update 2014-09 | GEORGIA POWER CO | Effect of Change
Condensed Statements of Income
Other operations and maintenance	23		57
Operating income (loss)	1		5
Other income (expense), net	(1)		(5)
Changes in certain current assets and liabilities:
Receivables			37
Other current assets			(37)
Condensed Balance Sheets
Unbilled revenues	(65)		(65)
Other accounts and notes receivable	(1)		(1)
Other current assets	66		66
Accounting Standards Update 2014-09 | SOUTHERN Co GAS | Effect of Change
Condensed Statements of Income
Operating income (loss)	(5)		1
Earnings (loss) before income taxes	(5)		1
Income taxes (benefit)	(1)		0
Consolidated net income (loss)	(4)		1
Condensed Statements of Cash Flows
Net income (loss)	(4)		1
Changes in certain current assets and liabilities:
Other current liabilities			1
Condensed Balance Sheets
Other current liabilities	(1)		(1)
Retained earnings (accumulated deficit)	1		1
Natural gas
Condensed Statements of Income
Total operating revenues	492	532	2,806	2,746
Natural gas | Balances Without Adoption of ASC 606
Condensed Statements of Income
Total operating revenues	497		2,805
Natural gas | SOUTHERN Co GAS
Condensed Statements of Income
Total operating revenues	487	532	2,829	2,737
Natural gas | SOUTHERN Co GAS | Balances Without Adoption of ASC 606
Condensed Statements of Income
Total operating revenues	492		2,828
Natural gas | Accounting Standards Update 2014-09 | Effect of Change
Condensed Statements of Income
Total operating revenues	(5)		1
Natural gas | Accounting Standards Update 2014-09 | SOUTHERN Co GAS | Effect of Change
Condensed Statements of Income
Total operating revenues	(5)		1
Other revenues
Condensed Statements of Income
Total operating revenues	199	168	1,007	494
Other revenues | Balances Without Adoption of ASC 606
Condensed Statements of Income
Total operating revenues	198		1,003
Other revenues | ALABAMA POWER CO
Condensed Statements of Income
Total operating revenues	68	50	199	158
Other revenues | ALABAMA POWER CO | Balances Without Adoption of ASC 606
Condensed Statements of Income
Total operating revenues	59		173
Other revenues | GEORGIA POWER CO
Condensed Statements of Income
Total operating revenues	121	93	349	284
Other revenues | GEORGIA POWER CO | Balances Without Adoption of ASC 606
Condensed Statements of Income
Total operating revenues	97		287
Other revenues | SOUTHERN Co GAS
Condensed Statements of Income
Total operating revenues	0	$ 33	55	$ 95
Other revenues | Accounting Standards Update 2014-09 | Effect of Change
Condensed Statements of Income
Total operating revenues	1		4
Other revenues | Accounting Standards Update 2014-09 | ALABAMA POWER CO | Effect of Change
Condensed Statements of Income
Total operating revenues	9		26
Other revenues | Accounting Standards Update 2014-09 | GEORGIA POWER CO | Effect of Change
Condensed Statements of Income
Total operating revenues	$ 24		$ 62

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Introduction - Asset Retirement Obligation (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($)
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at December 31, 2017	$ 4,824
Liabilities incurred	2
Liabilities settled	(160)
Accretion	153
Cash flow revisions	1,510
Reclassification to held for sale	(164)
Balance at September 30, 2018	6,165
ALABAMA POWER CO
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at December 31, 2017	1,709
Liabilities incurred	0
Liabilities settled	(31)
Accretion	72
Cash flow revisions	1,451
Reclassification to held for sale	0
Balance at September 30, 2018	3,201
GEORGIA POWER CO
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at December 31, 2017	2,638
Liabilities incurred	0
Liabilities settled	(82)
Accretion	70
Cash flow revisions	(32)
Reclassification to held for sale	0
Balance at September 30, 2018	2,594
GULF POWER CO
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at December 31, 2017	142
Liabilities incurred	0
Liabilities settled	(23)
Accretion	3
Cash flow revisions	42
Reclassification to held for sale	0
Balance at September 30, 2018	164
MISSISSIPPI POWER CO
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at December 31, 2017	174
Liabilities incurred	0
Liabilities settled	(22)
Accretion	4
Cash flow revisions	21
Reclassification to held for sale	0
Balance at September 30, 2018	$ 177

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Introduction - Nuclear Decommissioning (Details) - ALABAMA POWER CO - Plant Farley $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($)
Decommissioning periods:
Beginning year	2037
Completion year	2076
Site study costs	$ 1,720
Radiated structures
Decommissioning periods:
Site study costs	1,621
Non-radiated structures
Decommissioning periods:
Site study costs	$ 99

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Introduction - Goodwill (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2018	Mar. 31, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Goodwill [Roll Forward]
Balance at December 31, 2017		$ 6,268		$ 6,268
Impairment				(42)
Dispositions				(910)
Balance at September 30, 2018	$ 5,315			5,315
SOUTHERN Co GAS
Goodwill [Roll Forward]
Balance at December 31, 2017		5,967		5,967
Impairment	0	(42)	$ 0	(42)	$ 0
Dispositions				(910)
Balance at September 30, 2018	5,015			5,015
SOUTHERN Co GAS | Gas Distribution Operations
Goodwill [Roll Forward]
Balance at December 31, 2017		4,702		4,702
Impairment				0
Dispositions				(668)
Balance at September 30, 2018	4,034			4,034
SOUTHERN Co GAS | Gas Marketing Services
Goodwill [Roll Forward]
Balance at December 31, 2017		$ 1,265		1,265
Impairment				(42)
Dispositions				(242)
Balance at September 30, 2018	$ 981			$ 981

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Introduction - Other Intangible Assets Subject to Amortization (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Finite-Lived Intangible Assets [Line Items]
Accumulated Amortization	$ (225)	$ (186)
Total other intangible assets - net	674	873
SOUTHERN POWER CO
Finite-Lived Intangible Assets [Line Items]
Accumulated Amortization	(66)	(47)
SOUTHERN POWER CO | PPA fair value adjustments
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	456	456
Accumulated Amortization	(66)	(47)
Other Intangible Assets, Net	390	409
SOUTHERN Co GAS
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	246	400
Accumulated Amortization	(133)	(120)
Other Intangible Assets, Net	113	280
Total other intangible assets - net	113	280
SOUTHERN Co GAS | Customer relationships
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	156	221
Accumulated Amortization	(78)	(77)
Other Intangible Assets, Net	78	144
SOUTHERN Co GAS | Trade names
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	26	115
Accumulated Amortization	(6)	(9)
Other Intangible Assets, Net	20	106
SOUTHERN Co GAS | Storage and transportation contracts
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	64	64
Accumulated Amortization	(49)	(34)
Other Intangible Assets, Net	15	30
Southern Company
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	824	984
Accumulated Amortization	(225)	(186)
Other Intangible Assets, Net	599	798
Total other intangible assets - gross	899	1,059
Total other intangible assets - net	674	873
Southern Company | Customer relationships
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	223	288
Accumulated Amortization	(87)	(83)
Other Intangible Assets, Net	136	205
Southern Company | Trade names
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	70	159
Accumulated Amortization	(18)	(17)
Other Intangible Assets, Net	52	142
Southern Company | Storage and transportation contracts
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	64	64
Accumulated Amortization	(49)	(34)
Other Intangible Assets, Net	15	30
Southern Company | PPA fair value adjustments
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	456	456
Accumulated Amortization	(66)	(47)
Other Intangible Assets, Net	390	409
Southern Company | Other
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	11	17
Accumulated Amortization	(5)	(5)
Other Intangible Assets, Net	$ 6	$ 12

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Introduction - Other Intangible Assets Not Subject to Amortization (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Indefinite-lived Intangible Assets [Line Items]
Accumulated Amortization	$ (225)	$ (186)
Total other intangible assets - net	674	873
Southern Company
Indefinite-lived Intangible Assets [Line Items]
Total other intangible assets - gross	899	1,059
Accumulated Amortization	(225)	(186)
Total other intangible assets - net	674	873
Federal Communications Commission licenses | Southern Company
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	75	75
SOUTHERN POWER CO
Indefinite-lived Intangible Assets [Line Items]
Accumulated Amortization	(66)	(47)
SOUTHERN Co GAS
Indefinite-lived Intangible Assets [Line Items]
Accumulated Amortization	(133)	(120)
Total other intangible assets - net	$ 113	$ 280

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Introduction - Intangibles, Amortization (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 21	$ 70
SOUTHERN POWER CO
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	6	19
SOUTHERN Co GAS
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 12	$ 42

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Introduction - Restricted Cash (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	$ 1,847	$ 2,130
Restricted cash:
Total cash, cash equivalents, and restricted cash	1,891	2,147	$ 1,858	$ 1,992
SOUTHERN POWER CO
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	192	129
Restricted cash:
Other accounts and notes receivable		0
Deferred charges and other assets		11
Total cash, cash equivalents, and restricted cash	192	140	189	1,112
SOUTHERN Co GAS
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	56	73
Cash and cash equivalents classified as assets held for sale	0
Restricted cash:
Other accounts and notes receivable	6	5
Deferred charges and other assets		0
Total cash, cash equivalents, and restricted cash	62	78	$ 26	$ 24
Southern Company
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	1,847	2,130
Cash and cash equivalents classified as assets held for sale	37
Restricted cash:
Other accounts and notes receivable	6	5
Deferred charges and other assets		12
Total cash, cash equivalents, and restricted cash	$ 1,891	$ 2,147

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Contingencies and Regulatory Matters - General Litigation Matters (Details) $ in Thousands						9 Months Ended
	May 18, 2018 USD ($)	May 04, 2018	Apr. 25, 2018	Mar. 02, 2018 USD ($) generating_plant	Feb. 07, 2018	Sep. 30, 2018 USD ($)	Dec. 31, 2017 USD ($)
ALABAMA POWER CO
Loss Contingencies [Line Items]
Public utilities, approved return on equity percentage						47.00%
MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Public utilities, requested return on equity, percentage					9.33%
MISSISSIPPI POWER CO | MRA Fuel Costs
Loss Contingencies [Line Items]
Over recovered fuel cost						$ 7,000	$ 0
MISSISSIPPI POWER CO | MB Fuel Costs
Loss Contingencies [Line Items]
Over recovered fuel cost						0	0
SOUTHERN Co GAS
Loss Contingencies [Line Items]
Environmental remediation liability						294,000	388,000
GEORGIA POWER CO
Loss Contingencies [Line Items]
Environmental remediation liability						25,000	22,000
GULF POWER CO
Loss Contingencies [Line Items]
Environmental remediation liability						48,000	52,000
Location One | SOUTHERN Co GAS
Loss Contingencies [Line Items]
Environmental remediation liability						$ 2,000
Location One | SOUTHERN Co GAS | Elizabethtown Gas
Loss Contingencies [Line Items]
Environmental remediation liability							$ 85,000
Alabama Department of Environmental Management (ADEM) | ALABAMA POWER CO
Loss Contingencies [Line Items]
Litigation settlement, amount awarded to other party				$ 1,250
Number of electric generating plants | generating_plant				5
Open Access Transmission Tariff
Loss Contingencies [Line Items]
Public utilities, approved return on equity percentage						11.25%
RE Roserock, LLC | RE Roserock, LLC | SOUTHERN POWER CO
Loss Contingencies [Line Items]
Ownership percentage by parent						51.00%
Maximum | Open Access Transmission Tariff
Loss Contingencies [Line Items]
Public utilities, requested return on equity, percentage						8.65%
Martin Product Sales, LLC Litigation | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Damages sought by litigation	$ 143,000
Deepwater Horizon Oil Spill Litigation Case | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Litigation settlement awarded from other party						$ 18,000
Nicor Energy Services Company Litigation | SOUTHERN Co GAS
Loss Contingencies [Line Items]
Litigation amount awarded to other party						$ 11,000
Pending Litigation | Shareholder Derivative Lawsuits
Loss Contingencies [Line Items]
Stay period		30 days	30 days

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Contingencies and Regulatory Matters - Cost Recovery Clauses (Details) - ALABAMA POWER CO - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Under recovered regulatory clause revenues
Loss Contingencies [Line Items]
Rate CNP Compliance	$ 0	$ 17
Rate CNP PPA	30	12
Retail Energy Cost Recovery	58	25
Under recovered regulatory clause revenues
Loss Contingencies [Line Items]
Rate CNP Compliance	7	0
Retail Energy Cost Recovery	41	0
Other regulatory liabilities, deferred
Loss Contingencies [Line Items]
Natural Disaster Reserve	$ 24	$ 38

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Contingencies and Regulatory Matters - Alabama Power (Details)				1 Months Ended		3 Months Ended	9 Months Ended	12 Months Ended
	Aug. 06, 2018	May 01, 2018 USD ($) $ / KWH_Kilowatt_hour	Apr. 30, 2018 $ / KWH_Kilowatt_hour	Jan. 31, 2019 $ / KWH_Kilowatt_hour	Jun. 30, 2018	Dec. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Dec. 31, 2025	Dec. 31, 2018 USD ($)	Dec. 31, 2017
ALABAMA POWER CO
Loss Contingencies [Line Items]
Public utilities, approved return on equity percentage							47.00%
Public utilities, allowed weighted common equity return, percentage					6.15%					6.21%
Customer refundable fees, refund payments, tranche one, percentage							25.00%
Customer refundable fees, refund payments, tranche two, percentage							40.00%
Customer refundable fees, refund payments, tranche three, percentage							75.00%
Customer refund							$ 50,000,000
Customer refundable fees, refund payments							151,000,000
Current billing rates under rate ecr in terms of per units | $ / KWH_Kilowatt_hour		2.353	2.015
Approved increase (decrease) in fuel rates amount		$ 100,000,000
Tax Cuts and Jobs Act of 2017, change in tax rate, deferred tax liability, income tax benefit, maximum amount used to offset under recovered amounts		$ 30,000,000
Tax Cuts and Jobs Act of 2017, change in tax rate, deferred tax liability, income tax benefit							$ 30,000,000
ALABAMA POWER CO | Minimum
Loss Contingencies [Line Items]
Public utilities, actual weighted common equity return, threshold, percentage							6.15%
Public utilities, actual weighted common equity return, threshold for customer refundable fees, refund payments, percentage, tranche one							6.15%
Public utilities, actual weighted common equity return, threshold for customer refundable fees, refund payments, percentage, tranche two							6.65%
Public utilities, actual weighted common equity return, threshold for customer refundable fees, refund payments, percentage, tranche three							7.15%
ALABAMA POWER CO | Maximum
Loss Contingencies [Line Items]
Public utilities, actual weighted common equity return, threshold, percentage							7.65%
Public utilities, actual weighted common equity return, threshold for customer refundable fees, refund payments, percentage, tranche one							6.65%
Public utilities, actual weighted common equity return, threshold for customer refundable fees, refund payments, percentage, tranche two							7.15%
Public utilities, actual weighted common equity return, threshold for customer refundable fees, refund payments, percentage, tranche three							7.65%
Customer refundable fees, refund payments, percentage							7.65%
ALABAMA POWER CO | Scenario, Forecast
Loss Contingencies [Line Items]
Public utilities, approved return on equity percentage								55.00%
Customer refundable fees, refund payments						$ 257,000,000
Current billing rates under rate ecr in terms of per units | $ / KWH_Kilowatt_hour				5.910
Tax Cuts and Jobs Act of 2017, change in tax rate, deferred tax liability, income tax benefit									$ 50,000,000
Reserve Margin Plan | Plant Greene County Units 1 and 2 | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Accelerated retirement period	4 years

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Contingencies and Regulatory Matters - Georgia Power (Details) $ in Millions		1 Months Ended			9 Months Ended		12 Months Ended
	Apr. 03, 2018 USD ($)	Feb. 29, 2020 USD ($)	Jun. 30, 2019 USD ($)	Oct. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2019	Dec. 31, 2017 USD ($)
Loss Contingencies [Line Items]
Effective tax rate					22.70%	42.60%
Deferred income tax benefit					$ 286	$ (15)
GEORGIA POWER CO
Loss Contingencies [Line Items]
Customer refund					$ 330
Effective tax rate					25.50%	37.00%
Deferred income tax benefit	$ 700				$ 185	$ (328)
Customer refund liability in absence of base rate case	$ 185
Retail regulatory equity ratio					0.53
Under recovered fuel balance, threshold for interim fuel rider					$ 200
Annual accrual for incremental operating and maintenance costs of damage from major storms					30
GEORGIA POWER CO | Storm Damage
Loss Contingencies [Line Items]
Regulatory asset					311
GEORGIA POWER CO | Subsequent Event
Loss Contingencies [Line Items]
Customer refundable fees, refund payments				$ 130
GEORGIA POWER CO | Other current liabilities
Loss Contingencies [Line Items]
Under recovered fuel balance					105			$ 165
GEORGIA POWER CO | Maximum
Loss Contingencies [Line Items]
Retail regulatory equity ratio	0.55
GEORGIA POWER CO | Maximum | Subsequent Event | Loss from Catastrophes
Loss Contingencies [Line Items]
Estimated restoration costs				150
GEORGIA POWER CO | Minimum | Subsequent Event | Loss from Catastrophes
Loss Contingencies [Line Items]
Estimated restoration costs				$ 125
GEORGIA POWER CO | State (net of federal benefit)
Loss Contingencies [Line Items]
Effective tax rate	6.00%
GEORGIA POWER CO | Scenario, Forecast
Loss Contingencies [Line Items]
Customer refundable fees, refund payments		$ 105	$ 95
GEORGIA POWER CO | Scenario, Forecast | State (net of federal benefit)
Loss Contingencies [Line Items]
Effective tax rate							5.75%
Impact of Tax Reform Legislation | GEORGIA POWER CO
Loss Contingencies [Line Items]
Regulatory liabilities					$ 655

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Contingencies and Regulatory Matters - Gulf Power (Details) - GULF POWER CO $ in Millions						9 Months Ended	12 Months Ended
	Nov. 05, 2018 USD ($)	Oct. 30, 2018 USD ($)	Oct. 10, 2018 USD ($)	Mar. 26, 2018 USD ($) intervenor	Mar. 25, 2018	Sep. 30, 2018 USD ($)	Dec. 31, 2017 USD ($)
Loss Contingencies [Line Items]
Property damage reserve						$ 48.0
Property damage reserve replenishment						40.0
Number of intervenors | intervenor				3
Tax reform settlement agreement, annual reduction of revenue from base rates				$ 18.2
Tax reform settlement agreement, annual reduction of revenue from environmental cost recovery rates				15.6
Tax reform settlement agreement, refund				$ 69.4
Customer refundable fees, refund payments						53.0
Retail regulatory equity ratio				0.535	0.525
Environmental Cost Recovery						21.0	$ 11.0
Projected environmental expenditures						8.0	13.0
Property Basis Differences
Loss Contingencies [Line Items]
Deferred tax asset, regulatory liability						7.0
Subsequent Event
Loss Contingencies [Line Items]
Recovery from customers, period following the filing of cost recovery petition			60 days
Tax reform settlement agreement, annual reduction of revenue from base rates		$ 9.6
Decrease in annual revenues	$ 38.0
Under recovered regulatory clause revenues
Loss Contingencies [Line Items]
Fuel Cost Recovery						0.0	22.0
Purchased Power Capacity Recovery						0.0	2.0
Environmental Cost Recovery						0.0	2.0
Other regulatory liabilities, current
Loss Contingencies [Line Items]
Fuel Cost Recovery						23.0	0.0
Purchased Power Capacity Recovery						4.0	0.0
Environmental Cost Recovery						13.0	0.0
Energy Conservation Cost Recovery						$ 2.0	$ 0.0
Loss from Catastrophes | Subsequent Event | Minimum
Loss Contingencies [Line Items]
Estimated restoration costs			$ 350.0
Loss from Catastrophes | Subsequent Event | Maximum
Loss Contingencies [Line Items]
Estimated restoration costs			$ 400.0

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Contingencies and Regulatory Matters - Mississippi Power (Details) - MISSISSIPPI POWER CO - USD ($)					3 Months Ended	9 Months Ended	12 Months Ended
	Jul. 27, 2018	May 08, 2018	Mar. 22, 2018	Feb. 07, 2018	Sep. 30, 2018	Sep. 30, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Aug. 03, 2018
Loss Contingencies [Line Items]
Refund due to customers											$ 5,000,000
Performance evaluation plan, prior year lookback, surcharge (refund)			$ 0					$ 5,000,000	$ 5,000,000	$ 0	$ 0
Public utilities, interim rate increase (decrease), percentage						4.00%	0.00%	0.00%
Public utilities, interim rate						$ 38,000,000
Public utilities, requested revenue requirement increase (decrease), amount				$ 26,000,000
Public utilities, requested return on equity, percentage				9.33%
Performance evaluation plan, equity ratio				55.00%
Increase retail base rate, annual base revenue		$ 3,000,000
Ad valorem tax adjustment, annual rate increase, percentage		0.80%
Ad valorem tax adjustment, annual rate increase, amount		$ 7,000,000
Environmental compliance overview plan, maximum annual increase in revenue, amount												$ 17,000,000
Over (under) recovered retail fuel costs					$ 13,000,000	$ 13,000,000	$ (6,000,000)
PEP Settlement Agreement
Loss Contingencies [Line Items]
Public utilities, approved revenue requirement increase (decrease), amount	$ 21,600,000
Amount subsequently approved for recovery	$ 2,000,000
Public utilities, performance-adjusted allowed return on equity percentage	9.31%
Public utilities, approved return on equity percentage						45.00%
Deferred income taxes	$ 44,000,000
Equity ratio, variance threshold	1.00%
Retail electric revenues					5,000,000
PEP Settlement Agreement | Maximum
Loss Contingencies [Line Items]
Public utilities, approved return on equity percentage	50.00%
Other Regulatory Assets | PEP Settlement Agreement
Loss Contingencies [Line Items]
Regulatory asset					3,000,000	$ 3,000,000
Other Regulatory Assets
Loss Contingencies [Line Items]
Regulatory liabilities					2,000,000	2,000,000
Other Regulatory Assets | PEP Settlement Agreement
Loss Contingencies [Line Items]
Regulatory liabilities					$ 5,000,000	$ 5,000,000

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Contingencies and Regulatory Matters - Southern Company Gas (Details) - USD ($) $ in Millions						1 Months Ended		3 Months Ended
	Oct. 25, 2018	Oct. 15, 2018	May 15, 2018	May 02, 2018	Feb. 23, 2018	Oct. 31, 2018	Jul. 31, 2018	Mar. 31, 2018	Sep. 30, 2018
Florida City Gas
Loss Contingencies [Line Items]
Public utilities, interim rate increase (decrease), percentage			4.00%
Public utilities, approved return on equity percentage			55.00%
Atlanta Gas Light
Loss Contingencies [Line Items]
Public utilities, requested rate increase (decrease), amount					$ (16)
Customer credit							$ 8
Atlanta Gas Light | Pipeline Replacement Program
Loss Contingencies [Line Items]
Litigation settlement awarded from other party								$ 7
Atlanta Gas Light | Subsequent Event
Loss Contingencies [Line Items]
Customer credit						$ 8
Nicor Gas
Loss Contingencies [Line Items]
Public utilities, approved return on equity percentage				9.80%
Approved decrease in fuel rates amount				$ 44
Chattanooga Gas | Subsequent Event
Loss Contingencies [Line Items]
Public utilities, requested rate increase (decrease), amount		$ 1
Public utilities, requested return on equity, percentage		9.80%
Virginia Natural Gas | Impact of Tax Reform Legislation
Loss Contingencies [Line Items]
Regulatory liabilities									$ 9
Virginia Natural Gas | Subsequent Event
Loss Contingencies [Line Items]
Customer refund	$ 14
Minimum | Florida City Gas
Loss Contingencies [Line Items]
Public utilities, requested return on equity, percentage					10.55%
Maximum | Florida City Gas
Loss Contingencies [Line Items]
Public utilities, requested return on equity, percentage			10.95%

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Contingencies and Regulatory Matters - Nuclear Construction (Details) - GEORGIA POWER CO							1 Months Ended	3 Months Ended	9 Months Ended	12 Months Ended				48 Months Ended	108 Months Ended
	Jan. 01, 2021	Jan. 01, 2020	Nov. 09, 2018 USD ($)	Aug. 31, 2018 USD ($)	Jan. 11, 2018 USD ($)	Jan. 01, 2016	Sep. 30, 2018 USD ($) subcontractor	Jun. 30, 2018 USD ($)	Sep. 30, 2018 USD ($) subcontractor MW	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($) report	Dec. 31, 2009 USD ($) utility MW	Dec. 31, 2022 USD ($)	Dec. 31, 2017 USD ($)	Jun. 01, 2021	Mar. 08, 2018 appeal	Sep. 30, 2017 USD ($)	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					$ 3,300,000,000
Estimated in-service capital cost													$ 4,418,000,000
Financing costs collected, net of tax									$ 1,800,000,000
Amendment to estimated in-service capital cost					$ 5,680,000,000
Retail rate of return on common equity																			10.95%
Eligible project costs to be reimbursed									3,460,000,000
Scenario, Forecast
Loss Contingencies [Line Items]
Increase in NCCR tariff			$ 90,000,000
FFB Loan
Loss Contingencies [Line Items]
Long-term line of credit							$ 2,600,000,000		2,600,000,000
Conditional borrowing commitment																		$ 1,670,000,000
Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Construction financing costs									1,800,000,000
Increase in base project capital cost forecast								$ 700,000,000
Estimated project costs								1,100,000,000
Increase in expected costs								$ 800,000,000
Base project capital cost forecast, monthly									50,000,000
Monthly AFUDC									12,000,000
Percentage of ownership interest required for voting for continuing construction				90.00%
Project capital cost forecast							$ 8,400,000,000		8,400,000,000
Additional construction capital costs															$ 4,900,000,000
Construction costs, threshold									$ 2,100,000,000
Percentage of remaining share of construction costs to pay									100.00%
Percentage of cost savings									60.70%
Increase costs amount									$ 100,000
Percentage of approval required to change primary construction contractor							90.00%		90.00%
Percent disallowed for recovery									6.00%
Disallowed for recovery reporting period									6 months
Extension in project schedule							1 year
Percentage of approval required for material amendments							67.00%		67.00%
Voted in favor period									30 days
Ownership interests voted in favor									50.00%
Share of plants (mw) | MW									206
Aggregate purchase price not to exceed									$ 300,000,000
Funding for project									250,000,000
Cost settlement agreement revised forecast, net of payments							$ 7,300,000,000		7,300,000,000
Public utilities, approved return on equity percentage						10.00%
Return on equity reduction, negative impact on earnings												$ 25,000,000
Number Of Appeals | appeal																	2
Number of VCM reports approved | report												18
Guarantor obligations							$ 1,700,000,000		1,700,000,000
Customer refund									$ 188,000,000
Requested capital construction costs				$ 578,000,000
Plant Vogtle Units 3 And 4 | Scenario, Forecast
Loss Contingencies [Line Items]
Construction financing costs										$ 3,200,000,000
Public utilities, approved return on equity percentage	5.30%	8.30%
Approved return on equity, monthly percentage decrease																0.10%
Return on equity reduction, negative impact on earnings											$ 100,000,000			$ 680,000,000
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
Percentage of cost savings									39.30%
Plant Vogtle Units 3 And 4 | Minimum
Loss Contingencies [Line Items]
Number of subcontractors | subcontractor							60		60
Category I | Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Additional construction capital costs									$ 800,000,000
Category II | Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Percentage of construction costs responsible to pay									55.70%
Category II | Plant Vogtle Units 3 And 4 | Vogtle Owners
Loss Contingencies [Line Items]
Percentage of construction costs responsible to pay									44.30%
Category II | Plant Vogtle Units 3 And 4 | Minimum
Loss Contingencies [Line Items]
Additional construction capital costs									$ 80,000,000
Construction costs, threshold									800,000,000
Category II | Plant Vogtle Units 3 And 4 | Maximum
Loss Contingencies [Line Items]
Construction costs, threshold									$ 1,600,000,000
Category III | Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Percentage of construction costs responsible to pay									65.70%
Category III | Plant Vogtle Units 3 And 4 | Vogtle Owners
Loss Contingencies [Line Items]
Percentage of construction costs responsible to pay									34.30%
Category III | Plant Vogtle Units 3 And 4 | Minimum
Loss Contingencies [Line Items]
Additional construction capital costs									$ 100,000,000
Construction costs, threshold									1,600,000,000
Category III | Plant Vogtle Units 3 And 4 | Maximum
Loss Contingencies [Line Items]
Construction costs, threshold									$ 2,100,000,000

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Contingencies and Regulatory Matters - Nuclear Construction Cost and Schedule (Details) - GEORGIA POWER CO - Plant Vogtle Units 3 And 4 $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($)
Loss Contingencies [Line Items]
Base project capital cost forecast	$ 8,000
Construction contingency estimate	400
Project capital cost forecast	8,400
Net investment as of June 30, 2018	(4,300)
Remaining estimate to complete	4,100
Expected capitalized costs	350
Guarantor obligations	1,700
Customer refund	$ 188

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Contingencies and Regulatory Matters - Kemper County Energy Facility (Details) - MISSISSIPPI POWER CO - USD ($) $ in Millions		3 Months Ended		9 Months Ended	12 Months Ended
	Aug. 06, 2018	Dec. 31, 2018	Sep. 30, 2018	Sep. 30, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2017
Loss Contingencies [Line Items]
Accrued plant closure costs			$ 30	$ 30			$ 35
Kemper County Energy Facility
Loss Contingencies [Line Items]
Public utilities, charges to income			0	45
Public utilities, charges to income, after tax				34
Accrued plant closure costs			$ 20	$ 20
Reserve Margin Plan | Plant Watson, Unit 4
Loss Contingencies [Line Items]
Accelerated retirement period	2 years
Reserve Margin Plan | Plant Watson, Unit 5
Loss Contingencies [Line Items]
Accelerated retirement period	7 years
Reserve Margin Plan | Plant Greene County Units 1 and 2
Loss Contingencies [Line Items]
Accelerated retirement period	4 years
Scenario, Forecast | Kemper County Energy Facility
Loss Contingencies [Line Items]
Production costs, period cost		$ 2			$ 4	$ 8

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Contingencies and Regulatory Matters - Other Matters (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2018 USD ($) cavern	Dec. 31, 2017 USD ($)
Southern Company Holdings Subsidiary
Loss Contingencies [Line Items]
Lease receivable	$ 86,000,000
Number of salt dome caverns | cavern	2
SOUTHERN Co GAS
Loss Contingencies [Line Items]
Impairment of long-lived assets		$ 0
Natural Gas, Storage
Loss Contingencies [Line Items]
Property, plant and equipment, net book value	$ 110,000,000
Natural Gas Storage - Salt Dome Caverns
Loss Contingencies [Line Items]
Percentage of total property, plant and equipment	20.00%

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Revenue from Contracts with Customers - Disaggregate Revenue Sources (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Disaggregation of Revenue [Line Items]
Total operating revenues	$ 6,159		$ 18,158
Total operating revenues	6,159	$ 6,201	18,158	$ 17,403
Other Income	92		274
Retail electric revenues
Disaggregation of Revenue [Line Items]
Leases revenues	17		54
Increase (decrease) in revenue from cost recovery mechanisms	(98)		4
Residential
Disaggregation of Revenue [Line Items]
Total operating revenues	2,148		5,266
Commercial
Disaggregation of Revenue [Line Items]
Total operating revenues	1,527		4,084
Industrial
Disaggregation of Revenue [Line Items]
Total operating revenues	901		2,471
Other
Disaggregation of Revenue [Line Items]
Total operating revenues	29		92
Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	433		2,299
Alternative revenue programs
Disaggregation of Revenue [Line Items]
Total operating revenues	5		(23)
Total retail electric and gas distribution revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	5,043		14,189
Wholesale energy revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	516		1,444
Revenue from transactions accounted for as derivatives	63		217
Lease income from PPA contracts	130		318
Wholesale capacity revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	177		479
Lease income from PPA contracts	31		92
Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	54		530
Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	369		1,516
Total operating revenues	199	168	1,007	494
SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Total operating revenues	492		2,861
Total operating revenues	492	565	2,861	2,841
SOUTHERN Co GAS | Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	438		2,276
SOUTHERN Co GAS | Residential
Disaggregation of Revenue [Line Items]
Total operating revenues	149		1,082
SOUTHERN Co GAS | Commercial
Disaggregation of Revenue [Line Items]
Total operating revenues	45		313
SOUTHERN Co GAS | Transportation
Disaggregation of Revenue [Line Items]
Total operating revenues	203		708
SOUTHERN Co GAS | Industrial
Disaggregation of Revenue [Line Items]
Total operating revenues	4		28
SOUTHERN Co GAS | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	32		168
SOUTHERN Co GAS | Alternative revenue programs
Disaggregation of Revenue [Line Items]
Total operating revenues	5		(23)
SOUTHERN Co GAS | Gas marketing Services
Disaggregation of Revenue [Line Items]
Total operating revenues	44		403
Other Income			4
SOUTHERN Co GAS | Wholesale gas services
Disaggregation of Revenue [Line Items]
Total operating revenues	(10)		121
SOUTHERN Co GAS | Gas midstream operations
Disaggregation of Revenue [Line Items]
Total operating revenues	20		60
SOUTHERN Co GAS | Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	0		1
Total operating revenues	0	33	55	95
ALABAMA POWER CO
Disaggregation of Revenue [Line Items]
Total operating revenues	1,740		4,716
Total operating revenues	1,740	1,740	4,716	4,606
Other Income	27		79
ALABAMA POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	1,584		4,208
Increase (decrease) in revenue from cost recovery mechanisms	(12)		113
ALABAMA POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total operating revenues	721		1,848
ALABAMA POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total operating revenues	464		1,238
ALABAMA POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total operating revenues	392		1,103
ALABAMA POWER CO | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	7		19
ALABAMA POWER CO | Wholesale energy revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	62		234
Revenue from transactions accounted for as derivatives	6		14
ALABAMA POWER CO | Wholesale capacity revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	26		75
ALABAMA POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	68		199
Total operating revenues	68	50	199	158
GEORGIA POWER CO
Disaggregation of Revenue [Line Items]
Total operating revenues	2,593		6,601
Total operating revenues	2,593	2,546	6,601	6,426
Other Income	28		80
GEORGIA POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	2,425		6,112
Leases revenues	17		54
Increase (decrease) in revenue from cost recovery mechanisms	(47)		(35)
GEORGIA POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total operating revenues	1,142		2,671
GEORGIA POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total operating revenues	877		2,343
GEORGIA POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total operating revenues	385		1,036
GEORGIA POWER CO | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	21		62
GEORGIA POWER CO | Wholesale energy revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	33		99
Revenue from transactions accounted for as derivatives	8		21
GEORGIA POWER CO | Wholesale capacity revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	14		41
GEORGIA POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	121		349
Leases revenues	34		100
Total operating revenues	121	93	349	284
GULF POWER CO
Disaggregation of Revenue [Line Items]
Total operating revenues	414		1,106
Total operating revenues	414	437	1,106	1,144
Other Income	2		5
GULF POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	341		932
Increase (decrease) in revenue from cost recovery mechanisms	(36)		(63)
GULF POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total operating revenues	200		537
GULF POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total operating revenues	103		291
GULF POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total operating revenues	37		100
GULF POWER CO | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	1		4
GULF POWER CO | Wholesale energy revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	48		104
GULF POWER CO | Wholesale capacity revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	7		20
GULF POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	18		50
Total operating revenues	18	20	50	53
MISSISSIPPI POWER CO
Disaggregation of Revenue [Line Items]
Total operating revenues	358		956
Total operating revenues	358	341	956	915
MISSISSIPPI POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	254		660
Increase (decrease) in revenue from cost recovery mechanisms	(3)		(11)
MISSISSIPPI POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total operating revenues	85		209
MISSISSIPPI POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total operating revenues	82		212
MISSISSIPPI POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total operating revenues	86		233
MISSISSIPPI POWER CO | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	1		6
MISSISSIPPI POWER CO | Wholesale energy revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	92		259
MISSISSIPPI POWER CO | Wholesale capacity revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	1		6
MISSISSIPPI POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	11		31
Total operating revenues	11	5	31	14
SOUTHERN POWER CO
Disaggregation of Revenue [Line Items]
Total operating revenues	635		1,699
Total operating revenues	635	618	1,699	1,597
SOUTHERN POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	168		450
Lease income from PPA contracts	47		141
SOUTHERN POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	336		892
Revenue from transactions accounted for as derivatives	47		176
Lease income from PPA contracts	139		342
SOUTHERN POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	126		347
SOUTHERN POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	5		10
Total operating revenues	5	3	10	9
Operating Segments | SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Total operating revenues	497	607	2,902	3,000
Wholesale gas services | Operating Segments | SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Total operating revenues	(8)	(24)	142	95
Wholesale gas services | Third Party Gross Revenues | Operating Segments | SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Revenue from transactions accounted for as derivatives	900		2,700
Total operating revenues	$ 1,573	$ 1,411	$ 4,847	$ 4,781

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Revenue from Contracts with Customers - Contract Balances (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($)
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Receivables	$ 2,778
Contract Assets	99
Contract Liabilities	34
Unregulated Distributed Generation
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Contract Assets	27
Contract Liabilities	17
ALABAMA POWER CO
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Receivables	649
Contract Assets	1
Contract Liabilities	14
GEORGIA POWER CO
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Receivables	924
Contract Assets	70
Contract Liabilities	$ 3
Performance obligation, expected timing of satisfaction	Georgia Power had contract assets primarily related to 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.
GULF POWER CO
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Receivables	$ 186
Contract Assets	0
Contract Liabilities	0
MISSISSIPPI POWER CO
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Receivables	96
Contract Assets	0
Contract Liabilities	0
SOUTHERN POWER CO
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Receivables	142
Contract Assets	0
Contract Liabilities	17
SOUTHERN Co GAS
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Receivables	523
Contract Assets	0
Contract Liabilities	$ 1

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Revenue from Contracts with Customers - Performance Obligations (Details) $ in Millions	Sep. 30, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 168
Performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 406
Performance obligation, expected timing of satisfaction	1 year
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	$ 322
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	$ 322
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	$ 310
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	$ 2,112
Performance obligation, expected timing of satisfaction
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 6
Performance obligation, expected timing of satisfaction	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
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]: 2020-01-01
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]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 26
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	$ 161
Performance obligation, expected timing of satisfaction
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 10
Performance obligation, expected timing of satisfaction	1 year
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 41
Performance obligation, expected timing of satisfaction	1 year
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	$ 38
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	$ 40
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	$ 30
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	$ 113
Performance obligation, expected timing of satisfaction
GULF POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 5
Performance obligation, expected timing of satisfaction	1 year
GULF POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 22
Performance obligation, expected timing of satisfaction	1 year
GULF 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	$ 0
Performance obligation, expected timing of satisfaction	1 year
GULF 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	$ 0
Performance obligation, expected timing of satisfaction	1 year
GULF 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	$ 0
Performance obligation, expected timing of satisfaction	1 year
GULF 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	$ 0
Performance obligation, expected timing of satisfaction
MISSISSIPPI POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 1
Performance obligation, expected timing of satisfaction	1 year
MISSISSIPPI POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 3
Performance obligation, expected timing of satisfaction	1 year
MISSISSIPPI 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	$ 3
Performance obligation, expected timing of satisfaction	1 year
MISSISSIPPI 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	$ 1
Performance obligation, expected timing of satisfaction	1 year
MISSISSIPPI 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	$ 0
Performance obligation, expected timing of satisfaction	1 year
MISSISSIPPI 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	$ 0
Performance obligation, expected timing of satisfaction
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 75
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 310
Performance obligation, expected timing of satisfaction	1 year
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	$ 283
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	$ 277
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	$ 2,005
Performance obligation, expected timing of satisfaction

XML

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Liabilities:
Collateral already posted, aggregate fair value	$ 189
Net Asset Value as a Practical Expedient (NAV)
Assets:
Net Asset Value as a Practical Expedient (NAV)	37
Net Asset Value as a Practical Expedient (NAV) | Nuclear Decommissioning Trusts
Assets:
Net Asset Value as a Practical Expedient (NAV)	37
ALABAMA POWER CO
Assets:
Energy-related derivatives	7	$ 4
Liabilities:
Energy-related derivatives	10	10
ALABAMA POWER CO | Net Asset Value as a Practical Expedient (NAV)
Assets:
Net Asset Value as a Practical Expedient (NAV)	37
ALABAMA POWER CO | Net Asset Value as a Practical Expedient (NAV) | Nuclear Decommissioning Trusts
Assets:
Net Asset Value as a Practical Expedient (NAV)	37
GEORGIA POWER CO
Assets:
Energy-related derivatives	7	6
Nuclear decommissioning trusts	37
Liabilities:
Energy-related derivatives	28	24
GEORGIA POWER CO | Net Asset Value as a Practical Expedient (NAV)
Assets:
Net Asset Value as a Practical Expedient (NAV)	0
GULF POWER CO
Assets:
Energy-related derivatives	0	0
Liabilities:
Energy-related derivatives	8	21
MISSISSIPPI POWER CO
Assets:
Energy-related derivatives	3	3
Liabilities:
Energy-related derivatives	9	9
SOUTHERN POWER CO
Assets:
Energy-related derivatives	125	132
Liabilities:
Energy-related derivatives	30	36
SOUTHERN Co GAS
Assets:
Energy-related derivatives	400	554
Liabilities:
Energy-related derivatives	516	660
Collateral already posted, aggregate fair value	189	$ 193
Fair Value, Measurements, Recurring
Assets:
Energy-related derivatives	421
Foreign currency derivatives	122
Nuclear decommissioning trusts	1,872
Cash equivalents	1,309
Total	3,778
Liabilities:
Energy-related derivatives	575
Interest rate derivatives	72
Foreign currency derivatives	23
Contingent consideration	22
Total	692
Fair Value, Measurements, Recurring | Weather Derivative
Assets:
Energy-related derivatives	5
Fair Value, Measurements, Recurring | Domestic equity
Assets:
Non-qualified deferred compensation trusts:	11
Fair Value, Measurements, Recurring | Foreign equity
Assets:
Non-qualified deferred compensation trusts:	6
Fair Value, Measurements, Recurring | Pooled funds – fixed income
Assets:
Non-qualified deferred compensation trusts:	13
Fair Value, Measurements, Recurring | Cash equivalents
Assets:
Non-qualified deferred compensation trusts:	15
Fair Value, Measurements, Recurring | Other
Assets:
Non-qualified deferred compensation trusts:	9
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives	271
Foreign currency derivatives	0
Nuclear decommissioning trusts	828
Cash equivalents	1,309
Total	2,432
Liabilities:
Energy-related derivatives	416
Interest rate derivatives	0
Foreign currency derivatives	0
Contingent consideration	0
Total	416
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity
Assets:
Non-qualified deferred compensation trusts:	0
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign equity
Assets:
Non-qualified deferred compensation trusts:	0
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pooled funds – fixed income
Assets:
Non-qualified deferred compensation trusts:	0
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Cash equivalents
Assets:
Non-qualified deferred compensation trusts:	15
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Assets:
Non-qualified deferred compensation trusts:	9
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives	150
Foreign currency derivatives	122
Nuclear decommissioning trusts	1,007
Cash equivalents	0
Total	1,309
Liabilities:
Energy-related derivatives	159
Interest rate derivatives	72
Foreign currency derivatives	23
Contingent consideration	0
Total	254
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Domestic equity
Assets:
Non-qualified deferred compensation trusts:	11
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Foreign equity
Assets:
Non-qualified deferred compensation trusts:	6
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Pooled funds – fixed income
Assets:
Non-qualified deferred compensation trusts:	13
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Cash equivalents
Assets:
Non-qualified deferred compensation trusts:	0
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Other
Assets:
Non-qualified deferred compensation trusts:	0
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives	0
Foreign currency derivatives	0
Nuclear decommissioning trusts	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Foreign currency derivatives	0
Contingent consideration	22
Total	22
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Domestic equity
Assets:
Non-qualified deferred compensation trusts:	0
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Foreign equity
Assets:
Non-qualified deferred compensation trusts:	0
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Pooled funds – fixed income
Assets:
Non-qualified deferred compensation trusts:	0
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Cash equivalents
Assets:
Non-qualified deferred compensation trusts:	0
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Other
Assets:
Non-qualified deferred compensation trusts:	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO
Assets:
Energy-related derivatives	7
Cash equivalents	513
Total	1,458
Liabilities:
Energy-related derivatives	10
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Domestic equity
Assets:
Nuclear decommissioning trusts	558
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Foreign equity
Assets:
Nuclear decommissioning trusts	116
Fair Value, Measurements, Recurring | ALABAMA POWER CO | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	18
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Corporate bonds
Assets:
Nuclear decommissioning trusts	180
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	22
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Private equity
Assets:
Nuclear decommissioning trusts	37
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Other
Assets:
Nuclear decommissioning trusts	7
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives	0
Cash equivalents	513
Total	1,075
Liabilities:
Energy-related derivatives	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity
Assets:
Nuclear decommissioning trusts	469
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign equity
Assets:
Nuclear decommissioning trusts	60
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate bonds
Assets:
Nuclear decommissioning trusts	26
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Private equity
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Assets:
Nuclear decommissioning trusts	7
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives	7
Cash equivalents	0
Total	346
Liabilities:
Energy-related derivatives	10
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Domestic equity
Assets:
Nuclear decommissioning trusts	89
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Foreign equity
Assets:
Nuclear decommissioning trusts	56
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	18
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Corporate bonds
Assets:
Nuclear decommissioning trusts	154
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	22
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Private equity
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Other Observable Inputs (Level 2) | Other
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Domestic equity
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Foreign equity
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Corporate bonds
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Private equity
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | ALABAMA POWER CO | Significant Unobservable Inputs (Level 3) | Other
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO
Assets:
Energy-related derivatives	8
Cash equivalents	350
Total	1,291
Liabilities:
Energy-related derivatives	22
Interest rate derivatives	6
Total	28
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Domestic equity
Assets:
Nuclear decommissioning trusts	251
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Foreign equity
Assets:
Nuclear decommissioning trusts	134
Fair Value, Measurements, Recurring | GEORGIA POWER CO | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	236
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Municipal bonds
Assets:
Nuclear decommissioning trusts	82
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Corporate bonds
Assets:
Nuclear decommissioning trusts	163
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	42
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Other
Assets:
Non-qualified deferred compensation trusts:	25
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives	0
Cash equivalents	350
Total	616
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Total	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity
Assets:
Nuclear decommissioning trusts	250
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign equity
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Municipal bonds
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate bonds
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Assets:
Non-qualified deferred compensation trusts:	16
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives	8
Cash equivalents	0
Total	675
Liabilities:
Energy-related derivatives	22
Interest rate derivatives	6
Total	28
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Domestic equity
Assets:
Nuclear decommissioning trusts	1
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Foreign equity
Assets:
Nuclear decommissioning trusts	134
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	236
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Municipal bonds
Assets:
Nuclear decommissioning trusts	82
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Corporate bonds
Assets:
Nuclear decommissioning trusts	163
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	42
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Other Observable Inputs (Level 2) | Other
Assets:
Non-qualified deferred compensation trusts:	9
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Total	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Domestic equity
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Foreign equity
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Municipal bonds
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Corporate bonds
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	0
Fair Value, Measurements, Recurring | GEORGIA POWER CO | Significant Unobservable Inputs (Level 3) | Other
Assets:
Non-qualified deferred compensation trusts:	0
Fair Value, Measurements, Recurring | GULF POWER CO
Assets:
Cash equivalents	27
Liabilities:
Energy-related derivatives	8
Fair Value, Measurements, Recurring | GULF POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	27
Liabilities:
Energy-related derivatives	0
Fair Value, Measurements, Recurring | GULF POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	0
Liabilities:
Energy-related derivatives	8
Fair Value, Measurements, Recurring | GULF POWER CO | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents	0
Liabilities:
Energy-related derivatives	0
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO
Assets:
Energy-related derivatives	3
Cash equivalents	346
Total	349
Liabilities:
Energy-related derivatives	9
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives	0
Cash equivalents	346
Total	346
Liabilities:
Energy-related derivatives	0
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives	3
Cash equivalents	0
Total	3
Liabilities:
Energy-related derivatives	9
Fair Value, Measurements, Recurring | MISSISSIPPI POWER CO | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO
Assets:
Energy-related derivatives	3
Foreign currency derivatives	122
Total	125
Liabilities:
Energy-related derivatives	7
Foreign currency derivatives	23
Contingent consideration	22
Total	52
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives	0
Foreign currency derivatives	0
Total	0
Liabilities:
Energy-related derivatives	0
Foreign currency derivatives	0
Contingent consideration	0
Total	0
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives	3
Foreign currency derivatives	122
Total	125
Liabilities:
Energy-related derivatives	7
Foreign currency derivatives	23
Contingent consideration	0
Total	30
Fair Value, Measurements, Recurring | SOUTHERN POWER CO | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives	0
Foreign currency derivatives	0
Total	0
Liabilities:
Energy-related derivatives	0
Foreign currency derivatives	0
Contingent consideration	22
Total	22
Fair Value, Measurements, Recurring | SOUTHERN Co GAS
Assets:
Energy-related derivatives	400
Cash equivalents	26
Total	460
Liabilities:
Energy-related derivatives	517
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Domestic equity
Assets:
Non-qualified deferred compensation trusts:	11
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Foreign equity
Assets:
Non-qualified deferred compensation trusts:	6
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Pooled funds – fixed income
Assets:
Non-qualified deferred compensation trusts:	13
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Other
Assets:
Non-qualified deferred compensation trusts:	4
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives	271
Cash equivalents	26
Total	301
Liabilities:
Energy-related derivatives	416
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity
Assets:
Non-qualified deferred compensation trusts:	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign equity
Assets:
Non-qualified deferred compensation trusts:	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1) | Pooled funds – fixed income
Assets:
Non-qualified deferred compensation trusts:	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Assets:
Non-qualified deferred compensation trusts:	4
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives	129
Cash equivalents	0
Total	159
Liabilities:
Energy-related derivatives	101
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2) | Domestic equity
Assets:
Non-qualified deferred compensation trusts:	11
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2) | Foreign equity
Assets:
Non-qualified deferred compensation trusts:	6
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2) | Pooled funds – fixed income
Assets:
Non-qualified deferred compensation trusts:	13
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Other Observable Inputs (Level 2) | Other
Assets:
Non-qualified deferred compensation trusts:	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Domestic equity
Assets:
Non-qualified deferred compensation trusts:	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Foreign equity
Assets:
Non-qualified deferred compensation trusts:	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Pooled funds – fixed income
Assets:
Non-qualified deferred compensation trusts:	0
Fair Value, Measurements, Recurring | SOUTHERN Co GAS | Significant Unobservable Inputs (Level 3) | Other
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		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ 58	$ 50	$ 68	$ 168
ALABAMA POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	39	25	49	87
GEORGIA POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ 19	$ 25	$ 19	$ 81

XML

Fair Value Measurements - Fair Value Measurements Of Investments Calculated At Net Asset Value Per Share (Details) $ in Millions	Sep. 30, 2018 USD ($)
Private equity
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Unfunded Commitments	$ 47
ALABAMA POWER CO | Private equity
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Unfunded Commitments	47
Net Asset Value as a Practical Expedient (NAV)
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	37
Net Asset Value as a Practical Expedient (NAV) | Private equity
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	37
Net Asset Value as a Practical Expedient (NAV) | ALABAMA POWER CO
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	37
Net Asset Value as a Practical Expedient (NAV) | ALABAMA POWER CO | Private equity
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	$ 37

XML

Fair Value Measurements - Narrative (Details)	9 Months Ended
	Sep. 30, 2018
Private equity
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Liquidations term	10 years

XML

Fair Value Measurements - Financial Instruments for which Carrying Amount did not Equal Fair Value (Details) $ in Millions	Sep. 30, 2018 USD ($)
Southern Company
Long-term debt, including securities due within one year:
Carrying Amount	$ 45,524
Fair Value	45,500
ALABAMA POWER CO
Long-term debt, including securities due within one year:
Carrying Amount	8,120
Fair Value	8,321
GEORGIA POWER CO
Long-term debt, including securities due within one year:
Carrying Amount	10,227
Fair Value	10,159
GULF POWER CO
Long-term debt, including securities due within one year:
Carrying Amount	1,285
Fair Value	1,290
MISSISSIPPI POWER CO
Long-term debt, including securities due within one year:
Carrying Amount	1,736
Fair Value	1,702
SOUTHERN POWER CO
Long-term debt, including securities due within one year:
Carrying Amount	5,029
Fair Value	5,058
SOUTHERN Co GAS
Long-term debt, including securities due within one year:
Carrying Amount	5,908
Fair Value	$ 5,935

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Stockholders' Equity - Earnings per Share (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Equity [Abstract]
As reported shares (in shares)	1,023	1,003	1,016	998
Effect of stock-based compensation (in shares)	6	7	5	7
Diluted shares (in shares)	1,029	1,010	1,021	1,005

XML

Stockholders' Equity - Changes in Stockholders' Equity (Details) - USD ($) shares in Thousands, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Changes in Stockholders' Equity
Beginning balance, treasury shares (in shares)			(900)
Beginning balance			$ 25,528	$ 26,612
Consolidated net income attributable to Southern Company	$ 1,164	$ 1,069	1,948	347
Other comprehensive income (loss)			52	(2)
Stock issued			878	613
Stock-based compensation			74	97
Cash dividends on common stock			(1,805)	(1,716)
Preference stock redemption				(150)
Contributions from noncontrolling interests			154	77
Distributions to noncontrolling interests			(87)	(87)
Net income attributable to noncontrolling interests			71	45
Sale of noncontrolling interests			1,280
Reclassification from redeemable noncontrolling interests				114
Other			$ (28)	(11)
Ending balance, treasury shares (in shares)	(1,000)		(1,000)
Ending balance	$ 28,065	$ 25,939	$ 28,065	$ 25,939
Number of Common Shares Issued
Changes in Stockholders' Equity
Beginning balance (in shares)			1,008,532	991,213
Stock issued (in shares)			21,342	13,308
Other (in shares)			0
Ending balance (in shares)	1,029,874	1,004,521	1,029,874	1,004,521
Number of Common Shares Treasury Issued
Changes in Stockholders' Equity
Beginning balance, treasury shares (in shares)			(929)	(819)
Other (in shares)			(57)	(75)
Ending balance, treasury shares (in shares)	(986)	(894)	(986)	(894)
Common Stockholders' Equity
Changes in Stockholders' Equity
Beginning balance			$ 24,167	$ 24,758
Consolidated net income attributable to Southern Company			1,948	347
Other comprehensive income (loss)			52	(2)
Stock issued			878	613
Stock-based compensation			74	97
Cash dividends on common stock			(1,805)	(1,716)
Sale of noncontrolling interests			(410)
Other			(27)	(15)
Ending balance	$ 24,877	$ 24,082	24,877	24,082
Preferred and Preference Stock of Subsidiaries
Changes in Stockholders' Equity
Beginning balance			0	609
Preference stock redemption				(150)
Other				3
Ending balance	0	462	0	462
Noncontrolling Interests
Changes in Stockholders' Equity
Beginning balance			1,361	1,245
Contributions from noncontrolling interests			154	77
Distributions to noncontrolling interests			(87)	(87)
Net income attributable to noncontrolling interests			71	45
Sale of noncontrolling interests			1,690
Reclassification from redeemable noncontrolling interests				114
Other			(1)	1
Ending balance	$ 3,188	$ 1,395	$ 3,188	$ 1,395

XML

Financing - Narrative (Details)	1 Months Ended						3 Months Ended		9 Months Ended
	Nov. 06, 2018 USD ($) shares	Aug. 31, 2018 USD ($)	Jun. 30, 2018 USD ($) agreement	May 31, 2018 USD ($) agreement	Apr. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Jul. 31, 2018 USD ($)	Jan. 31, 2018 USD ($)	Jan. 04, 2018 USD ($)
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding							$ 1,500,000,000		$ 1,500,000,000
Maximum borrowing capacity							8,143,000,000		8,143,000,000
Repayments of short-term debt									1,800,000,000	$ 409,000,000
Stock redeemed during period, par value										150,000,000
Floating rate Promissory Note Due July 2018
Debt Instrument [Line Items]
Debt face amount													$ 100,000,000
Southern Company
Debt Instrument [Line Items]
Maximum borrowing capacity							2,000,000,000		2,000,000,000
Southern Company | Floating Rate Bank Term Loan Agreement 1 | Notes Payable to Banks
Debt Instrument [Line Items]
Debt face amount						$ 900,000,000
Southern Company | Uncommitted Bank Credit Arrangement | Notes Payable to Banks
Debt Instrument [Line Items]
Debt face amount					$ 250,000,000
Debt instrument, payable by demand from bank, term					30 days
Repayments of short-term debt		$ 250,000,000
Southern Company | Floating Rate Bank Term Loan Agreement 6 | Notes Payable to Banks
Debt Instrument [Line Items]
Debt face amount		1,500,000,000.0
Southern Company | Notes Payable to Banks | Floating Rate Bank Term Loan Agreement 1
Debt Instrument [Line Items]
Number of loan agreements | agreement			2
Southern Company | Notes Payable to Banks | Floating Rate Bank Term Loan Agreement 4
Debt Instrument [Line Items]
Debt face amount			$ 100,000,000					$ 100,000,000
Southern Company | Notes Payable to Banks | Floating Rate Bank Term Loan Agreement 5
Debt Instrument [Line Items]
Debt face amount			100,000,000					100,000,000
Southern Company | Senior Notes | Series 2018A Floating Rate Senior Notes Due February 14, 2020
Debt Instrument [Line Items]
Debt face amount		750,000,000
ALABAMA POWER CO
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding							854,000,000		854,000,000
Fixed rate pollution control revenue bonds outstanding							120,000,000		120,000,000
Maximum borrowing capacity							1,333,000,000		1,333,000,000
ALABAMA POWER CO | Senior Notes | Series 2018A Floating Rate Senior Notes
Debt Instrument [Line Items]
Debt face amount			$ 500,000,000					$ 500,000,000
Debt stated interest rate			4.30%					4.30%
ALABAMA POWER CO | Senior Notes | Series 2008B 5.40% Senior Notes due June 1, 2018
Debt Instrument [Line Items]
Debt stated interest rate					5.40%
Repurchased face amount					$ 250,000,000
ALABAMA POWER CO | Subsequent Event | Pollution Control Revenue Bonds
Debt Instrument [Line Items]
Debt instrument, repurchase amount	$ 120,000,000
GEORGIA POWER CO
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding							550,000,000		550,000,000
Fixed rate pollution control revenue bonds outstanding							345,000,000		345,000,000
Maximum borrowing capacity							1,750,000,000		$ 1,750,000,000
Amortization period for line of credit facility									5 years
Percent of eligible project costs to be reimbursed									70.00%
Repayments of short-term debt									$ 150,000,000	300,000,000
GEORGIA POWER CO | Loan Guarantee Agreement
Debt Instrument [Line Items]
Conditional borrowing commitment										1,670,000,000
GEORGIA POWER CO | Notes Payable to Banks | Floating Rate Bank Term Loan Agreement 2
Debt Instrument [Line Items]
Debt face amount												$ 150,000,000
GEORGIA POWER CO | Notes Payable to Banks | Floating Rate Bank Term Loan Agreement 3
Debt Instrument [Line Items]
Debt face amount												$ 100,000,000
GEORGIA POWER CO | Senior Notes
Debt Instrument [Line Items]
Repayments of debt				$ 902,000,000
GEORGIA POWER CO | Senior Notes | Series 2007A 5.65% Senior Notes
Debt Instrument [Line Items]
Debt instrument, repurchase amount				89,000,000
Debt face amount				$ 250,000,000
Debt stated interest rate				5.65%
GEORGIA POWER CO | Senior Notes | Series 2009A 5.95% Senior Notes
Debt Instrument [Line Items]
Debt instrument, repurchase amount				$ 326,000,000
Debt face amount				$ 500,000,000
Debt stated interest rate				5.95%
GEORGIA POWER CO | Senior Notes | Series 2010B 5.40% Senior Notes
Debt Instrument [Line Items]
Debt instrument, repurchase amount				$ 335,000,000
Debt face amount				$ 600,000,000
Debt stated interest rate				5.40%
GEORGIA POWER CO | Municipal bonds | Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995
Debt Instrument [Line Items]
Debt face amount							104,600,000		104,600,000
GEORGIA POWER CO | Municipal bonds | Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1997
Debt Instrument [Line Items]
Debt face amount							173,000,000		173,000,000
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
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		65,000,000
GEORGIA POWER CO | Municipal bonds | Development Authority Of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013
Debt Instrument [Line Items]
Debt face amount							71,735,000.000		71,735,000.000
GEORGIA POWER CO | FFB Loan
Debt Instrument [Line Items]
Conditional borrowing commitment										1,670,000,000
Maximum borrowing capacity							2,600,000,000		2,600,000,000
GULF POWER CO
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding							82,000,000		82,000,000
Fixed rate pollution control revenue bonds outstanding							58,000,000		58,000,000
Maximum borrowing capacity							280,000,000		280,000,000
MISSISSIPPI POWER CO
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding							40,000,000		40,000,000
Fixed rate pollution control revenue bonds outstanding							50,000,000		50,000,000
Maximum borrowing capacity							100,000,000		100,000,000
Repayments of short-term debt									300,000,000	$ 109,000,000
MISSISSIPPI POWER CO | Notes Payable to Banks
Debt Instrument [Line Items]
Debt face amount						300,000,000
MISSISSIPPI POWER CO | Senior Notes | Series 2018A Floating Rate Senior Notes
Debt Instrument [Line Items]
Debt face amount						300,000,000
MISSISSIPPI POWER CO | Senior Notes | Series 2018B 3.95% Senior Notes
Debt Instrument [Line Items]
Debt face amount						$ 300,000,000
Debt stated interest rate						3.95%
MISSISSIPPI POWER CO | Municipal bonds | Pollution Control Revenue Bonds
Debt Instrument [Line Items]
Debt instrument, repurchase amount											$ 43,000,000
MISSISSIPPI POWER CO | Promissory Notes | Promissory Notes
Debt Instrument [Line Items]
Repayments of debt							100,000,000	$ 200,000,000
MISSISSIPPI POWER CO | Unsecured Debt | Unsecured Term Loan
Debt Instrument [Line Items]
Repayments of debt						$ 900,000,000
MISSISSIPPI POWER CO | Subsequent Event | Senior Notes | Series G 5.40% Senior Notes Due July 1, 2035
Debt Instrument [Line Items]
Debt stated interest rate	5.40%
Aggregate principal amount outstanding	$ 30,000,000
MISSISSIPPI POWER CO | Subsequent Event | Senior Notes | Series 2009A 5.55% Senior Notes Due March 1, 2019
Debt Instrument [Line Items]
Debt stated interest rate	5.55%
Aggregate principal amount outstanding	$ 125,000,000
MISSISSIPPI POWER CO | 4.40% Series Preferred Stock | Subsequent Event
Debt Instrument [Line Items]
Stock redeemed during period (in shares) | shares	8,867
Stock redeemed during period, par value	$ 886,700
Preferred stock, dividend rate	4.40%
MISSISSIPPI POWER CO | 4.60% Series Preferred Stock | Subsequent Event
Debt Instrument [Line Items]
Stock redeemed during period (in shares) | shares	8,643
Stock redeemed during period, par value	$ 864,300
Preferred stock, dividend rate	4.60%
MISSISSIPPI POWER CO | 4.72% Series Preferred Stock | Subsequent Event
Debt Instrument [Line Items]
Stock redeemed during period (in shares) | shares	16,700
Stock redeemed during period, par value	$ 1,670,000
Preferred stock, dividend rate	4.72%
MISSISSIPPI POWER CO | Depository Shares | Subsequent Event
Debt Instrument [Line Items]
Stock redeemed during period (in shares) | shares	1,200,000
Stock redeemed during period, par value	$ 30,000,000
Interest in shares	25.00%
MISSISSIPPI POWER CO | 5.25% Series Preferred Stock | Subsequent Event
Debt Instrument [Line Items]
Preferred stock, dividend rate	5.25%
Traditional Electric Operating Companies
Debt Instrument [Line Items]
Fixed rate pollution control revenue bonds outstanding							573,000,000		573,000,000
SOUTHERN POWER CO
Debt Instrument [Line Items]
Maximum borrowing capacity							750,000,000		750,000,000
Repayments of debt				$ 770,000,000
Proceeds from third-party tax equity									148,000,000
SOUTHERN POWER CO | Floating Rate Bank Term Loan Agreement 1 | Notes Payable to Banks
Debt Instrument [Line Items]
Debt face amount				$ 100,000,000
Number of loan agreements | agreement				2
Repurchased face amount			$ 420,000,000					$ 420,000,000
SOUTHERN POWER CO | Senior Notes | Series 2015A 1.50% Senior Notes
Debt Instrument [Line Items]
Debt stated interest rate			1.50%					1.50%
Repurchased face amount			$ 350,000,000					$ 350,000,000
SOUTHERN Co GAS
Debt Instrument [Line Items]
Maximum borrowing capacity							1,900,000,000		1,900,000,000
SOUTHERN Co GAS | Uncommitted Bank Credit Arrangement | Notes Payable to Banks
Debt Instrument [Line Items]
Debt face amount				$ 95,000,000
Debt instrument, payable by demand from bank, term				30 days
SOUTHERN Co GAS | Senior Notes | Series 2017A
Debt Instrument [Line Items]
Debt face amount			$ 200,000,000					$ 200,000,000
Nicor Gas
Debt Instrument [Line Items]
Maximum borrowing capacity							$ 500,000,000		$ 500,000,000
Nicor Gas | First Mortgage Bonds
Debt Instrument [Line Items]
Debt face amount											$ 300,000,000
Nicor Gas | First Mortgage Bonds | First Mortgage Bonds Issued August 2018
Debt Instrument [Line Items]
Debt face amount		$ 100,000,000
Nicor Gas | Subsequent Event | First Mortgage Bonds | First Mortgage Bonds Issued November 2018
Debt Instrument [Line Items]
Debt face amount	$ 200,000,000

XML

Financing - Schedule of Credit Arrangements (Details)	Sep. 30, 2018 USD ($)
Line of Credit Facility [Line Items]
Expires, 2018	$ 20,000,000
Expires, 2019	188,000,000
Expires, 2020	735,000,000
Expires, 2022	7,200,000,000
Total	8,143,000,000
Unused	8,101,000,000
Executable Term Loans, One Year	45,000,000
Expires Within One Year, Term Out	45,000,000
Expires Within One Year, No Term Out	63,000,000
Southern Company
Line of Credit Facility [Line Items]
Expires, 2018	0
Expires, 2019	0
Expires, 2020	0
Expires, 2022	2,000,000,000
Total	2,000,000,000
Unused	1,999,000,000
Executable Term Loans, One Year	0
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	0
ALABAMA POWER CO
Line of Credit Facility [Line Items]
Expires, 2018	0
Expires, 2019	33,000,000
Expires, 2020	500,000,000
Expires, 2022	800,000,000
Total	1,333,000,000
Unused	1,333,000,000
Executable Term Loans, One Year	0
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	33,000,000
GEORGIA POWER CO
Line of Credit Facility [Line Items]
Expires, 2018	0
Expires, 2019	0
Expires, 2020	0
Expires, 2022	1,750,000,000
Total	1,750,000,000
Unused	1,736,000,000
Executable Term Loans, One Year	0
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	0
GULF POWER CO
Line of Credit Facility [Line Items]
Expires, 2018	20,000,000
Expires, 2019	25,000,000
Expires, 2020	235,000,000
Expires, 2022	0
Total	280,000,000
Unused	280,000,000
Executable Term Loans, One Year	45,000,000
Expires Within One Year, Term Out	45,000,000
Expires Within One Year, No Term Out	0
MISSISSIPPI POWER CO
Line of Credit Facility [Line Items]
Expires, 2018	0
Expires, 2019	100,000,000
Expires, 2020	0
Expires, 2022	0
Total	100,000,000
Unused	100,000,000
Executable Term Loans, One Year	0
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	0
SOUTHERN POWER CO
Line of Credit Facility [Line Items]
Expires, 2018	0
Expires, 2019	0
Expires, 2020	0
Expires, 2022	750,000,000
Total	750,000,000
Unused	728,000,000
Executable Term Loans, One Year	0
Expires Within One Year, Term Out	0
Expires 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	22,000,000
SOUTHERN Co GAS
Line of Credit Facility [Line Items]
Expires, 2018	0
Expires, 2019	0
Expires, 2020	0
Expires, 2022	1,900,000,000
Total	1,900,000,000
Unused	1,895,000,000
Executable Term Loans, One Year	0
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	0
Other
Line of Credit Facility [Line Items]
Expires, 2018	0
Expires, 2019	30,000,000
Expires, 2020	0
Expires, 2022	0
Total	30,000,000
Unused	30,000,000
Executable Term Loans, One Year	0
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	30,000,000
Southern Company Gas Capital
Line of Credit Facility [Line Items]
Total	1,400,000,000.0
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	9 Months Ended
	Sep. 30, 2018 USD ($)
Debt Instrument [Line Items]
Senior Note Issuances	$ 1,850
Senior Note Maturities, Redemptions, and Repurchases	2,350
Revenue Bond Maturities, Redemptions, and Repurchases	712
Other Long-Term Debt Issuances	100
Other Long-Term Debt Redemptions and Maturities	1,436
Elimination
Debt Instrument [Line Items]
Senior Note Issuances	0
Senior Note Maturities, Redemptions, and Repurchases	0
Revenue Bond Maturities, Redemptions, and Repurchases	0
Other Long-Term Debt Issuances	0
Other Long-Term Debt Redemptions and Maturities	(1)
ALABAMA POWER CO
Debt Instrument [Line Items]
Senior Note Issuances	500
Senior Note Maturities, Redemptions, and Repurchases	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 Issuances	0
Senior Note Maturities, Redemptions, and Repurchases	1,000
Revenue Bond Maturities, Redemptions, and Repurchases	469
Other Long-Term Debt Issuances	0
Other Long-Term Debt Redemptions and Maturities	107
MISSISSIPPI POWER CO
Debt Instrument [Line Items]
Senior Note Issuances	600
Senior Note Maturities, Redemptions, and Repurchases	0
Revenue Bond Maturities, Redemptions, and Repurchases	43
Other Long-Term Debt Issuances	0
Other Long-Term Debt Redemptions and Maturities	900
SOUTHERN POWER CO
Debt Instrument [Line Items]
Senior Note Issuances	0
Senior Note Maturities, Redemptions, and Repurchases	350
Revenue Bond Maturities, Redemptions, and Repurchases	0
Other Long-Term Debt Issuances	0
Other Long-Term Debt Redemptions and Maturities	420
SOUTHERN Co GAS
Debt Instrument [Line Items]
Senior Note Issuances	0
Senior Note Maturities, Redemptions, and Repurchases	0
Revenue Bond Maturities, Redemptions, and Repurchases	200
Other Long-Term Debt Issuances	100
Other Long-Term Debt Redemptions and Maturities	0
Other
Debt Instrument [Line Items]
Senior Note Issuances	0
Senior Note Maturities, Redemptions, and Repurchases	0
Revenue Bond Maturities, Redemptions, and Repurchases	0
Other Long-Term Debt Issuances	0
Other Long-Term Debt Redemptions and Maturities	10
Southern Company
Debt Instrument [Line Items]
Senior Note Issuances	750
Senior Note Maturities, Redemptions, and Repurchases	1,000
Revenue Bond Maturities, Redemptions, and Repurchases	0
Other Long-Term Debt Issuances	0
Other Long-Term Debt Redemptions and Maturities	$ 0

XML

Retirement Benefits (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
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 | ALABAMA POWER CO
Pension Plans and Postretirement Plans
Service cost	19,000,000	15,000,000	58,000,000	$ 47,000,000
Interest cost	26,000,000	25,000,000	76,000,000	73,000,000
Expected return on plan assets	(51,000,000)	(49,000,000)	(155,000,000)	(147,000,000)
Amortization:
Prior service costs	0	1,000,000	1,000,000	2,000,000
Regulatory asset	0		0
Net (gain)/loss	13,000,000	10,000,000	40,000,000	31,000,000
Net periodic pension cost (income)	7,000,000	2,000,000	20,000,000	6,000,000
Pension Plans | GEORGIA POWER CO
Pension Plans and Postretirement Plans
Service cost	22,000,000	19,000,000	65,000,000	56,000,000
Interest cost	34,000,000	34,000,000	104,000,000	103,000,000
Expected return on plan assets	(74,000,000)	(71,000,000)	(222,000,000)	(212,000,000)
Amortization:
Prior service costs	1,000,000	0	2,000,000	2,000,000
Regulatory asset	0		0
Net (gain)/loss	18,000,000	15,000,000	52,000,000	43,000,000
Net periodic pension cost (income)	1,000,000	(3,000,000)	1,000,000	(8,000,000)
Pension Plans | GULF POWER CO
Pension Plans and Postretirement Plans
Service cost	4,000,000	3,000,000	12,000,000	10,000,000
Interest cost	5,000,000	5,000,000	15,000,000	15,000,000
Expected return on plan assets	(10,000,000)	(10,000,000)	(30,000,000)	(29,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0		0
Net (gain)/loss	2,000,000	2,000,000	7,000,000	5,000,000
Net periodic pension cost (income)	1,000,000	0	4,000,000	1,000,000
Pension Plans | MISSISSIPPI POWER CO
Pension Plans and Postretirement Plans
Service cost	5,000,000	4,000,000	13,000,000	11,000,000
Interest cost	5,000,000	5,000,000	15,000,000	15,000,000
Expected return on plan assets	(11,000,000)	(9,000,000)	(31,000,000)	(29,000,000)
Amortization:
Prior service costs	0	0	0	1,000,000
Regulatory asset	0		0
Net (gain)/loss	3,000,000	1,000,000	8,000,000	5,000,000
Net periodic pension cost (income)	2,000,000	1,000,000	5,000,000	3,000,000
Pension Plans | SOUTHERN POWER CO
Pension Plans and Postretirement Plans
Service cost	3,000,000		7,000,000
Interest cost	1,000,000		4,000,000
Expected return on plan assets	(3,000,000)		(8,000,000)
Amortization:
Prior service costs	0		0
Regulatory asset	0		0
Net (gain)/loss	0		1,000,000
Net periodic pension cost (income)	1,000,000		4,000,000
Pension Plans | SOUTHERN Co GAS
Pension Plans and Postretirement Plans
Service cost	8,000,000	6,000,000	24,000,000	17,000,000
Interest cost	10,000,000	10,000,000	29,000,000	30,000,000
Expected return on plan assets	(18,000,000)	(18,000,000)	(53,000,000)	(53,000,000)
Amortization:
Prior service costs	(1,000,000)	0	(2,000,000)	(1,000,000)
Regulatory asset	4,000,000		11,000,000
Net (gain)/loss	3,000,000	5,000,000	9,000,000	15,000,000
Net periodic pension cost (income)	6,000,000	3,000,000	18,000,000	8,000,000
Pension Plans | Southern Company
Pension Plans and Postretirement Plans
Service cost	90,000,000	73,000,000	269,000,000	220,000,000
Interest cost	116,000,000	114,000,000	348,000,000	341,000,000
Expected return on plan assets	(236,000,000)	(224,000,000)	(707,000,000)	(673,000,000)
Amortization:
Prior service costs	1,000,000	3,000,000	3,000,000	9,000,000
Regulatory asset	0		0
Net (gain)/loss	53,000,000	41,000,000	160,000,000	122,000,000
Net periodic pension cost (income)	24,000,000	7,000,000	73,000,000	19,000,000
Postretirement Benefits | ALABAMA POWER CO
Pension Plans and Postretirement Plans
Service cost	1,000,000	1,000,000	4,000,000	4,000,000
Interest cost	5,000,000	4,000,000	13,000,000	13,000,000
Expected return on plan assets	(7,000,000)	(5,000,000)	(20,000,000)	(19,000,000)
Amortization:
Prior service costs	1,000,000	1,000,000	3,000,000	3,000,000
Regulatory asset	0		0
Net (gain)/loss	0	0	1,000,000	1,000,000
Net periodic pension cost (income)	0	1,000,000	1,000,000	2,000,000
Postretirement Benefits | GEORGIA POWER CO
Pension Plans and Postretirement Plans
Service cost	2,000,000	2,000,000	5,000,000	5,000,000
Interest cost	7,000,000	6,000,000	21,000,000	21,000,000
Expected return on plan assets	(6,000,000)	(6,000,000)	(19,000,000)	(18,000,000)
Amortization:
Prior service costs	0	0	1,000,000	1,000,000
Regulatory asset	0		0
Net (gain)/loss	2,000,000	3,000,000	6,000,000	6,000,000
Net periodic pension cost (income)	5,000,000	5,000,000	14,000,000	15,000,000
Postretirement Benefits | GULF POWER CO
Pension Plans and Postretirement Plans
Service cost	0	0	1,000,000	1,000,000
Interest cost	1,000,000	1,000,000	2,000,000	2,000,000
Expected return on plan assets	0	0	(1,000,000)	(1,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0		0
Net (gain)/loss	0	0	0	0
Net periodic pension cost (income)	1,000,000	1,000,000	2,000,000	2,000,000
Postretirement Benefits | MISSISSIPPI POWER CO
Pension Plans and Postretirement Plans
Service cost	0	0	1,000,000	1,000,000
Interest cost	0	1,000,000	2,000,000	3,000,000
Expected return on plan assets	0	0	(1,000,000)	(1,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0		0
Net (gain)/loss	0	0	0	0
Net periodic pension cost (income)	0	1,000,000	2,000,000	3,000,000
Postretirement Benefits | SOUTHERN POWER CO
Pension Plans and Postretirement Plans
Service cost	1,000,000		1,000,000
Interest cost	0		0
Expected return on plan assets	0		0
Amortization:
Prior service costs	0		0
Regulatory asset	0		0
Net (gain)/loss	0		0
Net periodic pension cost (income)	1,000,000		1,000,000
Postretirement Benefits | SOUTHERN Co GAS
Pension Plans and Postretirement Plans
Service cost	0	1,000,000	1,000,000	2,000,000
Interest cost	2,000,000	3,000,000	7,000,000	8,000,000
Expected return on plan assets	(1,000,000)	(2,000,000)	(5,000,000)	(5,000,000)
Amortization:
Prior service costs	0	(1,000,000)	0	(2,000,000)
Regulatory asset	2,000,000		5,000,000
Net (gain)/loss	0	1,000,000	0	3,000,000
Net periodic pension cost (income)	3,000,000	2,000,000	8,000,000	6,000,000
Postretirement Benefits | Southern Company
Pension Plans and Postretirement Plans
Service cost	6,000,000	6,000,000	18,000,000	18,000,000
Interest cost	19,000,000	19,000,000	56,000,000	59,000,000
Expected return on plan assets	(17,000,000)	(16,000,000)	(51,000,000)	(49,000,000)
Amortization:
Prior service costs	2,000,000	2,000,000	5,000,000	5,000,000
Regulatory asset	0		0
Net (gain)/loss	3,000,000	3,000,000	10,000,000	10,000,000
Net periodic pension cost (income)	$ 13,000,000	$ 14,000,000	$ 38,000,000	$ 43,000,000

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Income Taxes - Narrative (Details)		1 Months Ended	3 Months Ended				6 Months Ended	9 Months Ended		12 Months Ended
	Apr. 03, 2018	Sep. 30, 2018 USD ($)	Dec. 31, 2018 operating_facility	Sep. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Jun. 30, 2018 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2019	Dec. 31, 2017 USD ($)
Income Tax Contingency [Line Items]
Valuation allowances		$ 190,000,000		$ 190,000,000				$ 190,000,000			$ 148,000,000
Effective tax rate decrease								14.00%
Effective tax (benefit) rate								22.70%	42.60%
Increase in effective tax rate due to loss on Kemper IGCC									$ 3,100,000,000
Impairment charges				36,000,000		$ 0		$ 197,000,000	0
Income taxes benefit				(623,000,000)		(590,000,000)		(598,000,000)	$ (317,000,000)
Unrecognized tax benefits		0		0				$ 0
Significantly increase (decrease) in amount of unrecognized tax benefits								12 months
State
Income Tax Contingency [Line Items]
Valuation allowances		171,000,000		171,000,000				$ 171,000,000
ALABAMA POWER CO
Income Tax Contingency [Line Items]
Effective tax (benefit) rate								23.90%	39.90%
Income taxes benefit				(127,000,000)		(216,000,000)		$ (272,000,000)	$ (493,000,000)
GEORGIA POWER CO
Income Tax Contingency [Line Items]
Valuation allowances		39,000,000		39,000,000				$ 39,000,000
Effective tax (benefit) rate								25.50%	37.00%
Income taxes benefit				(262,000,000)		(350,000,000)		$ (212,000,000)	$ (705,000,000)
GEORGIA POWER CO | Plant Vogtle Units 3 And 4
Income Tax Contingency [Line Items]
Estimated project costs					$ 1,100,000,000
GEORGIA POWER CO | State
Income Tax Contingency [Line Items]
Valuation allowances		33,000,000		33,000,000				$ 33,000,000
Effective tax (benefit) rate	6.00%
GEORGIA POWER CO | Scenario, Forecast | State
Income Tax Contingency [Line Items]
Effective tax (benefit) rate										5.75%
GULF POWER CO
Income Tax Contingency [Line Items]
Effective tax (benefit) rate								(0.50%)	39.40%
Income taxes benefit				4,000,000		(40,000,000)		$ 1,000,000	$ (78,000,000)
MISSISSIPPI POWER CO
Income Tax Contingency [Line Items]
Valuation allowances		124,000,000		124,000,000				$ 124,000,000
Effective tax (benefit) rate								20.80%	(30.30%)
Increase in effective tax rate due to loss on Kemper IGCC								$ 3,100,000,000
Income taxes benefit				(14,000,000)		(24,000,000)		(23,000,000)	$ 885,000,000
MISSISSIPPI POWER CO | State
Income Tax Contingency [Line Items]
Valuation allowances		124,000,000		124,000,000				$ 124,000,000
SOUTHERN POWER CO
Income Tax Contingency [Line Items]
Effective tax (benefit) rate								(220.30%)	(66.50%)
Impairment charges				36,000,000		0		$ 155,000,000	$ 0
Income taxes benefit				38,000,000		39,000,000	$ 54,000,000	210,000,000	$ 129,000,000
SOUTHERN POWER CO | State
Income Tax Contingency [Line Items]
Income taxes benefit		11,000,000
SOUTHERN POWER CO | Scenario, Forecast
Income Tax Contingency [Line Items]
Number of operating wind facilities | operating_facility			8
SOUTHERN POWER CO | Florida Plants | Disposal Group, Held-for-sale, Not Discontinued Operations
Income Tax Contingency [Line Items]
Pre-tax impairment charge								119,000,000
Impairment charges								36,000,000
SOUTHERN Co GAS
Income Tax Contingency [Line Items]
Valuation allowances		12,000,000		12,000,000				$ 12,000,000
Effective tax (benefit) rate								61.80%	43.40%
Income taxes benefit				(316,000,000)		$ (52,000,000)		$ (475,000,000)	$ (233,000,000)
SOUTHERN Co GAS | State
Income Tax Contingency [Line Items]
Valuation allowances		1,000,000		1,000,000				1,000,000
Investment Tax Credit Carryforward
Income Tax Contingency [Line Items]
Tax credit carryforward, amount		$ 2,400,000,000		$ 2,400,000,000				$ 2,400,000,000			$ 2,100,000,000

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Income Taxes - Summary of Valuation Allowances (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Valuation Allowance [Line Items]
Valuation allowances	$ 190	$ 148
Federal
Valuation Allowance [Line Items]
Valuation allowances	19
State (net of federal benefit)
Valuation Allowance [Line Items]
Valuation allowances	171
GEORGIA POWER CO
Valuation Allowance [Line Items]
Valuation allowances	39
GEORGIA POWER CO | Federal
Valuation Allowance [Line Items]
Valuation allowances	6
GEORGIA POWER CO | State (net of federal benefit)
Valuation Allowance [Line Items]
Valuation allowances	33
MISSISSIPPI POWER CO
Valuation Allowance [Line Items]
Valuation allowances	124
MISSISSIPPI POWER CO | Federal
Valuation Allowance [Line Items]
Valuation allowances	0
MISSISSIPPI POWER CO | State (net of federal benefit)
Valuation Allowance [Line Items]
Valuation allowances	124
SOUTHERN Co GAS
Valuation Allowance [Line Items]
Valuation allowances	12
SOUTHERN Co GAS | Federal
Valuation Allowance [Line Items]
Valuation allowances	11
SOUTHERN Co GAS | State (net of federal benefit)
Valuation Allowance [Line Items]
Valuation allowances	$ 1

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Derivatives - Energy-Related and Interest Rate Derivatives (Details) MMBTU in Millions	9 Months Ended
	Sep. 30, 2018 USD ($) MMBTU
Energy-related, Natural Gas | ALABAMA POWER CO
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	82
Longest Hedge Date	2022
Energy-related, Natural Gas | GEORGIA POWER CO
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	165
Longest Hedge Date	2022
Energy-related, Natural Gas | GULF POWER CO
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	9
Longest Hedge Date	2020
Energy-related, Natural Gas | MISSISSIPPI POWER CO
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	69
Longest Hedge Date	2022
Energy-related, Natural Gas | SOUTHERN POWER CO
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	15
Longest Hedge Date	2020
Energy-related, Natural Gas | SOUTHERN Co GAS
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	255
Longest Hedge Date	2021
Longest Non-Hedge Date	2029
Energy-related, Natural Gas | SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Long
Energy-related derivative contracts
Derivative nonmonetary notional amount net long short position volume | MMBTU	4,300
Energy-related, Natural Gas | SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Short
Energy-related derivative contracts
Derivative nonmonetary notional amount net long short position volume | MMBTU	4,000
Energy-related, Natural Gas | Southern Company
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	595
Longest Hedge Date	2022
Longest Non-Hedge Date	2029
Interest rate derivatives
Interest rate derivatives
Notional Amount	$ 2,500,000,000
Fair Value Gain (Loss) at September 30, 2018	(72,000,000)
Interest rate derivatives | GEORGIA POWER CO | December 2018 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Notional Amount	$ 500,000,000
Interest Rate Received	1.95%
Fair Value Gain (Loss) at September 30, 2018	$ (3,000,000)
Interest rate derivatives | GEORGIA POWER CO | December 2019 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Notional Amount	$ 200,000,000
Interest Rate Received	4.25%
Fair Value Gain (Loss) at September 30, 2018	$ (3,000,000)
Interest rate derivatives | Southern Company | June 2020 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Notional Amount	$ 300,000,000
Interest Rate Received	2.75%
Fair Value Gain (Loss) at September 30, 2018	$ (6,000,000)
Interest rate derivatives | Southern Company | July 2021 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Notional Amount	$ 1,500,000,000
Interest Rate Received	2.35%
Fair Value Gain (Loss) at September 30, 2018	$ (60,000,000)
LIBOR | Interest rate derivatives | GEORGIA POWER CO | December 2018 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Weighted Average Interest Rate Paid	0.76%
LIBOR | Interest rate derivatives | GEORGIA POWER CO | December 2019 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Weighted Average Interest Rate Paid	2.46%
LIBOR | Interest rate derivatives | Southern Company | June 2020 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Weighted Average Interest Rate Paid	0.92%
LIBOR | Interest rate derivatives | Southern Company | July 2021 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Weighted Average Interest Rate Paid	0.87%

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Derivatives - Narrative (Details) MMBTU in Millions	9 Months Ended
	Sep. 30, 2018 USD ($) MMBTU	Dec. 31, 2017 USD ($)
Derivative [Line Items]
Collateral already posted, aggregate fair value | $	$ 189,000,000
ALABAMA POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	2
GEORGIA POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	4
Gulf Power and Mississippi Power
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	1
MISSISSIPPI POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	2
SOUTHERN POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	4
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]
Collateral already posted, aggregate fair value | $	$ 189,000,000	$ 193,000,000
Southern Company
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	13
Cash flow hedge gain (loss) to be reclassified within twelve months | $	$ (19,000,000)

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Derivatives - Foreign Currency Derivatives (Details) - 9 months ended Sep. 30, 2018 - Cash Flow Hedges of Existing 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 September 30, 2018	99
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 September 30, 2018	$ 48
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 September 30, 2018	$ 51

XML

Derivatives - Derivative Financial Statement Presentation and Amounts With Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Collateral already posted, aggregate fair value	$ 189
Southern Company
Derivatives, Fair Value [Line Items]
Derivatives, assets	543	$ 700
Derivatives, liabilities	668	794
Derivative asset, Gross amounts offset	(303)	(405)
Derivative liability, Gross amounts offset	(491)	(598)
Derivative asset	240	295
Derivative liability	177	196
Southern Company | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivatives, assets	397	550
Derivatives, liabilities	515	652
Southern Company | Derivatives not designated as hedging instruments | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	263	380
Southern Company | Derivatives not designated as hedging instruments | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	317	437
Southern Company | Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	134	170
Southern Company | Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	198	215
Southern Company | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives
Derivatives, Fair Value [Line Items]
Derivatives, assets	20	17
Derivatives, liabilities	51	67
Southern Company | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	15	10
Southern Company | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	17	43
Southern Company | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	5	7
Southern Company | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	26	24
Southern Company | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Assets held for sale, current
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Southern Company | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Liabilities held for sale, current
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	6	0
Southern Company | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Assets held for sale
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Southern Company | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Liabilities held for sale
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	2	0
Southern Company | 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	126	133
Derivatives, liabilities	102	75
Southern Company | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	3	3
Southern Company | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	6	14
Southern Company | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	0
Southern Company | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1	0
Southern Company | 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	1
Southern Company | 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	22	4
Southern Company | 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
Southern Company | 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	50	34
Southern Company | 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 Company | 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 Company | 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	122	129
Southern Company | 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	7	4
Derivatives, liabilities	10	10
Derivative asset, Gross amounts offset	(4)	(4)
Derivative liability, Gross amounts offset	(4)	(4)
Derivative asset	3	0
Derivative liability	6	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	7	4
Derivatives, liabilities	10	10
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	5	2
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	4	6
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	2
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	6	4
GEORGIA POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	7	6
Derivatives, liabilities	28	24
Derivative asset, Gross amounts offset	(7)	(6)
Derivative liability, Gross amounts offset	(7)	(6)
Derivative asset	0	0
Derivative liability	21	18
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	7	6
Derivatives, liabilities	22	19
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	5	2
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	9	9
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	4
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	13	10
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	6	5
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	5	4
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 deferred charges and 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 deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1	1
GULF POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Derivatives, liabilities	8	21
Derivative asset	0	0
Derivative liability	8	21
GULF 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	0	0
Derivatives, liabilities	8	21
GULF POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
GULF POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	6	14
GULF POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
GULF POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	2	7
MISSISSIPPI POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	3	3
Derivatives, liabilities	9	9
Derivative asset, Gross amounts offset	(3)	(2)
Derivative liability, Gross amounts offset	(3)	(2)
Derivative asset	0	1
Derivative liability	6	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	2
Derivatives, liabilities	9	9
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	1
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	3	6
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and 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 | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	6	3
MISSISSIPPI 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	1
Derivatives, liabilities	0	0
MISSISSIPPI 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	1
MISSISSIPPI 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	0	0
SOUTHERN POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	125	132
Derivatives, liabilities	30	36
Derivative asset, Gross amounts offset	(2)	(3)
Derivative liability, Gross amounts offset	(2)	(3)
Derivative asset	123	129
Derivative liability	28	33
SOUTHERN POWER CO | Derivatives not designated as hedging instruments | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
SOUTHERN POWER CO | Derivatives not designated as hedging instruments | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	2
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	125	132
Derivatives, liabilities	30	34
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	3
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	6	11
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	0
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1	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 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	122	129
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	400	554
Derivatives, liabilities	516	660
Derivative asset, Gross amounts offset	(287)	(390)
Derivative liability, Gross amounts offset	(475)	(583)
Derivative asset	113	164
Derivative liability	41	77
Collateral already posted, aggregate fair value	189	193
Weather derivative premium	5	11
SOUTHERN Co GAS | Energy-related derivatives
Derivatives, Fair Value [Line Items]
Collateral already posted, aggregate fair value	3	6
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives
Derivatives, Fair Value [Line Items]
Derivatives, assets	396	549
Derivatives, liabilities	514	649
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	134	170
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	198	215
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, assets	262	379
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	316	434
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives
Derivatives, Fair Value [Line Items]
Derivatives, assets	3	5
Derivatives, liabilities	2	8
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | 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 | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1	0
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, assets	3	5
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1	8
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	0
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	$ 0	$ 3

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Derivatives - Pre-tax Effects of Derivatives Designated as Cash Flow Hedging Instruments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Collateral already posted, aggregate fair value	$ 189		$ 189
Gain (Loss) Recognized in OCI on Derivative	(15)	$ 39	(26)	$ 86
SOUTHERN POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	(15)	40	(26)	93
SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Collateral already posted, aggregate fair value	189		189		$ 193
Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(29)		(29)		(44)
Gain (Loss) Recognized in OCI on Derivative	(5)	(6)	7	(26)
Energy-related derivatives | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(9)		(9)		(34)
Energy-related derivatives | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(20)		(20)		(18)
Energy-related derivatives | Assets held for sale, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(6)		(6)
Energy-related derivatives | Assets held for sale
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(2)		(2)
Energy-related derivatives | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	8		8		7
Energy-related derivatives | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)					1
Energy-related derivatives | ALABAMA POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(3)		(3)		(6)
Energy-related derivatives | ALABAMA POWER CO | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(2)		(2)		(4)
Energy-related derivatives | ALABAMA POWER CO | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(4)		(4)		(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		0
Energy-related derivatives | ALABAMA POWER CO | Assets held for sale
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0		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 | ALABAMA POWER CO | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)					1
Energy-related derivatives | GEORGIA POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(15)		(15)		(13)
Energy-related derivatives | GEORGIA POWER CO | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(4)		(4)		(7)
Energy-related derivatives | GEORGIA POWER CO | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(11)		(11)		(6)
Energy-related derivatives | GEORGIA POWER CO | Assets held for sale, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0		0
Energy-related derivatives | GEORGIA POWER CO | Assets held for sale
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0		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 | GEORGIA POWER CO | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)					0
Energy-related derivatives | GULF POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(8)		(8)		(21)
Energy-related derivatives | GULF POWER CO | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(6)		(6)		(14)
Energy-related derivatives | GULF POWER CO | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(2)		(2)		(7)
Energy-related derivatives | GULF POWER CO | Assets held for sale, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0		0
Energy-related derivatives | GULF POWER CO | Assets held for sale
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0		0
Energy-related derivatives | GULF POWER CO | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0		0		0
Energy-related derivatives | GULF POWER CO | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)					0
Energy-related derivatives | MISSISSIPPI POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(7)		(7)		(7)
Energy-related derivatives | MISSISSIPPI POWER CO | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(2)		(2)		(5)
Energy-related derivatives | MISSISSIPPI POWER CO | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(5)		(5)		(2)
Energy-related derivatives | MISSISSIPPI POWER CO | Assets held for sale, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0		0
Energy-related derivatives | MISSISSIPPI POWER CO | Assets held for sale
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0		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 | MISSISSIPPI POWER CO | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)					0
Energy-related derivatives | SOUTHERN POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	(5)	(6)	5	(21)
Energy-related derivatives | SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	4		4		3
Collateral already posted, aggregate fair value	3		3		6
Gain (Loss) Recognized in OCI on Derivative	0	0	2	(4)
Energy-related derivatives | SOUTHERN Co GAS | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(1)		(1)		(4)
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		0
Energy-related derivatives | SOUTHERN Co GAS | Assets held for sale
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0		0
Energy-related derivatives | SOUTHERN Co GAS | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	5		5		7
Energy-related derivatives | SOUTHERN Co GAS | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)					$ 0
Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	0	(1)	(2)	(2)
Foreign currency derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	(10)	46	(31)	114
Foreign currency derivatives | SOUTHERN POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	$ (10)	$ 46	$ (31)	$ 114

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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		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivative [Line Items]
Cost of natural gas	$ 104	$ 134	$ 1,053	$ 1,085
Gain (loss) recognized in income	(15)	39	(26)	86
Depreciation and amortization	787	767	2,338	2,236
Interest expense, net of amounts capitalized	(458)	(407)	(1,386)	(1,248)
Other income (expense), net	57	65	195	165
Energy-related derivatives
Derivative [Line Items]
Gain (loss) recognized in income	(5)	(6)	7	(26)
Interest rate derivatives
Derivative [Line Items]
Gain (loss) recognized in income	0	(1)	(2)	(2)
Foreign currency derivatives
Derivative [Line Items]
Gain (loss) recognized in income	(10)	46	(31)	114
Cash Flow Hedging | Energy-related derivatives | Cost of natural gas
Derivative [Line Items]
Gain (loss) recognized in income	0	0	(2)	0
Cash Flow Hedging | Energy-related derivatives | Depreciation and amortization
Derivative [Line Items]
Gain (loss) recognized in income	0	(6)	2	(12)
Cash Flow Hedging | Interest rate derivatives | Interest expense, net of amounts capitalized
Derivative [Line Items]
Gain (loss) recognized in income	(5)	(5)	(16)	(15)
Cash Flow Hedging | Foreign currency derivatives | Interest expense, net of amounts capitalized
Derivative [Line Items]
Gain (loss) recognized in income	(6)	(5)	(18)	(17)
Cash Flow Hedging | Foreign currency derivatives | Other income (expense), net
Derivative [Line Items]
Gain (loss) recognized in income	(9)	43	(46)	139
Fair Value Hedging | Interest rate derivatives | Interest expense, net of amounts capitalized
Derivative [Line Items]
Gain (loss) recognized in income	(4)	(5)	(35)	(6)
ALABAMA POWER CO
Derivative [Line Items]
Depreciation and amortization	192	185	570	549
Interest expense, net of amounts capitalized	(82)	(76)	(240)	(229)
Other income (expense), net	9	10	24	35
ALABAMA POWER CO | Cash Flow Hedging | Interest rate derivatives | Interest expense, net of amounts capitalized
Derivative [Line Items]
Gain (loss) recognized in income	(1)	(2)	(4)	(5)
GEORGIA POWER CO
Derivative [Line Items]
Depreciation and amortization	232	225	690	669
Interest expense, net of amounts capitalized	(95)	(105)	(303)	(310)
Other income (expense), net	30	22	104	95
GEORGIA POWER CO | Cash Flow Hedging | Interest rate derivatives | Interest expense, net of amounts capitalized
Derivative [Line Items]
Gain (loss) recognized in income	(1)	(1)	(4)	(3)
GEORGIA POWER CO | Fair Value Hedging | Interest rate derivatives | Interest expense, net of amounts capitalized
Derivative [Line Items]
Gain (loss) recognized in income	0	0	(1)	(1)
MISSISSIPPI POWER CO
Derivative [Line Items]
Depreciation and amortization	42	39	126	120
Interest expense, net of amounts capitalized	(19)	13	(59)	(23)
Other income (expense), net	0	1	28	4
MISSISSIPPI POWER CO | Cash Flow Hedging | Interest rate derivatives | Interest expense, net of amounts capitalized
Derivative [Line Items]
Gain (loss) recognized in income	0	0	(1)	(1)
SOUTHERN POWER CO
Derivative [Line Items]
Gain (loss) recognized in income	(15)	40	(26)	93
Depreciation and amortization	130	131	370	379
Interest expense, net of amounts capitalized	(45)	(47)	(138)	(144)
Other income (expense), net	17	3	22	3
SOUTHERN POWER CO | Energy-related derivatives
Derivative [Line Items]
Gain (loss) recognized in income	(5)	(6)	5	(21)
SOUTHERN POWER CO | Foreign currency derivatives
Derivative [Line Items]
Gain (loss) recognized in income	(10)	46	(31)	114
SOUTHERN POWER CO | Cash Flow Hedging | Energy-related derivatives | Depreciation and amortization
Derivative [Line Items]
Gain (loss) recognized in income	0	(6)	2	(12)
SOUTHERN POWER CO | Cash Flow Hedging | Foreign currency derivatives | Interest expense, net of amounts capitalized
Derivative [Line Items]
Gain (loss) recognized in income	(6)	(5)	(18)	(17)
SOUTHERN POWER CO | Cash Flow Hedging | Foreign currency derivatives | Other income (expense), net
Derivative [Line Items]
Gain (loss) recognized in income	(9)	43	(46)	139
SOUTHERN Co GAS
Derivative [Line Items]
Cost of natural gas	104	134	1,053	1,085
Depreciation and amortization	119	125	374	370
Interest expense, net of amounts capitalized	(52)	(51)	(170)	(145)
Other income (expense), net	6	19	21	30
SOUTHERN Co GAS | Energy-related derivatives
Derivative [Line Items]
Gain (loss) recognized in income	0	0	2	(4)
SOUTHERN Co GAS | Cash Flow Hedging | Energy-related derivatives | Cost of natural gas
Derivative [Line Items]
Gain (loss) recognized in income	$ 0	$ 0	$ (2)	$ 0

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Derivatives - Cumulative Basis Adjustments for Fair Value Hedges (Details) - Fair Value Hedging - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Securities due within one year
Derivative [Line Items]
Carrying Amount of the Hedged Item	$ (499)	$ (746)
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	1	3
Securities due within one year | GEORGIA POWER CO
Derivative [Line Items]
Carrying Amount of the Hedged Item	(499)	(746)
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	1	3
Long-term debt
Derivative [Line Items]
Carrying Amount of the Hedged Item	(2,526)	(2,553)
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	65	35
Long-term debt | GEORGIA POWER CO
Derivative [Line Items]
Carrying Amount of the Hedged Item	(497)	(498)
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	$ 2	$ 1

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Derivatives - Pre-tax Effects of Derivatives Not Designated as Hedging (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, gain (loss) on derivative, net			$ (23)	$ 32
Weather Derivatives | Southern Company
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, gain (loss) on derivative, net	$ 0	$ 0	0	15
Derivatives not designated as hedging instruments | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	(34)	(15)	(74)	46
Derivatives not designated as hedging instruments | Energy-related derivatives | Natural gas revenues
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	(36)	(17)	(79)	48
Derivatives not designated as hedging instruments | Energy-related derivatives | Cost of natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	2	2	5	(2)
Derivatives not designated as hedging instruments | Energy-related derivatives | SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	(34)	(15)	(74)	46
Derivatives not designated as hedging instruments | Energy-related derivatives | SOUTHERN Co GAS | Natural gas revenues
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	(36)	(17)	(79)	48
Derivatives not designated as hedging instruments | Energy-related derivatives | SOUTHERN Co GAS | Cost of natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	$ 2	$ 2	$ 5	$ (2)

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Acquisitions and Dispositions - Southern Company (Details) - Scenario, Forecast - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Jun. 28, 2019
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stock purchase agreement, contract termination fees		$ 100
700 Universe, LLC | Minimum
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stock purchase agreement, contract termination fees		100
700 Universe, LLC | Maximum
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stock purchase agreement, contract termination fees		$ 200
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	$ 5,750
Amount of indebtedness assumed at closing	$ 1,300

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Acquisitions and Dispositions - Schedule of Business Acquisitions and Construction Projects (Details) - SOUTHERN POWER CO - MW	1 Months Ended		3 Months Ended		6 Months Ended
	Jul. 31, 2018	Mar. 31, 2018	Jun. 30, 2020	Dec. 31, 2019	Jun. 30, 2019	Sep. 30, 2018	Aug. 31, 2018	May 31, 2018	Jul. 31, 2017
Gaskell West 1
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)						20
PPA Contract Period		20 years
Gaskell West 1 | Gaskell West 1 | Common Class B
Business Acquisition [Line Items]
Southern Power Percentage Ownership						100.00%
Gaskell West 1 | Gaskell West 1 | Class B Membership Interest
Business Acquisition [Line Items]
Southern Power Percentage Ownership						100.00%
Cactus Flats
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)	148
Cactus Flats | Minimum
Business Acquisition [Line Items]
PPA Contract Period	12 years
Cactus Flats | Maximum
Business Acquisition [Line Items]
PPA Contract Period	15 years
Cactus Flats | Cactus Flats
Business Acquisition [Line Items]
Southern Power Percentage Ownership									100.00%
Cactus Flats | Cactus Flats | Class B Membership Interest
Business Acquisition [Line Items]
Southern Power Percentage Ownership							100.00%
Mankato | Scenario, Forecast
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)					385
PPA Contract Period					20 years
Wild Horse Mountain | Scenario, Forecast
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)				100
PPA Contract Period				20 years
Wild Horse Mountain | Wild Horse Mountain
Business Acquisition [Line Items]
Southern Power Percentage Ownership								100.00%
Wild Horse Mountain | Wild Horse Mountain | Class B Membership Interest
Business Acquisition [Line Items]
Southern Power Percentage Ownership								100.00%
Reading | Scenario, Forecast
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)			200
PPA Contract Period			12 years
Reading | Reading
Business Acquisition [Line Items]
Southern Power Percentage Ownership							100.00%
Reading | Reading | Class B Membership Interest
Business Acquisition [Line Items]
Southern Power Percentage Ownership							100.00%

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Acquisitions and Dispositions - Southern Power Narrative (Details)	1 Months Ended	2 Months Ended	3 Months Ended			8 Months Ended	9 Months Ended		12 Months Ended	36 Months Ended
	May 31, 2018 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2018 USD ($) operating_facility	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Jun. 30, 2019 USD ($) MW	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2017 USD ($)
Business Acquisition [Line Items]
Construction work in progress				$ 7,655,000,000			$ 7,655,000,000				$ 6,904,000,000
Impairment charges				36,000,000	$ 0		197,000,000	$ 0
Increase (decrease) due to sale of noncontrolling interests							1,280,000,000
Assets subject to lien				111,717,000,000			111,717,000,000				111,005,000,000
Common Stockholders' Equity
Business Acquisition [Line Items]
Increase (decrease) due to sale of noncontrolling interests							(410,000,000)
SOUTHERN POWER CO
Business Acquisition [Line Items]
Construction work in progress				586,000,000			586,000,000				511,000,000
Impairment charges				36,000,000	$ 0		155,000,000	0
Repayments of debt	$ 770,000,000
Repayments of capital	250,000,000						650,000,000	$ 0
Increase (decrease) due to sale of noncontrolling interests	511,000,000
Assets subject to lien				15,355,000,000			15,355,000,000				$ 15,206,000,000
SOUTHERN POWER CO | Scenario, Forecast
Business Acquisition [Line Items]
Number of operating wind facilities | operating_facility			8
SOUTHERN POWER CO | Common Stockholders' Equity
Business Acquisition [Line Items]
Increase (decrease) due to sale of noncontrolling interests							(410,000,000)
SOUTHERN POWER CO | Disposal Group, Held-for-sale, Not Discontinued Operations | Florida Plants
Business Acquisition [Line Items]
Impairment charges							36,000,000
Proceeds from sale of equity method investments	195,000,000
Decrease in consideration per day between end of fiscal year and closing	110,000
Increase in consideration per day if closing is prior to end of fiscal year	$ 110,000
Pre-tax impairment charge							119,000,000
After tax impairment charge							89,000,000
SOUTHERN POWER CO | Wind Generating Facility
Business Acquisition [Line Items]
Impairment charges				36,000,000			155,000,000
SOUTHERN POWER CO | Wind Generating Facility | Scenario, Forecast
Business Acquisition [Line Items]
Project qualification for production tax credits, percentage									80.00%	100.00%
SOUTHERN POWER CO | SP Solar Holdings I, LP
Business Acquisition [Line Items]
Limited liability company or limited partnership, members or limited partners, ownership interest	33.00%
Proceeds from sale of equity method investments	$ 1,200,000,000
SOUTHERN POWER CO | Series of Construction Projects
Business Acquisition [Line Items]
Construction work in progress				246,000,000			246,000,000
SOUTHERN POWER CO | Series of Construction Projects | Minimum
Business Acquisition [Line Items]
Estimated future construction payments				575,000,000			575,000,000
SOUTHERN POWER CO | Series of Construction Projects | Maximum
Business Acquisition [Line Items]
Estimated future construction payments				640,000,000			640,000,000
SOUTHERN POWER CO | Plant Mankato | Senior Lien
Business Acquisition [Line Items]
Assets subject to lien				$ 500,000,000			$ 500,000,000
SOUTHERN POWER CO | Plant Mankato | Scenario, Forecast
Business Acquisition [Line Items]
Expansion currently under construction (MW) | MW						385
Tax Equity Funding | SOUTHERN POWER CO | Scenario, Forecast
Business Acquisition [Line Items]
Repayments of capital		$ 1,000,000,000
Tax equity funding		$ 1,200,000,000	$ 1,200,000,000
Subsequent Event | SOUTHERN POWER CO | Disposal Group, Held-for-sale, Not Discontinued Operations | Plant Mankato | Scenario, Forecast
Business Acquisition [Line Items]
Proceeds from sale of equity method investments						$ 650,000,000
Decrease per day after June 1, 2019						66,667
Maximum price decrease						$ 15,000,000
Subsequent Event | SOUTHERN POWER CO | Plant Mankato | Scenario, Forecast
Business Acquisition [Line Items]
Expansion currently under construction (MW) | MW						385

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Acquisitions and Dispositions - Southern Company Gas (Details) $ in Millions				3 Months Ended			9 Months Ended
	Jul. 29, 2018 USD ($)	Jul. 01, 2018 USD ($) utility	Jun. 04, 2018 USD ($)	Sep. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Jul. 31, 2018 utility
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Goodwill impairment							$ 42
Gain on disposition of business							324	$ 22
SOUTHERN Co GAS
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Goodwill impairment				$ 0	$ 42	$ 0	42	$ 0
SOUTHERN Co GAS | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of natural gas distribution utilities disposed | utility									3
SOUTHERN Co GAS | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Pivotal Home Solutions
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash purchase price on sale of business			$ 365
Gain (loss) on disposition of business, after tax			(73)
Tax on gain (loss) on disposition of business			$ 39
Goodwill impairment					$ 42		$ 42
SOUTHERN Co GAS | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Elizabethtown Gas and Elkton Gas
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash purchase price on sale of business		$ 1,700
Gain (loss) on disposition of business, after tax		$ 18
Number of natural gas distribution utilities disposed | utility		2
Working capital adjustment		$ 40
Gain on disposition of business		$ 230
SOUTHERN Co GAS | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Florida City Gas
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash purchase price on sale of business	$ 530
Gain (loss) on disposition of business, after tax	20
Gain on disposition of business	121
Long-term debt	3
Additional cash amount	$ 60

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Acquisitions and Dispositions - Held for Sale (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Assets Held for Sale:
Current assets	$ 407	$ 12
Liabilities Held for Sale:
Current liabilities	355	0
Other non-current liabilities	2,835	0
SOUTHERN POWER CO
Assets Held for Sale:
Current assets	18	1
Liabilities Held for Sale:
Current liabilities	4	$ 0
Disposal Group, Held-for-sale, Not Discontinued Operations
Assets Held for Sale:
Current assets	407
Total property, plant, and equipment	4,093
Other non-current assets	574
Total Assets Held for Sale	5,074
Liabilities Held for Sale:
Current liabilities	355
Long-term debt	1,285
Accumulated deferred income taxes	542
Other non-current liabilities	1,008
Total Liabilities Held for Sale	3,190
Disposal Group, Held-for-sale, Not Discontinued Operations | SOUTHERN POWER CO
Assets Held for Sale:
Current assets	18
Total property, plant, and equipment	168
Other non-current assets	17
Total Assets Held for Sale	203
Liabilities Held for Sale:
Current liabilities	4
Long-term debt	0
Accumulated deferred income taxes	0
Other non-current liabilities	0
Total Liabilities Held for Sale	$ 4

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Acquisitions and Dispositions - Pre-tax Profit (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
GULF POWER CO
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Earnings before income taxes	$ 59	$ 103	$ 146	$ 199
SOUTHERN POWER CO | Florida Plants
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Earnings before income taxes	$ 18	$ 11	$ 40	$ 28

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Variable Interest Entity and Equity Method Investments - Narrative (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	May 31, 2018	Sep. 30, 2018
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%
SP Solar Holdings I, LP | SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Limited liability company or limited partnership, members or limited partners, ownership interest	33.00%
SP Solar Holdings I, LP | Wholly Owned Subsidiary Of Southern Power | SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Ownership interest	66.00%
SP Solar Holdings I, LP | Variable Interest Entity, Primary Beneficiary | SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Assets		$ 6,400
Liabilities		111
Noncontrolling interests related to other partners' interests		$ 1,200
SP Solar Holdings I, LP | General Partner | Wholly Owned Subsidiary Of Southern Power | SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Ownership interest	1.00%

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Variable Interest Entity and Equity Method Investments - Balance Sheet Equity Method Investment Carrying Amount (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Investment Balance	$ 1,569	$ 1,513
SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Investment Balance	1,529	1,477
SOUTHERN Co GAS | SNG
Schedule of Equity Method Investments [Line Items]
Investment Balance	1,260	1,262
SOUTHERN Co GAS | Atlantic Coast Pipeline
Schedule of Equity Method Investments [Line Items]
Investment Balance	73	41
SOUTHERN Co GAS | PennEast Pipeline
Schedule of Equity Method Investments [Line Items]
Investment Balance	70	57
SOUTHERN Co GAS | Other
Schedule of Equity Method Investments [Line Items]
Investment Balance	$ 126	$ 117

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Variable Interest Entity and Equity Method Investments - Income Statement Equity Method Investment Carrying Amount (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	$ 36	$ 32	$ 108	$ 100
SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	34	32	108	100
SOUTHERN Co GAS | SNG
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	29	28	95	86
SOUTHERN Co GAS | PennEast Pipeline
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	2	1	4	5
SOUTHERN Co GAS | Atlantic Coast Pipeline
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	1	1	4	4
SOUTHERN Co GAS | Other
Schedule of Equity Method Investments [Line Items]
Earnings from Equity Method Investments	$ 2	$ 2	$ 5	$ 5

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Variable Interest Entity and Equity Method Investments - Investment in SNG (Details) - SNG - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Statement Information
Revenues	$ 145	$ 146	$ 451	$ 445
Operating income	71	71	230	218
Net income	$ 58	$ 57	$ 190	$ 172

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Segment and Related Information - Narrative (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018 USD ($) state	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($) state segment	Sep. 30, 2017 USD ($)	Jul. 31, 2018 utility
Segment Reporting Information [Line Items]
Number of reportable segments | segment			4
Number of states in which entity operates | state	4		4
Total operating revenues	$ 6,159	$ 6,201	$ 18,158	$ 17,403
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Number of reportable segments | segment			4
Number of states in which entity operates | state	7		7
Total operating revenues	$ 492	565	$ 2,861	2,841
SOUTHERN Co GAS | Traditional Electric Operating Companies
Segment Reporting Information [Line Items]
Natural gas revenues	14	9	22	19
SOUTHERN Co GAS | Southern Company
Segment Reporting Information [Line Items]
Natural gas revenues	38	38	96	94
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
SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Total operating revenues	635	618	1,699	1,597
SOUTHERN POWER CO | Wholesale revenues, affiliates
Segment Reporting Information [Line Items]
Total operating revenues	$ 134	$ 105	$ 326	$ 295

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Segment and Related Information - Financial Data for Business Segments (Details) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2018 USD ($) utility	Mar. 31, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($) utility	Sep. 30, 2017 USD ($)	Jul. 31, 2018 utility	Dec. 31, 2017 USD ($)
Segment Reporting Information [Line Items]
Operating revenues	$ 6,159		$ 6,201	$ 18,158	$ 17,403
Segment net income (loss)	1,164		1,069	1,948	347
Goodwill	5,315			5,315			$ 6,268
Total assets	111,717			111,717			111,005
Pre-tax impairment charges	36		0	197	0
Net gain (loss) on dispositions	353		0	317	19
Goodwill impairment				42
Plant Scherer Unit 3
Segment Reporting Information [Line Items]
Loss on Plant Scherer Unit 3					33
After tax charge to income					20
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	1		34	1,100	3,200
Public utilities, property, plant and equipment, amount of loss (recovery) on plant abandonment after tax	1		21	800	2,200
SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Operating revenues	635		618	1,699	1,597
Segment net income (loss)	92		124	235	276
Total assets	15,355			15,355			15,206
Pre-tax impairment charges	36		0	155	0
SOUTHERN POWER CO | Wind Generating Facility
Segment Reporting Information [Line Items]
Pre-tax impairment charges	36			155
After tax impairment charges	27			116
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	492		565	2,861	2,841
Segment net income (loss)	46		15	294	303
Goodwill	5,015			5,015			5,967
Total assets	20,398			20,398			22,987
Net gain (loss) on dispositions	353		0	317	0
Goodwill impairment	0	$ 42	0	42	0
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
SOUTHERN Co GAS | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Pivotal Home Solutions
Segment Reporting Information [Line Items]
Net gain (loss) on dispositions	353			317
Net gain (loss) on dispositions, net of tax	40			(35)
Goodwill impairment		$ 42		42
Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	5,509		5,523	14,456	14,239
Segment net income (loss)	1,240		1,132	1,946	276
Goodwill	2			2			2
Total assets	90,102			90,102			87,085
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	492		565	2,861	2,841
Gas Distribution Operations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Goodwill	4,034			4,034			4,702
Net gain (loss) on dispositions	351			351
Net gain (loss) on dispositions, net of tax	38			38
Goodwill impairment				0
Gas Marketing Services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Goodwill	981			981			1,265
Net gain (loss) on dispositions	2			(34)
Net gain (loss) on dispositions, net of tax	2			(73)
Goodwill impairment				42
Operating Segments | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	497		607	2,902	3,000
Segment net income (loss)	64		44	338	325
Total assets	21,524			21,524			24,842
Operating Segments | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	492		565	2,861	2,841
Segment net income (loss)	46		15	294	303
Goodwill	5,015			5,015			5,967
Total assets	20,398			20,398			22,987
Operating Segments | Gas Distribution Operations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	441		472	2,297	2,255
Segment net income (loss)	74		52	290	223
Total assets	16,850			16,850			19,358
Revenue on disposition	$ 8		50
Net income on disposition				$ 245	274
Operating Segments | Gas Distribution Operations | 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
Operating Segments | Gas Marketing Services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	$ 44		143	$ 403	597
Segment net income (loss)	(8)		1	(71)	36
Total assets	1,522			1,522			2,147
Revenue on disposition			32
Net income on disposition				55	95
Operating Segments | Wholesale Gas Services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	(8)		(24)	142	95
Segment net income (loss)	(18)		(23)	65	28
Total assets	855			855			1,096
Less Gross Gas Costs	1,663		1,538	5,057	5,048
Operating Segments | Gas Midstream Operations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	20		16	60	53
Segment net income (loss)	16		14	54	38
Total assets	2,297			2,297			2,241
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues	202		153	984	442
Segment net income (loss)	(119)		(80)	(292)	(232)
Goodwill	298			298			299
Total assets	3,086			3,086			2,552
Operating Segments | All Other | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	1		2	3	7
Segment net income (loss)	(18)		(29)	(44)	(22)
Total assets	10,146			10,146			12,184
Operating Segments | Third Party Gross Revenues | Wholesale Gas Services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	1,573		1,411	4,847	4,781
Operating Segments | Intercompany Revenues | Wholesale Gas Services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	82		103	352	362
Operating Segments | Total Gross Revenues | Wholesale Gas Services | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	1,655		1,514	5,199	5,143
Eliminations
Segment Reporting Information [Line Items]
Operating revenues	(44)		(40)	(143)	(119)
Segment net income (loss)	(3)		2	0	0
Goodwill	0			0			0
Total assets	(1,869)			(1,869)			(1,619)
Eliminations | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	(6)		(44)	(44)	(166)
Segment net income (loss)	0		0	0	0
Total assets	(11,272)			(11,272)			(14,039)
Reportable Subsegments | Traditional Electric Operating Companies | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	5,014		5,017	13,117	12,960
Segment net income (loss)	1,148		1,008	1,711	0
Goodwill	0			0			0
Total assets	75,069			75,069			72,204
Reportable Subsegments | SOUTHERN POWER CO | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	635		618	1,699	1,597
Segment net income (loss)	92		124	235	276
Goodwill	2			2			2
Total assets	15,355			15,355			15,206
Intersubsegment Eliminations | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	(140)		(112)	(360)	(318)
Segment net income (loss)	0		$ 0	0	$ 0
Goodwill	0			0			0
Total assets	$ (322)			$ (322)			$ (325)

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Segment and Related Information - Financial Data for Products and Services (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenue from External Customer [Line Items]
Total operating revenues	$ 6,159	$ 6,201	$ 18,158	$ 17,403
Retail
Revenue from External Customer [Line Items]
Total operating revenues	4,605	4,615	11,913	11,786
Electric Utilities' Revenues
Revenue from External Customer [Line Items]
Total operating revenues	5,509	5,523	14,456	14,239
Electric Utilities' Revenues | Retail
Revenue from External Customer [Line Items]
Total operating revenues	4,605	4,615	11,913	11,786
Electric Utilities' Revenues | Wholesale
Revenue from External Customer [Line Items]
Total operating revenues	693	718	1,923	1,867
Electric Utilities' Revenues | Other
Revenue from External Customer [Line Items]
Total operating revenues	211	190	620	586
Southern Company Gas' Revenues
Revenue from External Customer [Line Items]
Total operating revenues	492	565	2,861	2,841
Southern Company Gas' Revenues | Gas Distribution Operations
Revenue from External Customer [Line Items]
Total operating revenues	438	430	2,276	2,119
Southern Company Gas' Revenues | Gas Marketing Services
Revenue from External Customer [Line Items]
Total operating revenues	44	143	403	597
Southern Company Gas' Revenues | Other
Revenue from External Customer [Line Items]
Total operating revenues	$ 10	$ (8)	$ 182	$ 125