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, 2017

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 and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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. (Check one):

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, 2017
The Southern Company	Par Value $5 Per Share	1,003,627,691
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, 2017

		Page Number
DEFINITIONS		5
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION		8
	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	11
	Condensed Consolidated Statements of Comprehensive Income	12
	Condensed Consolidated Statements of Cash Flows	13
	Condensed Consolidated Balance Sheets	14
	Management's Discussion and Analysis of Financial Condition and Results of Operations	16
	Alabama Power Company
	Condensed Statements of Income	57
	Condensed Statements of Comprehensive Income	57
	Condensed Statements of Cash Flows	58
	Condensed Balance Sheets	59
	Management's Discussion and Analysis of Financial Condition and Results of Operations	61
	Georgia Power Company
	Condensed Statements of Income	75
	Condensed Statements of Comprehensive Income	75
	Condensed Statements of Cash Flows	76
	Condensed Balance Sheets	77
	Management's Discussion and Analysis of Financial Condition and Results of Operations	79
	Gulf Power Company
	Condensed Statements of Income	101
	Condensed Statements of Comprehensive Income	101
	Condensed Statements of Cash Flows	102
	Condensed Balance Sheets	103
	Management's Discussion and Analysis of Financial Condition and Results of Operations	105
	Mississippi Power Company
	Condensed Statements of Income	120
	Condensed Statements of Comprehensive Income	120
	Condensed Statements of Cash Flows	121
	Condensed Balance Sheets	122
	Management's Discussion and Analysis of Financial Condition and Results of Operations	124
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	152
	Condensed Consolidated Statements of Comprehensive Income	152
	Condensed Consolidated Statements of Cash Flows	153
	Condensed Consolidated Balance Sheets	154
	Management's Discussion and Analysis of Financial Condition and Results of Operations	156

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q

September 30, 2017

		Page Number
	PART I—FINANCIAL INFORMATION (CONTINUED)
	Southern Company Gas and Subsidiary Companies
	Condensed Consolidated Statements of Income	171
	Condensed Consolidated Statements of Comprehensive Income	172
	Condensed Consolidated Statements of Cash Flows	173
	Condensed Consolidated Balance Sheets	174
	Management's Discussion and Analysis of Financial Condition and Results of Operations	176
	Notes to the Condensed Financial Statements	206
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	55
Item 4.	Controls and Procedures	55
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	279
Item 1A.	Risk Factors	279
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	282
	Signatures	286

4

DEFINITIONS

Term	Meaning
2012 MPSC CPCN Order	A detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC
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
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
Baseload Act	State of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of Mississippi
CCR	Coal combustion residuals
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 formerly known as South Mississippi Electric Power Association (SMEPA)
CPCN	Certificate of public convenience and necessity
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 Title XVII Loan Guarantee Program
EPA	U.S. Environmental Protection Agency
EPC Contractor	Westinghouse and its affiliate, WECTEC (formerly known as CB&I Stone & Webster, Inc.), formerly a subsidiary of The Shaw Group Inc. and Chicago Bridge & Iron Company N.V.; 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, 2016, as applicable
GAAP	U.S. generally accepted accounting principles
Georgia Power	Georgia Power Company
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

5

DEFINITIONS

(continued)

Term	Meaning
IGCC	Integrated coal gasification combined cycle
IIC	Intercompany interchange contract
Illinois Commission	Illinois Commerce Commission, the state regulatory agency for Nicor Gas
IRC	Internal Revenue Code of 1986, as amended
IRS	Internal Revenue Service
ITC	Investment tax credit
Kemper IGCC	Mississippi Power's IGCC project in Kemper County, Mississippi
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
MATS rule	Mercury and Air Toxics Standards rule
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
Mirror CWIP	A regulatory liability used by Mississippi Power to record customer refunds resulting from a 2015 Mississippi PSC order
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' seven natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, Elizabethtown Gas, Florida City Gas, Chattanooga Gas Company, and Elkton Gas)
NCCR	Georgia Power's Nuclear Construction Cost Recovery
New Jersey BPU	New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
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
Piedmont	Piedmont Natural Gas Company, Inc.
Pivotal Utility Holdings	Pivotal Utility Holdings, Inc., a wholly-owned subsidiary of Southern Company Gas, doing business as Elizabethtown Gas, Elkton Gas, and Florida City Gas
Plant Vogtle Units 3 and 4	Two new nuclear generating units under construction at Georgia Power's Plant Vogtle
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

6

DEFINITIONS

(continued)

Term	Meaning
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.
scrubber	Flue gas desulfurization system
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 system	Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), Southern Electric Generating Company, Southern Nuclear, SCS, Southern Communications Services, Inc., PowerSecure (as of May 9, 2016), and other subsidiaries
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company and its subsidiaries
SouthStar	SouthStar Energy Services, LLC
STRIDE	Atlanta Gas Light's Strategic Infrastructure Development and Enhancement program
Toshiba	Toshiba Corporation, parent company of Westinghouse
Toshiba Guarantee	Certain payment obligations of the EPC Contractor guaranteed by Toshiba
traditional electric operating companies	Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
Triton	Triton Container Investments, LLC
Virginia Commission	Virginia State Corporation Commission, the state regulatory agency for Virginia Natural Gas
Virginia Natural Gas	Virginia Natural Gas, Inc., a wholly-owned subsidiary of Southern Company Gas
Vogtle 3 and 4 Agreement	Agreement entered into with the EPC Contractor in 2008 by Georgia Power, acting for itself and as agent for the Vogtle Owners, 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, the Municipal Electric Authority of Georgia, 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
WACOG	Weighted average cost of gas
WECTEC	WECTEC Global Project Services Inc.
Westinghouse	Westinghouse Electric Company LLC

7

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, 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 acquisitions or dispositions, filings with state and federal regulatory authorities, federal 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," "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 regulating emissions, discharges, and disposal to air, water, and land, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, including potential tax reform legislation, as well as changes in application of existing laws and regulations;

• current and future litigation, 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;

• variations in demand for electricity and natural gas, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;

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

• limits on pipeline capacity;

• effects of inflation;

• the ability to control costs and avoid cost overruns during the development, construction, and operation of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, 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 (including additional costs to satisfy any operational parameters ultimately adopted by any PSC);

• the impact of any inability or other failure of Toshiba to perform its obligations under the Toshiba Guarantee, including any effect on the construction of Plant Vogtle Units 3 and 4;

• the ability to construct facilities in accordance with the requirements of permits and licenses, 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;

• legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;

8

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)

• actions related to cost recovery for the Kemper IGCC, including ongoing settlement discussions, Mississippi PSC review of the prudence of Kemper IGCC costs and approval of further permanent rate recovery plans, and related legal or regulatory proceedings;

• 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;

• 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 disposition by a wholly-owned subsidiary of Southern Company Gas of Elizabethtown Gas and Elkton Gas, 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, the possibility that costs related to the integration of Southern Company and Southern Company Gas will be greater than expected, the ability to retain and hire key personnel and maintain relationships with customers, suppliers, or other business partners, and the diversion of management time on integration-related issues;

• 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 terrorist incidents and the threat of terrorist incidents;

• 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;

• 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.

9

THE SOUTHERN COMPANY

AND SUBSIDIARY COMPANIES

10

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,
	2017			2016			2017			2016
	(in millions)						(in millions)
Operating Revenues:
Retail electric revenues	$	4,615		$	4,808		$	11,786		$	11,932
Wholesale electric revenues	718			613			1,867			1,455
Other electric revenues	168			181			510			529
Natural gas revenues	532			518			2,746			518
Other revenues	168			144			494			281
Total operating revenues	6,201			6,264			17,403			14,715
Operating Expenses:
Fuel	1,285			1,400			3,372			3,334
Purchased power	256			227			646			581
Cost of natural gas	134			133			1,085			133
Cost of other sales	90			84			293			161
Other operations and maintenance	1,287			1,411			3,918			3,616
Depreciation and amortization	767			695			2,236			1,805
Taxes other than income taxes	303			309			941			821
Estimated loss on Kemper IGCC	34			88			3,155			222
Total operating expenses	4,156			4,347			15,646			10,673
Operating Income	2,045			1,917			1,757			4,042
Other Income and (Expense):
Allowance for equity funds used during construction	18			52			133			150
Earnings from equity method investments	32			29			100			28
Interest expense, net of amounts capitalized	(407		)	(374		)	(1,248		)	(913		)
Other income (expense), net	11			(8		)	2			(66		)
Total other income and (expense)	(346		)	(301		)	(1,013		)	(801		)
Earnings Before Income Taxes	1,699			1,616			744			3,241
Income taxes	590			439			317			917
Consolidated Net Income	1,109			1,177			427			2,324
Less:
Dividends on preferred and preference stock of subsidiaries	10			11			32			34
Net income attributable to noncontrolling interests	30			27			48			39
Consolidated Net Income Attributable to    Southern Company	$	1,069		$	1,139		$	347		$	2,251
Common Stock Data:
Earnings per share —
Basic	$	1.07		$	1.18		$	0.35		$	2.40
Diluted	$	1.06		$	1.17		$	0.35		$	2.38
Average number of shares of common stock outstanding (in millions)
Basic	1,003			968			998			940
Diluted	1,010			975			1,005			945
Cash dividends paid per share of common stock	$	0.5800		$	0.5600		$	1.7200		$	1.6625

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

11

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,
	2017			2016		2017			2016
	(in millions)					(in millions)
Consolidated Net Income	$	1,109		$	1,177	$	427		$	2,324
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $15, $12, $32, and $(74), respectively	25			19		54			(118		)
Reclassification adjustment for amounts included in net income, net of tax of $(10), $2, $(36), and $13, respectively	(17		)	2		(59		)	20
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $2, and $2, respectively	1			1		3			3
Total other comprehensive income (loss)	9			22		(2		)	(95		)
Comprehensive Income	1,118			1,199		425			2,229
Less:
Dividends on preferred and preference stock of subsidiaries	10			11		32			34
Comprehensive income attributable to noncontrolling interests	30			27		48			39
Consolidated Comprehensive Income Attributable to    Southern Company	$	1,078		$	1,161	$	345		$	2,156

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 CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2017			2016
	(in millions)
Operating Activities:
Consolidated net income	$	427		$	2,324
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	2,564			2,109
Deferred income taxes	15			(22		)
Allowance for equity funds used during construction	(133		)	(150		)
Pension, postretirement, and other employee benefits	(64		)	(158		)
Settlement of asset retirement obligations	(137		)	(117		)
Hedge settlements	—			(236		)
Estimated loss on Kemper IGCC	3,148			222
Other, net	(8		)	(1		)
Changes in certain current assets and liabilities —
-Receivables	426			(458		)
-Fossil fuel for generation	59			204
-Natural gas for sale, net of temporary LIFO liquidation	—			(222		)
-Other current assets	(164		)	(112		)
-Accounts payable	(467		)	(9		)
-Accrued taxes	157			1,062
-Accrued compensation	(230		)	(122		)
-Retail fuel cost over recovery	(211		)	(106		)
-Other current liabilities	(129		)	88
Net cash provided from operating activities	5,253			4,296
Investing Activities:
Business acquisitions, net of cash acquired	(1,032		)	(9,513		)
Property additions	(5,242		)	(5,252		)
Investment in restricted cash	(16		)	(750		)
Distribution of restricted cash	33			746
Nuclear decommissioning trust fund purchases	(585		)	(838		)
Nuclear decommissioning trust fund sales	580			832
Cost of removal, net of salvage	(208		)	(155		)
Change in construction payables, net	120			(259		)
Investment in unconsolidated subsidiaries	(134		)	(1,421		)
Payments pursuant to LTSAs	(189		)	(125		)
Other investing activities	(14		)	95
Net cash used for investing activities	(6,687		)	(16,640		)
Financing Activities:
Increase (decrease) in notes payable, net	(515		)	655
Proceeds —
Long-term debt	4,068			14,091
Common stock	613			3,265
Preferred stock	250			—
Short-term borrowings	1,263			—
Redemptions and repurchases —
Long-term debt	(1,981		)	(2,405		)
Preferred and preference stock	(150		)	—
Short-term borrowings	(409		)	(475		)
Distributions to noncontrolling interests	(89		)	(22		)
Capital contributions from noncontrolling interests	79			367
Purchase of membership interests from noncontrolling interests	—			(129		)
Payment of common stock dividends	(1,716		)	(1,553		)
Other financing activities	(113		)	(185		)
Net cash provided from financing activities	1,300			13,609
Net Change in Cash and Cash Equivalents	(134		)	1,265
Cash and Cash Equivalents at Beginning of Period	1,975			1,404
Cash and Cash Equivalents at End of Period	$	1,841		$	2,669
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $72 and $94 capitalized for 2017 and 2016, respectively)	$	1,286		$	766
Income taxes, net	(187		)	(151		)
Noncash transactions — Accrued property additions at end of period	805			578

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 BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2017			At December 31, 2016
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,841		$	1,975
Receivables —
Customer accounts receivable	1,744			1,583
Energy marketing receivables	427			623
Unbilled revenues	595			706
Under recovered fuel clause revenues	62			—
Income taxes receivable, current	138			544
Other accounts and notes receivable	578			377
Accumulated provision for uncollectible accounts	(43		)	(43		)
Materials and supplies	1,499			1,462
Fossil fuel for generation	571			689
Natural gas for sale	631			631
Prepaid expenses	365			364
Other regulatory assets, current	585			581
Other current assets	209			230
Total current assets	9,202			9,722
Property, Plant, and Equipment:
In service	102,014			98,416
Less: Accumulated depreciation	31,164			29,852
Plant in service, net of depreciation	70,850			68,564
Nuclear fuel, at amortized cost	865			905
Construction work in progress	8,026			8,977
Total property, plant, and equipment	79,741			78,446
Other Property and Investments:
Goodwill	6,267			6,251
Equity investments in unconsolidated subsidiaries	1,637			1,549
Other intangible assets, net of amortization of $156 and $62 at September 30, 2017 and December 31, 2016, respectively	902			970
Nuclear decommissioning trusts, at fair value	1,783			1,606
Leveraged leases	788			774
Miscellaneous property and investments	236			270
Total other property and investments	11,613			11,420
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,318			1,629
Unamortized loss on reacquired debt	210			223
Other regulatory assets, deferred	6,718			6,851
Other deferred charges and assets	1,513			1,406
Total deferred charges and other assets	9,759			10,109
Total Assets	$	110,315		$	109,697

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)

Liabilities and Stockholders' Equity	At September 30, 2017			At December 31, 2016
	(in millions)
Current Liabilities:
Securities due within one year	$	3,505		$	2,587
Notes payable	2,579			2,241
Energy marketing trade payables	451			597
Accounts payable	2,353			2,228
Customer deposits	550			558
Accrued taxes —
Accrued income taxes	176			193
Unrecognized tax benefits	17			385
Other accrued taxes	690			667
Accrued interest	443			518
Accrued compensation	703			915
Asset retirement obligations, current	245			378
Acquisitions payable	—			489
Other regulatory liabilities, current	139			236
Other current liabilities	752			925
Total current liabilities	12,603			12,917
Long-term Debt	44,042			42,629
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	14,321			14,092
Accumulated deferred ITCs	2,290			2,228
Employee benefit obligations	2,139			2,299
Asset retirement obligations, deferred	4,356			4,136
Other cost of removal obligations	2,708			2,748
Other regulatory liabilities, deferred	449			476
Other deferred credits and liabilities	1,048			1,278
Total deferred credits and other liabilities	27,311			27,257
Total Liabilities	83,956			82,803
Redeemable Preferred Stock of Subsidiaries	361			118
Redeemable Noncontrolling Interests	59			164
Stockholders' Equity:
Common Stockholders' Equity:
Common stock, par value $5 per share —
Authorized — 1.5 billion shares
Issued — September 30, 2017: 1.0 billion shares
— December 31, 2016: 991 million shares
Treasury — September 30, 2017: 0.9 million shares
— December 31, 2016: 0.8 million shares
Par value	5,018			4,952
Paid-in capital	10,300			9,661
Treasury, at cost	(35		)	(31		)
Retained earnings	8,981			10,356
Accumulated other comprehensive loss	(182		)	(180		)
Total Common Stockholders' Equity	24,082			24,758
Preferred and Preference Stock of Subsidiaries	462			609
Noncontrolling Interests	1,395			1,245
Total Stockholders' Equity	25,939			26,612
Total Liabilities and Stockholders' Equity	$	110,315		$	109,697

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

15

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2017 vs. THIRD QUARTER 2016

AND

YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016

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 constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. Southern Company'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 herein for information regarding agreements entered into by a wholly-owned subsidiary of Southern Company Gas to sell two of its natural gas distribution utilities.

Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, electric and natural gas system reliability, execution of major construction projects, and earnings per share.

Construction Program

See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC," FUTURE EARNINGS POTENTIAL – "Construction Program," and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the construction program. For information about Southern Power's acquisitions and construction of renewable energy facilities, see Note (I) to the Condensed Financial Statements under "Southern Power" herein.

Kemper IGCC

On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC (Kemper IGCC Settlement Docket). The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.

On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future

16

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants).

While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.

Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($4.0 billion after tax) through September 30, 2017.

Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the Mississippi Public Utilities Staff (MPUS)), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.

As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.

For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Nuclear Construction

On March 29, 2017, the EPC Contractor for Plant Vogtle Units 3 and 4 filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the EPC Contractor (Interim Assessment Agreement), which the bankruptcy court approved on March 30, 2017. On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million.

Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into a services agreement (Services Agreement), which was 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. On July 27, 2017, the Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE and the Interim Assessment Agreement expired pursuant to its terms. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice. Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement (Bechtel Agreement) with Bechtel Power Corporation (Bechtel), whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4.

In the seventeenth Vogtle Construction Monitoring (VCM) report filed on August 31, 2017, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4, at an additional cost of approximately $1.41 billion, net of the Guarantee Settlement Agreement. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.

On September 28, 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. 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 (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's financial statements. The ultimate outcome of these matters cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Construction Program – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4, including Georgia Power's cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.

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 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(70)	(6.1)	$(1,904)	(84.6)

Consolidated net income attributable to Southern Company was $1.07 billion ($1.07 per share) for the third quarter 2017 compared to $1.14 billion ($1.18 per share) for the corresponding period in 2016. The decrease was primarily due to a decrease in retail electric revenues due to milder weather and lower customer usage, a decrease in tax benefits at Southern Power, and an increase in depreciation and amortization. These changes were partially offset by higher retail electric revenues resulting from increases in base rates and a decrease in operations and maintenance expenses.

Consolidated net income attributable to Southern Company was $347 million ($0.35 per share) for year-to-date 2017 compared to $2.3 billion ($2.40 per share) for the corresponding period in 2016. The decrease was primarily due to charges of $3.2 billion and $222 million for year-to-date 2017 and 2016, respectively, related to the Kemper IGCC at Mississippi Power. Also contributing to the change was an increase of $299 million in net income from Southern Company Gas reflecting the nine-month period in 2017 compared to the three-month period following the Merger closing on July 1, 2016, higher retail electric revenues resulting from increases in base rates, and increases in renewable energy sales at Southern Power, partially offset by a decrease in retail electric revenues due to milder weather and lower customer usage, higher interest expense, and an increase in depreciation and amortization.

See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC and Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information on the Merger.

Retail Electric Revenues

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(193)	(4.0)	$(146)	(1.2)

In the third quarter 2017, retail electric revenues were $4.6 billion compared to $4.8 billion for the corresponding period in 2016. For year-to-date 2017, retail electric revenues were $11.8 billion compared to $11.9 billion for the corresponding period in 2016.

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

	Third Quarter 2017					Year-to-Date 2017
	(in millions)			(% change)		(in millions)			(% change)
Retail electric – prior year	$	4,808				$	11,932
Estimated change resulting from –
Rates and pricing	138			2.9		338			2.8
Sales decline	(52		)	(1.1	)	(74		)	(0.6	)
Weather	(162		)	(3.4	)	(351		)	(2.9	)
Fuel and other cost recovery	(117		)	(2.4	)	(59		)	(0.5	)
Retail electric – current year	$	4,615		(4.0	)%	$	11,786		(1.2	)%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to a Rate RSE increase at Alabama Power effective

19

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

January 1, 2017, the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff at Georgia Power, and an increase in retail base revenues effective July 2017 and in environmental cost recovery effective November 2016 at Gulf 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 decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjusted residential KWH sales decreased 2.0% and 0.6% in the third quarter and year-to-date 2017, respectively, primarily due to decreased customer usage resulting from an increase in penetration of energy efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 1.4% and 1.1% in the third quarter and year-to-date 2017, respectively, primarily due to decreased customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth. Industrial KWH sales decreased 0.5% and 1.1% in the third quarter and year-to-date 2017, respectively, primarily in the paper sector, partially offset by increased sales in the primary metals and textile sectors. Despite a more stable dollar and improving global economy, the industrial sector remains constrained by economic policy uncertainty. Additionally, Hurricane Irma negatively impacted customer usage for all customer classes.

Fuel and other cost recovery revenues decreased $117 million and $59 million in the third quarter and year-to-date 2017, respectively, when compared to the corresponding periods in 2016 primarily due to lower energy sales resulting from milder weather and lower coal prices. 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 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$105	17.1	$412	28.3

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, Southern Company'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, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.

20

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the third quarter 2017, wholesale electric revenues were $718 million compared to $613 million for the corresponding period in 2016. This increase was primarily related to a $78 million increase in energy revenues and a $27 million increase in capacity revenues. For year-to-date 2017, wholesale electric revenues were $1.9 billion compared to $1.5 billion for the corresponding period in 2016. This increase was primarily related to a $354 million increase in energy revenues and a $58 million increase in capacity revenues. The increases in energy revenues primarily relate to Southern Power increases in renewable energy sales arising from new solar and wind facilities and non-PPA revenues from short-term sales. The increases in capacity revenues primarily resulted from PPAs related to new natural gas facilities and additional customer capacity requirements at Southern Power.

Other Electric Revenues

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(13)	(7.2)	$(19)	(3.6)

In the third quarter 2017, other electric revenues were $168 million compared to $181 million for the corresponding period in 2016. The decrease was primarily related to lower open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts at Georgia Power and rate adjustments at Alabama Power, and a decrease in solar application fee revenues at Georgia Power.

For year-to-date 2017, other electric revenues were $510 million compared to $529 million for the corresponding period in 2016. The decrease was primarily due to a $14 million adjustment in 2016 for customer temporary facilities services revenues and a $12 million decrease in open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts at Georgia Power, partially offset by a $10 million increase in outdoor lighting sales revenues primarily attributable to LED conversions at Georgia Power.

Natural Gas Revenues

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$14	2.7	$2,228	N/M

N/M - Not meaningful

Natural gas revenues represent sales from the natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. In the third quarter 2017, natural gas revenues were $532 million compared to $518 million for the corresponding period in 2016. This increase is primarily due to infrastructure replacement programs and increases in base rate revenues at Southern Company Gas.

For year-to-date 2017, natural gas revenues were $2.7 billion compared to $518 million for the corresponding period in 2016. The increase reflects the inclusion of Southern Company Gas results for the nine-month period in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016.

See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.

Other Revenues

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$24	16.7	$213	75.8

In the third quarter 2017, other revenues were $168 million compared to $144 million for the corresponding period in 2016. For year-to-date 2017, other revenues were $494 million compared to $281 million for the corresponding

21

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

period in 2016. These increases were primarily due to increases of $5 million and $135 million for the third quarter and year-to-date 2017, respectively, from products and services at PowerSecure, which was acquired on May 9, 2016, and $8 million and $70 million for the third quarter and year-to-date 2017, respectively, of revenues from gas marketing products and services at Southern Company Gas following the Merger. Additionally, revenues from certain non-regulated sales of products and services at the traditional electric operating companies increased $5 million and $13 million for the third quarter and year-to-date 2017, respectively, primarily due to additional third-party infrastructure services.

See Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information on the Merger and the acquisition of PowerSecure.

Fuel and Purchased Power Expenses

	Third Quarter 2017 vs. Third Quarter 2016				Year-to-Date 2017 vs. Year-to-Date 2016
	(change in millions)			(% change)	(change in millions)		(% change)
Fuel	$	(115	)	(8.2)	$	38	1.1
Purchased power	29			12.8	65		11.2
Total fuel and purchased power expenses	$	(86	)		$	103

In the third quarter 2017, total fuel and purchased power expenses were $1.5 billion compared to $1.6 billion for the corresponding period in 2016. The decrease was primarily the result of a $104 million net decrease in the volume of KWHs generated and purchased, partially offset by an $18 million net increase in the average cost of fuel and purchased power primarily due to higher natural gas prices.

For year-to-date 2017, total fuel and purchased power expenses were $4.0 billion compared to $3.9 billion for the corresponding period in 2016. The increase was primarily the result of a $277 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset by a $174 million decrease in the volume of KWHs generated and purchased.

Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Fuel Cost Recovery" herein for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.

22

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	Third Quarter 2017	Third Quarter 2016	Year-to-Date 2017	Year-to-Date 2016
Total generation (in billions of KWHs)	54	56	147	145
Total purchased power (in billions of KWHs)	6	6	14	15
Sources of generation (percent) —
Coal	31	38	30	33
Nuclear	15	15	16	16
Gas	47	44	46	46
Hydro	2	1	2	3
Other	5	2	6	2
Cost of fuel, generated (in cents per net KWH)—
Coal	2.82	2.97	2.82	3.10
Nuclear	0.80	0.81	0.80	0.82
Gas	2.92	2.74	2.93	2.40
Average cost of fuel, generated (in cents per net KWH)	2.54	2.54	2.51	2.38
Average cost of purchased power (in cents per net KWH)(*)	4.96	4.98	5.32	4.75

(*) 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 2017, fuel expense was $1.3 billion compared to $1.4 billion for the corresponding period in 2016. The decrease was primarily due to a 21.4% decrease in the volume of KWHs generated by coal and a 5.1% decrease in the average cost of coal per KWH generated, partially offset by a 6.6% increase in the average cost of natural gas per KWH generated and a 1.2% increase in the volume of KWHs generated by natural gas.

For year-to-date 2017, fuel expense was $3.4 billion compared to $3.3 billion for the corresponding period in 2016. The increase was primarily due to a 22.1% increase in the average cost of natural gas per KWH generated, partially offset by a 9.0% decrease in the average cost of coal per KWH generated, a 7.4% decrease in the volume of KWHs generated by coal, and a 3.7% decrease in the volume of KWHs generated by natural gas.

Purchased Power

In the third quarter 2017, purchased power expense was $256 million compared to $227 million for the corresponding period in 2016. The increase was primarily due to a 10.1% increase in the volume of KWHs purchased, partially offset by a 0.4% decrease in the average cost per KWH purchased.

For year-to-date 2017, purchased power expense was $646 million compared to $581 million for the corresponding period in 2016. The increase was primarily due to a 12.0% increase in the average cost per KWH purchased, primarily as a result of higher natural gas prices, partially offset by a 1.3% decrease in the volume of KWHs purchased.

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cost of Natural Gas

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$1	0.8	$952	N/M

N/M - Not meaningful

Cost of natural gas represents the cost of natural gas sold by the natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. In the third quarter 2017, cost of natural gas was $134 million compared to $133 million for the corresponding period in 2016. For year-to-date 2017, cost of natural gas was $1.1 billion compared to $133 million for the corresponding period in 2016. The year-to-date increase reflects the inclusion of Southern Company Gas results for the nine-month period in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016.

See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.

Cost of Other Sales

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$6	7.1	$132	82.0

In the third quarter 2017, cost of other sales was $90 million compared to $84 million for the corresponding period in 2016. For year-to-date 2017, cost of other sales was $293 million compared to $161 million for the corresponding period in 2016. The year-to-date increase primarily reflects costs related to sales of products and services by PowerSecure, which was acquired on May 9, 2016, and costs related to gas marketing products and services at Southern Company Gas following the Merger closing on July 1, 2016. See Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information.

Other Operations and Maintenance Expenses

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(124)	(8.8)	$302	8.4

In the third quarter 2017, other operations and maintenance expenses were $1.3 billion compared to $1.4 billion for the corresponding period in 2016. The decrease was primarily due to cost containment and modernization activities implemented at Georgia Power in the third quarter 2016 that contributed to decreases of $37 million in maintenance costs, $9 million in customer accounts, service, and sales costs, and $8 million in other employee compensation and benefits. Other factors include a $40 million decrease in acquisition-related expenses and a $31 million decrease in employee compensation and benefits including pension costs.

For year-to-date 2017, other operations and maintenance expenses were $3.9 billion compared to $3.6 billion for the corresponding period in 2016. The increase was primarily due to increases of $420 million and $32 million in operations and maintenance expenses as a result of the inclusion of Southern Company Gas and PowerSecure results for the nine-month period in 2017, respectively, a $48 million increase associated with new solar, wind, and gas facilities at Southern Power, and $32.5 million resulting from the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with a settlement agreement approved by the Florida PSC on April 4, 2017 (2017 Rate Case Settlement Agreement). These increases were partially offset due to cost containment and modernization activities implemented at Georgia Power in the third quarter 2016 that contributed to decreases of $79 million in maintenance costs and $34 million in other employee compensation and benefits. Other factors

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

include a $32 million decrease in acquisition-related expenses, a $25 million decrease in customer accounts, service, and sales costs primarily at Georgia Power, a $19 million increase in gains from sales of integrated transmission system assets at Georgia Power, and a $16 million decrease in scheduled outage and maintenance costs at generation facilities.

See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement and Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information related to the Merger and the acquisition of PowerSecure.

Depreciation and Amortization

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$72	10.4	$431	23.9

In the third quarter 2017, depreciation and amortization was $767 million compared to $695 million for the corresponding period in 2016. The increase is primarily related to additional plant in service at the traditional electric operating companies, Southern Power, and Southern Company Gas.

For year-to-date 2017, depreciation and amortization was $2.2 billion compared to $1.8 billion for the corresponding period in 2016. The increase reflects $254 million as a result of the inclusion of Southern Company Gas for the nine-month period in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016. Additionally, the increase reflects $170 million related to additional plant in service at the traditional electric operating companies and Southern Power. The increase was partially offset by a $34 million increase in the reductions in depreciation authorized in Gulf Power's 2013 rate case settlement approved by the Florida PSC as compared to the corresponding period in 2016.

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 and Notes (B) and (I) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" and "Southern Company – Merger with Southern Company Gas," respectively, herein for additional information.

Taxes Other Than Income Taxes

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(6)	(1.9)	$120	14.6

For year-to-date 2017, taxes other than income taxes were $941 million compared to $821 million for the corresponding period in 2016. The increase primarily reflects the inclusion of Southern Company Gas taxes for the nine-month period in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016.

See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.

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Estimated Loss on Kemper IGCC

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(54)	(61.4)	$2,933	N/M

N/M - Not meaningful

Estimated probable losses on the Kemper IGCC of $34 million and $3.2 billion were recorded at Mississippi Power in the third quarter and year-to-date 2017, respectively, compared to $88 million and $222 million in the third quarter and year-to-date 2016, respectively. While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable. As a result, Mississippi Power suspended the project on June 28, 2017, and recorded $34 million and $2.9 billion of additional charges to income in the third quarter and year-to-date 2017, respectively, for the estimated costs associated with the gasification portions of the plant and lignite mine.

Prior to the project's suspension, Mississippi Power recorded losses for revisions of estimated costs expected to be incurred on construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (construction cost increase demonstrated to produce efficiencies that result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions).

See FUTURE EARNINGS POTENTIAL – "Construction Program – Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Allowance for Equity Funds Used During Construction

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(34)	(65.4)	$(17)	(11.3)

In the third quarter 2017, AFUDC equity was $18 million compared to $52 million in the corresponding period in 2016. For year-to-date 2017, AFUDC equity was $133 million compared to $150 million in the corresponding period in 2016. These decreases primarily resulted from Mississippi Power's suspension of the Kemper IGCC project in June 2017.

See FUTURE EARNINGS POTENTIAL – "Construction Program – Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Earnings from Equity Method Investments

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$3	10.3	$72	N/M

N/M - Not meaningful

In the third quarter 2017, earnings from equity method investments were $32 million compared to $29 million in the corresponding period in 2016. For year-to-date 2017, earnings from equity method investments were $100 million

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compared to $28 million in the corresponding period in 2016. These increases were primarily related to Southern Company Gas' equity method investment in SNG in September 2016.

See Note 12 to the financial statements of Southern Company under "Southern Company – Investment in Southern Natural Gas" in Item 8 of the Form 10-K for additional information.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$33	8.8	$335	36.7

In the third quarter 2017, interest expense, net of amounts capitalized was $407 million compared to $374 million in the corresponding period in 2016. The increase was primarily due to an increase in average outstanding long-term debt and a $16 million decrease in interest capitalized, partially offset by a net reduction of $33 million following Mississippi Power's settlement with the IRS related to research and experimental (R&E) deductions.

For year-to-date 2017, interest expense, net of amounts capitalized was $1.2 billion compared to $913 million in the corresponding period in 2016. The increase was primarily due to an increase in average outstanding long-term debt and a $31 million decrease in interest capitalized, partially offset by a net reduction of $33 million following Mississippi Power's settlement with the IRS related to R&E deductions. In addition, year-to-date 2017 includes an additional $106 million reflecting the nine-month period of interest expense for Southern Company Gas compared to the three-month period subsequent to the Merger closing on July 1, 2016.

See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Section 174 Research and Experimental Deduction" and Notes (E) and (G) to the Condensed Financial Statements herein for additional information.

Other Income (Expense), Net

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$19	N/M	$68	N/M

N/M - Not meaningful

In the third quarter 2017, other income (expense), net was $11 million compared to $(8) million for the corresponding period in 2016. For year-to-date 2017, other income (expense), net was $2 million compared to $(66) million for the corresponding period in 2016. These changes were primarily due to $14 million and $16 million from settlement of contractor litigation claims at Southern Company Gas in the third quarter and year-to-date 2017, respectively, and increases of $6 million and $10 million in customer contributions in aid of construction and contract service revenue at Georgia Power in the third quarter and year-to-date 2017, respectively. Additionally, the year-to-date change reflects $30 million of expenses incurred in 2016 associated with bridge financing for the Merger. These changes also include increases of $36 million and $152 million in currency losses arising from a translation of euro-denominated fixed-rate notes into U.S. dollars for the third quarter and year-to-date 2017, respectively, fully offset by an equal change in gains on the foreign currency hedges that were reclassified from accumulated OCI into earnings at Southern Power.

See Note (H) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for additional information.

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Income Taxes

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$151	34.4	$(600)	(65.4)

In the third quarter 2017, income taxes were $590 million compared to $439 million for the corresponding period in 2016. The increase was primarily due to a $61 million decrease in income tax benefits from solar ITCs at Southern Power, a $23 million increase in deferred income tax expenses associated with new State of Illinois tax legislation and new tax apportionment factors at Southern Company Gas, and a $21 million decrease in tax benefits related to estimated losses on the Kemper IGCC at Mississippi Power.

For year-to-date 2017, income taxes were $317 million compared to $917 million for the corresponding period in 2016. The decrease was primarily due to $866 million in tax benefits related to estimated losses on the Kemper IGCC at Mississippi Power, partially offset by a $226 million increase reflecting the nine-month period of income taxes at Southern Company Gas in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016 and a $44 million net decrease in tax benefits from renewable tax credits at Southern Power.

See Notes (B), (G), and (I) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle," "Effective Tax Rate," and "Southern Company – Merger with Southern Company Gas," respectively, herein for additional information.

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 a constructive regulatory environment that allows for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Matters related to Plant Vogtle Units 3 and 4 construction and rate recovery and the ability to recover costs for the remainder of the Kemper County energy facility not included in current rates are also major factors. In addition, the profitability of Southern Power's competitive wholesale business and successful additional investments in renewable and other energy projects are also major factors.

Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability or realizability of ITCs and PTCs, is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Southern Company's financial statements.

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 higher multi-family home construction. 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

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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.

Southern Power is considering the sale of up to a one-third equity interest in its solar asset portfolio. The ultimate outcome of this matter cannot be determined at this time.

On October 15, 2017, a wholly-owned subsidiary of Southern Company Gas entered into agreements for the sale 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. As of September 30, 2017, the net book value of the assets to be disposed of in the sale was approximately $1.5 billion, which includes approximately $0.5 billion of goodwill. The goodwill is not deductible for tax purposes and as a result, a deferred tax liability has not yet been provided for goodwill. Through the completion of the sale, Southern Company Gas intends to invest approximately $0.1 billion in capital expenditures which are required for ordinary business operations. The completion of each sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act; (ii) the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC; and (iii) other customary closing conditions. The sales are expected to be completed by the end of the third quarter 2018. 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 and RISK FACTORS in Item 1A herein.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations 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. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher 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. 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.

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Environmental Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's eight-hour ozone National Ambient Air Quality Standard (NAAQS).

On June 2, 2017, the EPA published a final rule redesignating a 15-county area within metropolitan Atlanta to attainment for the 2008 eight-hour ozone NAAQS.

On June 18, 2017, the EPA published a notice delaying attainment designations for the 2015 eight-hour ozone NAAQS by one year, setting a revised deadline of October 1, 2018. However, on August 2, 2017, the EPA issued a withdrawal notice of the one-year extension and reinstated the original October 1, 2017 designation deadline. The ultimate outcome of this matter cannot be determined at this time.

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the final effluent guidelines rule and the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.

On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.

On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.

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 Southern Company in Item 7 of the Form 10-K for additional information.

On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.

On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.

The ultimate outcome of these matters 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 (LDNR). 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, 2017, the facility's property, plant, and equipment had a net book value of $111 million, of which the cavern itself

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

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represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including the results of ongoing third-party technical engineering reviews, testing, and compliance with an order from the LDNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining a core sample to determine the composition of the sheath surrounding the edge of the salt dome. 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.

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 the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.

On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.

On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.

The ultimate outcome of these matters 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 and Note 4 to the financial statements of Southern Company in Item 8 of the Form 10-K for additional information regarding Southern Company Gas' pipeline projects.

On August 1, 2017, the Dalton Pipeline was placed in service as authorized by the FERC and transportation service for customers commenced.

On October 13, 2017, the Atlantic Coast Pipeline project received FERC approval.

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

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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.

Renewables

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Renewables" of Southern Company in Item 7 of the Form 10-K for additional information regarding the Southern Company system's renewables activity.

On May 16, 2017, the Georgia PSC approved Georgia Power's request to build, own, and operate a 139-MW solar generation facility at a U.S. Air Force base that is expected to be placed in service by the end of 2019.

During the nine months ended September 30, 2017, Georgia Power continued construction of a 31-MW solar generation facility at a U.S. Marine Corps base that is expected to be placed in service in the fourth quarter 2017.

In 2015, the Florida PSC approved Gulf Power's three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. Purchases under these agreements began in the summer of 2017.

Mississippi Power placed in service three solar projects in January, June, and October 2017. Mississippi Power may retire the renewable energy credits (REC) generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.

On August 17, 2017, the Mississippi PSC approved Mississippi Power's CPCN for the construction, operation, and maintenance of a 52.5-MW solar energy generating facility, which is expected to be placed in service by January 2020.

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

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 for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.

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 the construction 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 "Regulatory Matters – Georgia Power – Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – 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.

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Integrated Resource Plan

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Georgia Power – Integrated Resource Plan" of Southern Company in Item 7 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan.

On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at a future generation site in Stewart County, Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing of recovery for costs incurred of approximately $50 million will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.

Storm Damage Recovery

Georgia Power is accruing$30 millionannually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. During September 2017, Hurricane Irma caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of incremental restoration costs related to this hurricane is estimated to be approximately $150 million. As of September 30, 2017, Georgia Power had deferred approximately $145 million in a regulatory asset related to storm damage. As of September 30, 2017, the total balance in Georgia Power's regulatory asset related to storm damage was $360 million. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's financial statements. 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.

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 regarding Gulf Power's October 2016 request to the Florida PSC to increase retail base rates and Gulf Power's ownership of Plant Scherer Unit 3.

On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and three intervenors with respect to Gulf Power's request to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%) and is deemed to have an equity ratio of 52.5% for all retail regulatory purposes. Gulf Power will also begin amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and will implement new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.

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Southern Company Gas

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 revenues or net income, but will affect cash flows.

Base Rate Cases

On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase in December 2017, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.

Construction Program

Overview

The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding 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. Following Mississippi Power's suspension of the Kemper IGCC construction, 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). In August 2017, Georgia Power filed its seventeenth VCM report with the Georgia PSC, in which it recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4, at an additional cost of approximately $1.41 billion, net of the Guarantee Settlement Agreement. The Georgia PSC is expected to make a decision on these and other related matters by February 6, 2018. 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.

For additional information, see Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" and " – Southern Company Gas – Regulatory Infrastructure Programs" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters– Georgia Power – Nuclear Construction" and " – Southern Company Gas–Regulatory Infrastructure Programs" and "Integrated Coal Gasification Combined Cycle" herein. Also see Note 12 to the financial statements of Southern Company under "Southern Power – Construction Projects" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power" herein.

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.

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Integrated Coal Gasification Combined Cycle

The Kemper IGCC was approved by the Mississippi PSC in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of Initial DOE Grants and excluding the Cost Cap Exceptions. The combined cycle and associated common facilities portion of the Kemper IGCC were placed in service in August 2014.

In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation between Mississippi Power and the MPUS, authorizing rates that provide for the recovery of approximately $126 million annually related to the combined cycle and associated common facilities portion of Kemper IGCC assets previously placed in service. As required by the In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable. At September 30, 2017, the related regulatory liability totaled $7 million.

The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO₂, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has increased significantly since certification.

On June 21, 2017, the Mississippi PSC stated its intent to issue the Kemper Settlement Order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.

On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.

While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension,

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which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.

Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($4.0 billion after tax) through September 30, 2017.

Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the MPUS), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.

As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.

For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein. Also see "Litigation" herein.

Litigation

On April 26, 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 on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have 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 IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On June 23, 2017, the Circuit

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Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal.

On June 9, 2016, Treetop Midstream Services, LLC (Treetop) and other related parties filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO₂ contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO₂ contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop and other related parties filed a claim for arbitration requesting $500 million in damages.

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

Nuclear Construction

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

Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy

In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Georgia Power's proportionate share of Plant Vogtle Units 3 and 4 is 45.7%.

The Vogtle 3 and 4 Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed.

Under the terms of the Vogtle 3 and 4 Agreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the Vogtle 3 and 4 Agreement was 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest).

On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement, which the bankruptcy court approved on March 30, 2017.

The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided. The Interim Assessment Agreement, as amended, expired on July 27, 2017.

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Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through September 30, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which $340 million had been paid or accrued as of September 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $176 million.

On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion, of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, which will reduce CWIP, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million. Georgia Power is considering potential options with respect to its right to future payments under the Guarantee Settlement Agreement and its claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to DOE consents and related approvals under the Loan Guarantee Agreement and related agreements.

On August 10, 2017, Toshiba released its financial results for the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $4.5 billion as of June 30, 2017. Toshiba previously announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's financial statements.

Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Services Agreement, which was 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. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

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Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Bechtel Agreement, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4. Facility design and engineering remains the responsibility of the EPC Contractor under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a 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 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, 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 connection with the recommendation to continue with construction of Plant Vogtle Units 3 and 4 (described below), the Vogtle Owners agreed on a term sheet to amend the existing joint ownership agreements to provide for additional Vogtle Owner approval requirements. Under the 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 adverse events occur, including (i) the bankruptcy of Toshiba or a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) 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 because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report by more than $1 billion or extension of the project schedule contained in the seventeenth VCM report by more than one year. In addition, under the term sheet, 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 Services Agreement or agreements with the primary construction contractor or Southern Nuclear.

The term sheet also confirms 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.

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 nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. As of September 30, 2017, Georgia Power had recovered approximately $1.5 billion of financing costs. Georgia Power expects to file on November 1, 2017 to increase the NCCR tariff by approximately $90 million, effective January 1, 2018, pending Georgia PSC approval.

On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are

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incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not placed in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.

The Georgia PSC has approved sixteen VCM reports covering the periods through December 31, 2016, including construction capital costs incurred, which through that date totaled $3.9 billion. Georgia Power filed its seventeenth VCM report, covering the period from January 1 through June 30, 2017, requesting approval of $542 million of construction capital costs incurred during that period, with the Georgia PSC on August 31, 2017.

In the seventeenth VCM report, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4. Georgia Power's recommendation to go forward with completion of Vogtle Units 3 and 4 is based on the following assumptions about the regulatory treatment of this recommendation, if the recommendation to go forward is adopted by the Georgia PSC: (i) that pursuant to Georgia law, the Georgia PSC in the seventeenth VCM proceeding approves the new cost and schedule forecast and finds that it is a reasonable basis for going forward, and that if the Georgia PSC disapproves all or part of the proposed cost and schedule revisions, Georgia Power may cancel Plant Vogtle Units 3 and 4 and recover its actual investment in Plant Vogtle Units 3 and 4; (ii) that the Vogtle Cost Settlement Agreement remains in full force and effect, including Georgia Power retaining the burden of proving all capital costs above $5.680 billion were prudent; (iii) that while the Georgia PSC will make no prudence finding in the seventeenth VCM proceeding, nor will the certified amount be amended consistent with the Vogtle Cost Settlement Agreement, the Georgia PSC recognizes that the certified amount is not a cap, and all costs that are approved and presumed or shown to be prudently incurred will be recoverable by Georgia Power; (iv) that Georgia Power is not a guarantor of the Toshiba Guarantee, and the failure of Toshiba to pay the Toshiba Guarantee, the failure of the U.S. Congress to extend the PTCs for Plant Vogtle Units 3 and 4, or the failure of the DOE to extend the Loan Guarantee Agreement with Georgia Power to reflect the increased capital amounts, will not reduce the amount of investment Georgia Power is otherwise allowed to collect; and (v) that as conditions change and assumptions are either proven or disproven, Georgia Power and the Georgia PSC may reconsider the decision to go forward. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.

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

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Revised Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 is as follows:

	(in billions)
Estimated cost to complete	$	4.2
CWIP as of September 30, 2017	4.6
Guarantee Obligations	(1.7		)
Estimated capital costs	$	7.1
Vogtle Cost Settlement Agreement Revised Forecast	(5.7		)
Estimated net additional capital costs	$	1.4

Georgia Power's estimated financing costs during the construction period total approximately $3.4 billion, of which approximately $1.5 billion had been incurred through September 30, 2017.

Georgia Power's cancellation cost estimate results indicate that its proportionate share of the estimated costs to cancel both units is approximately $350 million. As a result, as of September 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:

	Cancellation Cost Estimate
	(in billions)
CWIP as of September 30, 2017	$	4.6
Financing costs collected, net of tax	1.5
Cancellation costs(*)	0.4
Guarantee Obligations	(1.7		)
Estimated net cancellation cost	$	4.8

(*) The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site.

The Guarantee Obligations continue to exist in the event of cancellation. In addition, under Georgia law, prudently incurred costs related to certificated projects cancelled by the Georgia PSC are allowed recovery, including carrying costs, in future retail rates. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery.

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

Other Matters

As of September 30, 2017, 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. On September 28, 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. 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 (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the applicable unit be placed in service prior to 2021. The net present value of Georgia Power's PTCs is estimated at approximately $400 million per unit.

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 while construction proceeds. 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 and the related approvals by the NRC, may arise while construction proceeds, 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.

While construction continues, the risk remains that challenges with management of contractors, subcontractors, and vendors, labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost.

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

See RISK FACTORS of Southern Company in Item 1A of 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. See additional risks in Item 1A herein regarding the EPC Contractor's bankruptcy.

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

Bonus Depreciation

Excluding the Kemper IGCC, approximately $830 million of positive cash flows is expected to result from bonus depreciation for the 2017 tax year. All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. If the suspension of the Kemper IGCC start-up activities ultimately results in an abandonment for income tax purposes, the related deduction would be claimed in the year of the abandonment. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein and Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

Section 174 Research and Experimental Deduction

Southern Company has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the JCT approval, Southern Company recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Section 174 Research and Experimental Deduction," respectively, herein for additional information.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Power

During the third quarter 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate solar facilities, including certain subsidiaries owned in partnership with various third parties. Southern Power's ownership interests in the various solar entities and facilities will not be affected by the reorganization. The reorganization is expected to result in estimated tax benefits totaling approximately $40 million that will be recorded in the fourth quarter 2017 related to certain changes in state apportionment rates and net operating loss carryforward utilization. The ultimate outcome of this matter cannot be determined at this time.

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 regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, 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 January 20, 2017, a purported 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 IGCC 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. On June 12, 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. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition on September 11, 2017.

On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District 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 defendants caused Southern Company to make false or misleading statements regarding the Kemper IGCC cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.

On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia and, on May 31, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. Each

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 IGCC. Each complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper IGCC schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. Each 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. Each plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.

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.

The SEC is conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company believes the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on the Kemper IGCC. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Southern Company.

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 related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, Goodwill and Other Intangible Assets, Derivatives and Hedging Activities, and Contingent Obligations.

Kemper IGCC Rate Recovery

For periods prior to the second quarter 2017, significant accounting estimates included Kemper IGCC estimated construction costs, project completion date, and rate recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery" of Southern Company in Item 7 of the Form 10-K for additional information. Mississippi Power recorded total pre-tax charges to income related to the Kemper IGCC of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($729 million after tax) in prior years.

As a result of the Mississippi PSC's June 21, 2017 stated intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant, as well as Mississippi Power's June 28, 2017 suspension of the operation and start-up of the gasifier portion of the Kemper IGCC, the estimated construction costs and project completion date are no longer considered significant accounting estimates. Significant accounting estimates

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

for the September 30, 2017 financial statements presented herein include the overall assessment of rate recovery for the Kemper County energy facility and the estimated costs for the potential cancellation of the Kemper IGCC.

While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.

As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.

In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.00 billion ($3.96 billion after tax) through September 30, 2017. Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $34 million ($21 million after tax) and $88 million ($54 million after tax) in the third quarter 2017 and the third quarter 2016, respectively, and total pre-tax charges of $3.2 billion ($2.2 billion after tax) and $222 million ($137 million after tax) year-to-date in 2017 and 2016, respectively.

Given the significant judgment involved in estimating the costs to cancel the gasifier portion of the Kemper IGCC, the ultimate rate recovery for the Kemper IGCC, including the $0.5 billion of combined cycle-related costs not yet in rates, and the impact on Southern Company's results of operations, Southern Company considers these items to be critical accounting estimates. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" 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.

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. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While Southern Company expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Southern Company's revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

contractual term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements. Southern Company expects the adoption of ASC 606 will not result in a significant shift from the current timing of revenue recognition for such transactions.

Southern Company's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company's financial statements.In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company expects CIAC to be out of the scope of ASC 606.

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company intends to use the modified retrospective method of adoption effective January 1, 2018. Southern Company has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Southern Company's financial statements, Southern Company will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.

On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017. Southern Company is evaluating the standard and expects to early adopt ASU 2017-04 effective January 1, 2018.

On March 10, 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 income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Southern Company's financial statements.

On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 and interim periods within those fiscal years, with early adoption permitted. Southern Company is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Southern Company's financial statements.

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, 2017. 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 $5.3 billion for the first nine months of 2017, an increase of $1.0 billion from the corresponding period in 2016. The increase in net cash provided from operating activities was primarily due to an increase of $1.5 billion in net cash provided from operating activities of Southern Company Gas, which was acquired on July 1, 2016, partially offset by the timing of vendor payments. Net cash used for investing activities totaled $6.7 billion for the first nine months of 2017 primarily due to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, capital expenditures for Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions. Net cash provided from financing activities totaled $1.3 billion for the first nine months of 2017 primarily due to net issuances of long-term and short-term debt, partially offset by common stock dividend payments. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first nine months of 2017 include an increase of $1.3 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, Southern Company Gas' infrastructure replacement programs, and Southern Power's renewable acquisitions, largely offset by the $2.9 billion write-down of the gasification portions of the Kemper IGCC; a decrease of $0.4 billion in income taxes receivable, current and unrecognized tax benefits primarily related to income tax refunds associated with deductible R&E expenditures; a decrease of $0.5 billion in acquisitions payable related to Southern Power; an increase of $2.3 billion in long-term debt (including amounts due within one year) primarily to fund the Southern Company system's continuous construction programs and for general corporate purposes; and a decrease of $0.7 billion in total common stockholder's equity primarily related to the estimated probable losses on the Kemper IGCC, partially offset by the issuance of additional shares of common stock.

At the end of the third quarter 2017, the market price of Southern Company's common stock was $49.14 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $23.99 per share, representing a market-to-book ratio of 205%, compared to $49.19, $25.00, and 197%, respectively, at the end of 2016. Southern Company's common stock dividend for the third quarter 2017 was $0.58 per share compared to $0.56 per share in the third quarter 2016.

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 for the construction programs of the Southern Company system, including estimated capital expenditures for new electric generating facilities and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

obligations, preferred and preference stock dividends, leases, purchase commitments, pipeline charges, storage capacity, and gas supply, asset management agreements, standby letters of credit and performance/surety bonds, trust funding requirements, and unrecognized tax benefits. Subsequent to September 30, 2017, Alabama Power repaid at maturity $325 million aggregate principal amount of its Series Q 5.50% Senior Notes due October 15, 2017. An additional $3.2 billion will be required through September 30, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the 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 (I) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures, including Georgia Power's cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.

Sources of Capital

Southern Company intends to meet its future capital needs through operating cash flows, short-term debt, term loans, and external security issuances. 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 capital and debt issuances in 2017, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements and will depend upon prevailing market conditions and other factors. See "Capital Requirements and Contractual Obligations" herein for additional information.

Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, short-term borrowings, and equity contributions or loans from Southern Company. In addition, Southern Power 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 (i) Eligible Project Costs, less (ii) amounts received from Toshiba under the Guarantee Settlement Agreement and amounts received from the Westinghouse bankruptcy proceeding) 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, 2017, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. On July 27, 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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On September 28, 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. 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 (E) 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, and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

As of September 30, 2017, Southern Company's current liabilities exceeded current assets by $3.4 billion due to long-term debt that is due within one year of $3.5 billion (comprised of approximately $1.0 billion at the parent company, $0.3 billion at Alabama Power, $0.3 billion at Georgia Power, $1.0 billion at Mississippi Power, and $0.9 billion at Southern Power) and notes payable of $2.6 billion (comprised of approximately $1.1 billion at the parent company, $0.4 billion at Georgia Power, $0.1 billion at Southern Power, and $0.9 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.

At September 30, 2017, Southern Company and its subsidiaries had approximately $1.8 billion of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:

	Expires														Executable Term Loans				Expires Within One Year
Company	2017		2018		2019		2020		2022		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)
Southern Company(a)	$	—	$	—	$	—	$	—	$	2,000	$	2,000	$	2,000	$	—	$	—	$	—	$	—
Alabama Power	—		35		—		500		800		1,335		1,335		—		—		—		35
Georgia Power	—		—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	30		195		25		30		—		280		280		45		—		—		40
Mississippi Power	100		—		—		—		—		100		100		—		—		—		100
Southern Power Company(b)	—		—		—		—		750		750		728		—		—		—		—
Southern Company Gas(c)	—		—		—		—		1,900		1,900		1,861		—		—		—		—
Other	—		30		—		—		—		30		30		20		—		20		10
Southern Company Consolidated	$	130	$	260	$	25	$	530	$	7,200	$	8,145	$	8,066	$	65	$	—	$	20	$	185

(a) Represents the Southern Company parent entity.

(b) Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $111 million has been used for letters of credit and $9 million remains unused at September 30, 2017.

(c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.2 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.

49

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

As reflected in the table above, in May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018. Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022. Pursuant to the new multi-year credit arrangement, the allocations may be adjusted. In September 2017, Alabama Power amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020.

Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Georgia Power, Mississippi 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, 2017, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

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

A portion of the unused credit with banks is allocated to provide liquidity support to the pollution control 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 pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of September 30, 2017 was approximately $1.5 billion as compared to $1.9 billion at December 31, 2016. In June 2017, Georgia Power remarketed $318 million of variable rate pollution control bonds in index rate modes, reducing the liquidity support utilized under Georgia Power's bank credit arrangement. In addition, at September 30, 2017, the traditional electric operating companies had approximately $699 million of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2017, $40 million of these pollution control revenue bonds of Georgia Power which were in an index rate mode were remarketed to the public in a long-term fixed rate mode.

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.

50

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of short-term borrowings were as follows:

	Short-term Debt at September 30, 2017				Short-term Debt During the Period(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
Commercial paper	$	1,725	1.5	%	$	1,895	1.5	%	$	2,284
Short-term bank debt	854		2.0	%	938		2.1	%	1,017
Total	$	2,579	1.7	%	$	2,833	1.7	%

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017.

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, 2017, 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, and interest rate management.

The maximum potential collateral requirements under these contracts at September 30, 2017 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	38
At BBB- and/or Baa3	$	647
At BB+ and/or Ba1(*)	$	2,352

(*) 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 March 1, 2017, Moody's downgraded the senior unsecured debt rating of Mississippi Power to Ba1 from Baa3.

On March 20, 2017, Moody's revised its rating outlook for Georgia Power from stable to negative.

On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including the traditional electric operating companies, Southern Power, Southern Company Gas, Southern Company Gas Capital, and Nicor Gas) from stable to negative.

On March 30, 2017, Fitch placed the ratings of Southern Company, Georgia Power, and Mississippi Power on rating watch negative.

On June 22, 2017, Moody's placed the ratings of Mississippi Power on review for downgrade. On September 21, 2017, Moody's revised its rating outlook for Mississippi Power from under review to stable.

51

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities

During the first nine months of 2017, Southern Company issued approximately 10.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $479 million.

In addition, during the second and third quarters of 2017, Southern Company issued a total of approximately 2.7 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 $134 million, net of $1.1 million in fees and commissions.

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2017:

Company	Senior Note Issuances		Senior Note Maturities and Redemptions		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions and Maturities(a)
	(in millions)
Southern Company(b)	$	300	$	400	$	—	$	500		$	400
Alabama Power	550		200		36		—			—
Georgia Power	1,350		450		65		370			13
Gulf Power	300		85		—		6			—
Mississippi Power	—		—		—		40			893
Southern Power	—		—		—		43			4
Southern Company Gas(c)	450		—		—		200			22
Other	—		—		—		—			12
Elimination(d)	—		—		—		(40		)	(599		)
Southern Company Consolidated	$	2,950	$	1,135	$	101	$	1,119		$	745

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

(b) Represents the Southern Company parent entity.

(c) The senior notes were issued by Southern Company Gas Capital and guaranteed by the Southern Company Gas parent entity. Other long-term debt issued represents first mortgage bonds issued by Nicor Gas.

(d) Includes intercompany loans from Southern Company to Mississippi Power and reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements.

In March 2017, Southern Company repaid at maturity a $400 million 18-month floating rate bank loan.

In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057 and $300 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due September 30, 2020, which bear interest at a floating rate based on three-month LIBOR. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.

Also in June 2017, Southern Company entered into two $100 million aggregate principal amount floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.

In August 2017, Southern Company borrowed $250 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds were used for working capital and other general corporate purposes.

52

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Also in August 2017, Southern Company repaid at maturity $400 million aggregate principal amount of Series 2014A 1.30% Senior Notes.

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

In September 2017, Alabama Power issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used in October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of Alabama Power's 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of Alabama Power's 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of Alabama Power's 5.83% Class A Preferred Stock and for other general corporate purposes, including Alabama Power's continuous construction program.

Subsequent to September 30, 2017, Alabama Power repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes due October 15, 2017.

In June 2017, Georgia Power entered into three floating rate bank loans in aggregate principal amounts of $50 million, $150 million, and $100 million, with maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, which bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds from these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes, including Georgia Power's continuous construction program.

In August 2017, Georgia Power repaid its $50 million floating rate bank loan due December 1, 2017 and $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. Also in August 2017, Georgia Power amended its $100 million floating rate bank loan to extend the maturity date from June 28, 2018 to October 26, 2018.

As reflected in the table above under other long-term debt issuances, in September 2017, Georgia Power issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used in October 2017 to redeem all 1.8 million shares ($45 million aggregate liquidation amount) of Georgia Power's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of Georgia Power's 6.50% Series 2007A Preference Stock.

In March 2017, Gulf Power extended the maturity of a $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017.

A portion of the proceeds of Gulf Power's senior note issuances was used in June 2017 to redeem 550,000 shares ($55 million aggregate liquidation amount) of Gulf Power's 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Gulf Power's Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Gulf Power's Series 2013A 5.60% Preference Stock.

In June 2017, Mississippi Power prepaid $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018.

In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate bank loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes.

In July 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage

53

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Bonds 3.62% Series due August 10, 2037. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. The remaining $200 million is expected to be issued in November 2017.

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.

54

PART I

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

During the nine months ended September 30, 2017, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to Gulf Power and Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power and Southern Company Gas, respectively, 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 (C) and Note (H) 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 2017 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.

55

ALABAMA POWER COMPANY

56

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,595		$	1,629		$	4,155		$	4,139
Wholesale revenues, non-affiliates	77			82			210			211
Wholesale revenues, affiliates	18			18			83			49
Other revenues	50			56			158			162
Total operating revenues	1,740			1,785			4,606			4,561
Operating Expenses:
Fuel	343			410			944			973
Purchased power, non-affiliates	57			63			132			139
Purchased power, affiliates	55			41			117			129
Other operations and maintenance	391			348			1,134			1,097
Depreciation and amortization	185			177			549			524
Taxes other than income taxes	93			96			284			286
Total operating expenses	1,124			1,135			3,160			3,148
Operating Income	616			650			1,446			1,413
Other Income and (Expense):
Allowance for equity funds used during construction	11			7			27			23
Interest expense, net of amounts capitalized	(76		)	(77		)	(229		)	(224		)
Other income (expense), net	(5		)	(5		)	(8		)	(16		)
Total other income and (expense)	(70		)	(75		)	(210		)	(217		)
Earnings Before Income Taxes	546			575			1,236			1,196
Income taxes	216			219			493			462
Net Income	330			356			743			734
Dividends on Preferred and Preference Stock	5			4			14			13
Net Income After Dividends on Preferred and Preference Stock	$	325		$	352		$	729		$	721

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)				(in millions)
Net Income	$	330	$	356	$	743	$	734
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $-, $-, and $(1), respectively	—		—		—		(2		)
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $2, and $2, respectively	1		1		3		3
Total other comprehensive income (loss)	1		1		3		1
Comprehensive Income	$	331	$	357	$	746	$	735

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

57

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2017			2016
	(in millions)
Operating Activities:
Net income	$	743		$	734
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	666			634
Deferred income taxes	260			267
Allowance for equity funds used during construction	(27		)	(23		)
Pension, postretirement, and other employee benefits	(4		)	(14		)
Other, net	43			(12		)
Changes in certain current assets and liabilities —
-Receivables	(163		)	(4		)
-Fossil fuel stock	34			18
-Other current assets	(58		)	(46		)
-Accounts payable	(125		)	(113		)
-Accrued taxes	159			207
-Accrued compensation	(48		)	(22		)
-Retail fuel cost over recovery	(76		)	(104		)
-Other current liabilities	7			19
Net cash provided from operating activities	1,411			1,541
Investing Activities:
Property additions	(1,211		)	(947		)
Nuclear decommissioning trust fund purchases	(174		)	(275		)
Nuclear decommissioning trust fund sales	174			275
Cost of removal, net of salvage	(82		)	(70		)
Change in construction payables	105			(37		)
Other investing activities	(29		)	(28		)
Net cash used for investing activities	(1,217		)	(1,082		)
Financing Activities:
Proceeds —
Senior notes	550			400
Capital contributions from parent company	337			253
Preferred stock	250			—
Other long-term debt	—			45
Redemptions —
Pollution control revenue bonds	(36		)	—
Senior notes	(200		)	(200		)
Payment of common stock dividends	(536		)	(574		)
Other financing activities	(26		)	(21		)
Net cash provided from (used for) financing activities	339			(97		)
Net Change in Cash and Cash Equivalents	533			362
Cash and Cash Equivalents at Beginning of Period	420			194
Cash and Cash Equivalents at End of Period	$	953		$	556
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $10 and $8 capitalized for 2017 and 2016, respectively)	$	217		$	215
Income taxes, net	146			(70		)
Noncash transactions — Accrued property additions at end of period	189			84

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

58

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2017			At December 31, 2016
	(in millions)
Current Assets:
Cash and cash equivalents	$	953		$	420
Receivables —
Customer accounts receivable	428			348
Unbilled revenues	149			146
Other accounts and notes receivable	47			27
Affiliated	45			40
Accumulated provision for uncollectible accounts	(8		)	(10		)
Fossil fuel stock	171			205
Materials and supplies	455			435
Prepaid expenses	58			34
Other regulatory assets, current	122			149
Other current assets	5			11
Total current assets	2,425			1,805
Property, Plant, and Equipment:
In service	26,619			26,031
Less: Accumulated provision for depreciation	9,463			9,112
Plant in service, net of depreciation	17,156			16,919
Nuclear fuel, at amortized cost	314			336
Construction work in progress	928			491
Total property, plant, and equipment	18,398			17,746
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	65			66
Nuclear decommissioning trusts, at fair value	869			792
Miscellaneous property and investments	121			112
Total other property and investments	1,055			970
Deferred Charges and Other Assets:
Deferred charges related to income taxes	525			525
Deferred under recovered regulatory clause revenues	17			150
Other regulatory assets, deferred	1,191			1,157
Other deferred charges and assets	178			163
Total deferred charges and other assets	1,911			1,995
Total Assets	$	23,789		$	22,516

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

59

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2017			At December 31, 2016
	(in millions)
Current Liabilities:
Securities due within one year	$	325		$	561
Accounts payable —
Affiliated	275			297
Other	376			433
Customer deposits	92			88
Accrued taxes —
Accrued income taxes	115			45
Other accrued taxes	128			42
Accrued interest	75			78
Accrued compensation	151			193
Other regulatory liabilities, current	4			85
Other current liabilities	50			76
Total current liabilities	1,591			1,898
Long-term Debt	7,083			6,535
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,919			4,654
Deferred credits related to income taxes	60			65
Accumulated deferred ITCs	118			110
Employee benefit obligations	289			300
Asset retirement obligations	1,564			1,503
Other cost of removal obligations	630			684
Other regulatory liabilities, deferred	93			100
Other deferred credits and liabilities	51			63
Total deferred credits and other liabilities	7,724			7,479
Total Liabilities	16,398			15,912
Redeemable Preferred Stock	329			85
Preference Stock	196			196
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	2,961			2,613
Retained earnings	2,711			2,518
Accumulated other comprehensive loss	(28		)	(30		)
Total common stockholder's equity	6,866			6,323
Total Liabilities and Stockholder's Equity	$	23,789		$	22,516

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

60

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2017 vs. THIRD QUARTER 2016

AND

YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016

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 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.

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 and preference stock.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(27)	(7.7)	$8	1.1

Alabama Power's net income after dividends on preferred and preference stock for the third quarter 2017 was $325 million compared to $352 million for the corresponding period in 2016. The decrease was primarily related to a decrease in retail revenues associated with milder weather and lower customer usage in the third quarter 2017 compared to the corresponding period in 2016 and an increase in non-fuel operations and maintenance expenses. The decrease was partially offset by an increase in rates under Rate RSE effective January 1, 2017.

Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2017 was $729 million compared to $721 million for the corresponding period in 2016. The increase was primarily related to an increase in rates under Rate RSE effective January 1, 2017, partially offset by a decrease in retail revenues associated with milder weather and lower customer usage for year-to-date 2017 compared to the corresponding period in 2016, and an increase in non-fuel operations and maintenance expenses.

Retail Revenues

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(34)	(2.1)	$16	0.4

In the third quarter 2017, retail revenues were $1.60 billion compared to $1.63 billion for the corresponding period in 2016. For year-to-date 2017, retail revenues were $4.16 billion compared to $4.14 billion for the corresponding period in 2016.

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Details of the changes in retail revenues were as follows:

	Third Quarter 2017					Year-to-Date 2017
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	1,629				$	4,139
Estimated change resulting from –
Rates and pricing	85			5.2		240			5.8
Sales decline	(18		)	(1.1	)	(31		)	(0.7	)
Weather	(50		)	(3.1	)	(116		)	(2.8	)
Fuel and other cost recovery	(51		)	(3.1	)	(77		)	(1.9	)
Retail – current year	$	1,595		(2.1	)%	$	4,155		0.4	%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to an increase in rates under Rate RSE effective January 1, 2017. 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.

Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjusted residential KWH sales decreased 2.4% and 1.1% for the third quarter and year-to-date 2017, respectively, primarily due to lower customer usage resulting from an increase in penetration of energy efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 2.3% and 1.4% for the third quarter and year-to-date 2017, respectively, primarily due to lower customer usage resulting from customer initiatives in energy savings and an ongoing migration to the electronic commerce business model, partially offset by customer growth. Industrial KWH sales increased 1.8% and 0.6% for the third quarter and year-to-date 2017, respectively, as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, chemicals, and mining sectors, partially offset by a decrease in demand from the pipeline sector.

Revenues resulting from changes in weather decreased in the third quarter and year-to-date 2017 due to milder weather experienced in Alabama Power's service territory compared to the corresponding periods in 2016. For the third quarter 2017, the resulting decreases were 5.1% and 2.4% for residential and commercial sales revenues, respectively. For year-to-date 2017, the resulting decreases were 5.2% and 1.8% for residential and commercial sales revenues, respectively.

Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to a decrease in KWH generation and a decrease in 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.

Wholesale Revenues – Affiliates

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$34	69.4

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

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

For year-to-date 2017, wholesale revenues from sales to affiliates were $83 million compared to $49 million for the corresponding period in 2016. The increase was primarily due to a 52% increase in KWH sales as a result of supporting Southern Company system transmission reliability and an 11% increase in the price of energy due to an increase in natural gas prices.

Other Revenues

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(6)	(10.7)	$(4)	(2.5)

In the third quarter 2017, other revenues were $50 million compared to $56 million for the corresponding period in 2016. The decrease was primarily due to lower open access transmission tariff revenues as a result of rate adjustments.

Fuel and Purchased Power Expenses

	Third Quarter 2017 vs. Third Quarter 2016				Year-to-Date 2017 vs. Year-to-Date 2016
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(67	)	(16.3)	$	(29	)	(3.0	)
Purchased power – non-affiliates	(6		)	(9.5)	(7		)	(5.0	)
Purchased power – affiliates	14			34.1	(12		)	(9.3	)
Total fuel and purchased power expenses	$	(59	)		$	(48	)

In the third quarter 2017, fuel and purchased power expenses were $455 million compared to $514 million for the corresponding period in 2016. The decrease was primarily due to a $43 million net decrease related to the volume of KWHs generated and purchased and a $16 million decrease related to the average cost of fuel.

For year-to-date 2017, fuel and purchased power expenses were $1.19 billion compared to $1.24 billion for the corresponding period in 2016. The decrease was primarily due to a $53 million decrease in the volume of KWHs purchased and a $34 million decrease related to the average cost of fuel. This decrease was partially offset by a $35 million increase in the average cost of purchased power.

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

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

	Third Quarter 2017	Third Quarter 2016	Year-to-Date 2017	Year-to-Date 2016
Total generation (in billions of KWHs)	16	18	46	46
Total purchased power (in billions of KWHs)	2	2	5	6
Sources of generation (percent) —
Coal	52	59	49	51
Nuclear	24	22	25	24
Gas	19	18	20	19
Hydro	5	1	6	6
Cost of fuel, generated (in cents per net KWH)—
Coal	2.61	2.73	2.61	2.80
Nuclear	0.75	0.77	0.75	0.78
Gas	2.72	2.85	2.74	2.62
Average cost of fuel, generated (in cents per net KWH)(a)	2.17	2.32	2.15	2.25
Average cost of purchased power (in cents per net KWH)(b)	5.65	5.70	5.57	4.81

(a) KWHs generated by hydro are excluded from the average cost of fuel, generated.

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

Fuel

In the third quarter 2017, fuel expense was $343 million compared to $410 million for the corresponding period in 2016. The decrease was primarily due to an 18.4% decrease in the volume of KWHs generated by coal, a 4.6% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and a 4.4% decrease in average cost of coal per KWH generated. In addition, there was a 194.0% increase in the volume of KWHs generated by hydro facilities as a result of significantly more rainfall in 2017.

For year-to-date 2017, fuel expense was $944 million compared to $973 million for the corresponding period in 2016. The decrease was primarily due to a 6.8% decrease in the average cost of coal per KWH generated and a 2.0% decrease in the volume of KWHs generated by coal. The decrease was partially offset by a 4.8% increase in the volume of KWHs generated by natural gas and a 4.6% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements.

Purchased Power – Affiliates

In the third quarter 2017, purchased power expense from affiliates was $55 million compared to $41 million for the corresponding period in 2016. The increase was primarily related to a 55.2% increase in the amount of energy purchased due to an increase in plant outages and increased purchases from Southern Electric Generating Company (SEGCO). The increase was partially offset by a 14.5% decrease in the average cost per KWH of capacity and energy at SEGCO. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information.

For year-to-date 2017, purchased power expense from affiliates was $117 million compared to $129 million for the corresponding period in 2016. The decrease was primarily related to a 26.6% decrease in the amount of energy purchased due to a decrease in demand as a result of milder weather in 2017, partially offset by a 22.9% increase in the average cost of purchased power per KWH as a result of higher natural gas prices.

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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 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$43	12.4	$37	3.4

In the third quarter 2017, other operations and maintenance expenses were $391 million compared to $348 million for the corresponding period in 2016. The increase was primarily due to increases of $26 million in scheduled generation outage costs, $11 million in vegetation management costs, and $3 million in employee compensation and benefit costs, including pension costs.

For year-to-date 2017, other operations and maintenance expenses were $1.13 billion compared to $1.10 billion for the corresponding period in 2016. The increase was primarily due to increases of $31 million in vegetation management costs, $10 million in nuclear generation plant improvement costs, and $7 million in employee compensation and benefit costs, including pension costs, partially offset by an $11 million decrease in contract services.

Depreciation and Amortization

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$8	4.5	$25	4.8

In the third quarter 2017, depreciation and amortization was $185 million compared to $177 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $549 million compared to $524 million for the corresponding period in 2016. These increases were primarily due to additional plant in service and an increase in depreciation rates, effective January 1, 2017, associated with compliance-related steam projects and asset retirement obligation recovery, partially offset by a decrease in distribution-related depreciation rates. 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.

Income Taxes

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(3)	(1.4)	$31	6.7

For year-to-date 2017, income taxes were $493 million compared to $462 million for the corresponding period in 2016. The increase was primarily due to higher pre-tax earnings, unrecognized tax benefits related to certain state deductions for federal income taxes, and prior year tax return actualization.

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 driven primarily by customer growth. Earnings will also depend upon

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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. 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. Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Alabama Power's financial statements. 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

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Environmental compliance costs are recovered through Rate CNP Compliance. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information. Further, higher 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. 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" in Item 8 of the Form 10-K for additional information.

Environmental Statutes and Regulations

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the final effluent guidelines rule and the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.

On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.

On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.

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 Alabama Power in Item 7 of the Form 10-K for additional information.

On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order

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specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.

On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.

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

FERC Matters

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 the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.

On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Alabama Power's) and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies (including Alabama Power) and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' (including Alabama Power's) and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.

On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including Alabama Power's) and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Alabama Power) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including Alabama Power) and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.

The ultimate outcome of these matters 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 for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.

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 regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, 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.

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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.

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 related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.

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.

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. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While Alabama Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Alabama Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Alabama Power expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.

Alabama Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Alabama Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Alabama Power expects CIAC to be out of the scope of ASC 606.

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Alabama Power intends to use the modified retrospective method of adoption effective January 1, 2018. Alabama Power has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-

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effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Alabama Power's financial statements, Alabama Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.

On March 10, 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 income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Alabama Power's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Alabama Power's financial statements.

On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. 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 and interim periods within those fiscal years, with early adoption permitted. Alabama Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Alabama Power's financial statements.

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, 2017. 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 $1.4 billion for the first nine months of 2017, a decrease of $130 million as compared to the first nine months of 2016. The decrease in net cash provided from operating activities was primarily due to the receipt of income tax refunds in 2016 as a result of bonus depreciation. Net cash used for investing activities totaled $1.2 billion for the first nine months of 2017 primarily due to gross property additions related to distribution, environmental, transmission, and steam generation. Net cash provided from financing activities totaled $339 million for the first nine months of 2017 primarily due to an issuance of long-term debt and preferred stock and additional capital contributions from Southern Company, partially offset by common stock dividend payments and a redemption of long-term debt. 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 2017 include increases of $652 million in property, plant, and equipment primarily due to additions to distribution, transmission, and steam generation, $548 million in long-term debt primarily due to the issuance of additional senior notes, $533 million in cash and cash equivalents, $348 million in additional paid-in capital due to capital contributions from Southern Company, $265 million in

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accumulated deferred income taxes primarily due to bonus depreciation, and $244 million in redeemable preferred stock primarily due to the September 2017 issuance, as well as a decrease of $236 million in securities due within one year.

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 for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Subsequent to September 30, 2017, Alabama Power repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes due October 15, 2017. No additional funds will be required through September 30, 2018 to fund maturities of long-term debt.

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

Alabama Power's Board of Directors approved its construction program that is currently estimated to total $2.2 billion for 2018, $1.6 billion for 2019, $1.6 billion for 2020, $1.7 billion for 2021, and $1.4 billion for 2022. 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 $0.6 billion for 2018, $0.1 billion for 2019, $0.2 billion for 2020, $0.3 billion for 2021, and $0.3 billion for 2022. These estimated expenditures do not include any potential compliance costs that may arise from the EPA's final rules and guidelines or future state plans that would limit CO₂ emissions from new, existing, modified, or reconstructed fossil-fuel-fired electric generating units.

Alabama Power also anticipates costs associated with closure in place and monitoring of ash ponds in accordance with the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), which are reflected in Alabama Power's asset retirement obligation liabilities. These costs, which could change as Alabama Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $27 million for 2018, $101 million for 2019, $105 million for 2020, $107 million for 2021, and $109 million for 2022. See 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. Costs associated with the CCR Rule are expected to be recovered through Rate CNP Compliance.

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 statutes and regulations; the outcome of any legal challenges to the 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, short-term debt, term loans, external security issuances, 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

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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, 2017, Alabama Power had approximately $953 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:

Expires										Expires Within One Year
2018		2020		2022		Total		Unused		Term Out		No Term Out
(in millions)
$	35	$	500	$	800	$	1,335	$	1,335	$	—	$	35

See Note 6 to the financial statements of Alabama Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

In May 2017 and September 2017, Alabama Power amended its $800 million and $500 million multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022 and 2018 to 2020, respectively, as reflected in the table above.

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, 2017, 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, 2017. At September 30, 2017, Alabama Power had no fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

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

71

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of commercial paper borrowings were as follows:

	Short-term Debt During the Period(*)
	Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)
Commercial paper	$	30	1.3	%	$	220

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017. No short-term debt was outstanding at September 30, 2017.

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, 2017, Alabama Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

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

The maximum potential collateral requirements under these contracts at September 30, 2017 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	1
At BBB- and/or Baa3	$	2
Below BBB- and/or Baa3	$	338

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

On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Alabama Power) from stable to negative.

Financing Activities

In February 2017, Alabama Power repaid at maturity $200 million aggregate principal amount of Series 2007A 5.55% Senior Notes.

In March 2017, Alabama Power issued $550 million aggregate principal amount of Series 2017A 2.45% Senior Notes due March 30, 2022. The proceeds were used to repay Alabama Power's short-term indebtedness and for general corporate purposes, including Alabama Power's continuous construction program.

In July 2017, Alabama Power repaid at maturity $36.1 million aggregate principal amount of Series 1993-A, 1993-B, and 1993-C Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Refunding Bonds (Alabama Power Company Project).

72

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In September 2017, Alabama Power issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used in October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of 5.83% Class A Preferred Stock and for other general corporate purposes, including Alabama Power's continuous construction program.

Subsequent to September 30, 2017, Alabama Power repaid at maturity $325 million aggregate principal amount of Series Q 5.50% Senior Notes due October 15, 2017.

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.

73

GEORGIA POWER COMPANY

74

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	2,402		$	2,540		$	5,995		$	6,164
Wholesale revenues, non-affiliates	45			49			124			131
Wholesale revenues, affiliates	6			9			23			24
Other revenues	93			100			284			302
Total operating revenues	2,546			2,698			6,426			6,621
Operating Expenses:
Fuel	482			575			1,297			1,390
Purchased power, non-affiliates	119			102			310			277
Purchased power, affiliates	161			142			470			392
Other operations and maintenance	413			496			1,194			1,393
Depreciation and amortization	225			215			669			639
Taxes other than income taxes	112			114			311			311
Total operating expenses	1,512			1,644			4,251			4,402
Operating Income	1,034			1,054			2,175			2,219
Other Income and (Expense):
Interest expense, net of amounts capitalized	(105		)	(98		)	(310		)	(290		)
Other income (expense), net	5			11			41			35
Total other income and (expense)	(100		)	(87		)	(269		)	(255		)
Earnings Before Income Taxes	934			967			1,906			1,964
Income taxes	350			363			705			734
Net Income	584			604			1,201			1,230
Dividends on Preferred and Preference Stock	4			4			13			13
Net Income After Dividends on Preferred and Preference Stock	$	580		$	600		$	1,188		$	1,217

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2017		2016		2017		2016
	(in millions)				(in millions)
Net Income	$	584	$	604	$	1,201	$	1,230
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $1, and $1, respectively	1		1		2		2
Total other comprehensive income (loss)	1		1		2		2
Comprehensive Income	$	585	$	605	$	1,203	$	1,232

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,
	2017			2016
	(in millions)
Operating Activities:
Net income	$	1,201		$	1,230
Adjustments to reconcile net income to net cash provided from operating activities --
Depreciation and amortization, total	821			794
Deferred income taxes	328			346
Allowance for equity funds used during construction	(29		)	(36		)
Deferred expenses	(30		)	(40		)
Pension, postretirement, and other employee benefits	(42		)	(14		)
Settlement of asset retirement obligations	(95		)	(93		)
Other, net	(21		)	7
Changes in certain current assets and liabilities —
-Receivables	(254		)	(162		)
-Fossil fuel stock	(2		)	128
-Other current assets	(29		)	62
-Accounts payable	(161		)	39
-Accrued taxes	(52		)	(22		)
-Accrued compensation	(60		)	(26		)
-Retail fuel cost over recovery	(84		)	9
-Other current liabilities	(11		)	44
Net cash provided from operating activities	1,480			2,266
Investing Activities:
Property additions	(1,907		)	(1,566		)
Nuclear decommissioning trust fund purchases	(411		)	(563		)
Nuclear decommissioning trust fund sales	406			558
Cost of removal, net of salvage	(54		)	(45		)
Change in construction payables, net of joint owner portion	180			(139		)
Payments pursuant to LTSAs	(59		)	(27		)
Sale of property	63			10
Other investing activities	(52		)	14
Net cash used for investing activities	(1,834		)	(1,758		)
Financing Activities:
Decrease in notes payable, net	(391		)	(63		)
Proceeds —
Capital contributions from parent company	412			294
Senior notes	1,350			650
FFB loan	—			300
Short-term borrowings	700			—
Other long-term debt	370			—
Redemptions and repurchases —
Pollution control revenue bonds	(65		)	(4		)
Senior notes	(450		)	(700		)
Short-term borrowings	(300		)	—
Payment of common stock dividends	(961		)	(979		)
Other financing activities	(48		)	(26		)
Net cash provided from (used for) financing activities	617			(528		)
Net Change in Cash and Cash Equivalents	263			(20		)
Cash and Cash Equivalents at Beginning of Period	3			67
Cash and Cash Equivalents at End of Period	$	266		$	47
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $17 and $15 capitalized for 2017 and 2016, respectively)	$	284		$	277
Income taxes, net	369			188
Noncash transactions — Accrued property additions at end of period	470			226

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, 2017			At December 31, 2016
	(in millions)
Current Assets:
Cash and cash equivalents	$	266		$	3
Receivables —
Customer accounts receivable	670			523
Unbilled revenues	276			224
Under recovered fuel clause revenues	62			—
Joint owner accounts receivable	222			57
Other accounts and notes receivable	82			81
Affiliated	21			18
Accumulated provision for uncollectible accounts	(3		)	(3		)
Fossil fuel stock	300			298
Materials and supplies	480			479
Prepaid expenses	82			105
Other regulatory assets, current	200			193
Other current assets	27			38
Total current assets	2,685			2,016
Property, Plant, and Equipment:
In service	34,589			33,841
Less: Accumulated provision for depreciation	11,655			11,317
Plant in service, net of depreciation	22,934			22,524
Nuclear fuel, at amortized cost	551			569
Construction work in progress	5,751			4,939
Total property, plant, and equipment	29,236			28,032
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	53			60
Nuclear decommissioning trusts, at fair value	914			814
Miscellaneous property and investments	51			46
Total other property and investments	1,018			920
Deferred Charges and Other Assets:
Deferred charges related to income taxes	669			676
Other regulatory assets, deferred	2,890			2,774
Other deferred charges and assets	608			417
Total deferred charges and other assets	4,167			3,867
Total Assets	$	37,106		$	34,835

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

77

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2017			At December 31, 2016
	(in millions)
Current Liabilities:
Securities due within one year	$	261		$	460
Notes payable	400			391
Accounts payable —
Affiliated	396			438
Other	1,012			589
Customer deposits	270			265
Accrued taxes	353			407
Accrued interest	121			106
Accrued compensation	164			224
Asset retirement obligations, current	214			299
Other current liabilities	192			297
Total current liabilities	3,383			3,476
Long-term Debt	11,610			10,225
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	6,328			6,000
Accumulated deferred ITCs	248			256
Employee benefit obligations	665			703
Asset retirement obligations, deferred	2,367			2,233
Other deferred credits and liabilities	232			320
Total deferred credits and other liabilities	9,840			9,512
Total Liabilities	24,833			23,213
Preferred Stock	45			45
Preference Stock	221			221
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — 9,261,500 shares	398			398
Paid-in capital	7,308			6,885
Retained earnings	4,311			4,086
Accumulated other comprehensive loss	(10		)	(13		)
Total common stockholder's equity	12,007			11,356
Total Liabilities and Stockholder's Equity	$	37,106		$	34,835

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 2017 vs. THIRD QUARTER 2016

AND

YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016

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.

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 after dividends on preferred and preference stock.

Nuclear Construction

Georgia Power and the Vogtle Owners have been constructing Plant Vogtle Units 3 and 4 since 2009. On March 29, 2017, the EPC Contractor for Plant Vogtle Units 3 and 4 filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the EPC Contractor (Interim Assessment Agreement), which the bankruptcy court approved on March 30, 2017. On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million.

Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into a services agreement (Services Agreement), which was 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. On July 27, 2017, the Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE and the Interim Assessment Agreement expired pursuant to its terms. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice. Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement (Bechtel Agreement) with Bechtel Power Corporation (Bechtel), whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4.

In the seventeenth Vogtle Construction Monitoring (VCM) report filed on August 31, 2017, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and

79

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

4 is by November 2021 for Unit 3 and by November 2022 for Unit 4, at an additional cost of approximately $1.41 billion, net of the Guarantee Settlement Agreement. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.

On September 28, 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. 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 (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Georgia Power's financial statements. The ultimate outcome of these matters cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4, including Georgia Power's cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(20)	(3.3)	$(29)	(2.4)

Georgia Power's net income after dividends on preferred and preference stock for the third quarter 2017 was $580 million compared to $600 million for the corresponding period in 2016. For year-to-date 2017, net income after dividends on preferred and preference stock was $1.19 billion compared to $1.22 billion for the corresponding period in 2016. The decreases were primarily due to lower revenues resulting from milder weather and lower customer usage as compared to the corresponding periods in 2016, partially offset by lower non-fuel operations and maintenance expenses.

Retail Revenues

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(138)	(5.4)	$(169)	(2.7)

In the third quarter 2017, retail revenues were $2.40 billion compared to $2.54 billion for the corresponding period in 2016. For year-to-date 2017, retail revenues were $6.00 billion compared to $6.16 billion for the corresponding period in 2016.

80

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:

	Third Quarter 2017					Year-to-Date 2017
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	2,540				$	6,164
Estimated change resulting from –
Rates and pricing	41			1.6		60			1.0
Sales decline	(39		)	(1.5	)	(50		)	(0.8	)
Weather	(94		)	(3.7	)	(204		)	(3.3	)
Fuel cost recovery	(46		)	(1.8	)	25			0.4
Retail – current year	$	2,402		(5.4	)%	$	5,995		(2.7	)%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to an increase in revenues related to the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff. See 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 decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjusted residential KWH sales decreased 3.5% and 0.8% for the third quarter and year-to-date 2017, respectively, primarily due to a decline in average customer usage due to an increase in multi-family housing and energy saving initiatives, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 1.4% and 1.1% for the third quarter and year-to-date 2017, respectively, primarily due to a decline in average customer usage resulting from an increase in energy saving initiatives and electronic commerce transactions, partially offset by customer growth. Weather-adjusted industrial KWH sales increased 0.8% in the third quarter 2017 primarily due to increased demand in the non-manufacturing, rubber, and textile sectors, partially offset by decreased demand in the chemicals and paper sectors. Weather-adjusted industrial KWH sales decreased 1.2% for year-to-date 2017 primarily due to decreased demand in the paper and chemicals sectors, partially offset by increased demand in the non-manufacturing and rubber sectors. Despite a more stable dollar and improving global economy, the industrial sector remains constrained by economic policy uncertainty.Additionally, Hurricane Irma negatively impacted customer usage for all customer classes during the third quarter and year-to-date 2017.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. In the third quarter 2017, retail fuel cost recovery revenues decreased $46 million when compared to the corresponding period in 2016 primarily due to lower coal prices and lower energy sales resulting from milder weather. For year-to-date 2017, retail fuel cost recovery revenues increased $25 million when compared to the corresponding period in 2016 primarily due to higher natural gas prices, partially offset by lower coal prices and lower energy sales resulting from milder weather. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information.

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Revenues

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(7)	(7.0)	$(18)	(6.0)

In the third quarter 2017, other revenues were $93 million compared to $100 million for the corresponding period in 2016. The decrease was primarily due to a $3 million decrease in open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts, and a $3 million decrease in solar application fee revenues, partially offset by a $3 million increase in outdoor lighting sales revenues primarily attributable to LED conversions.

For year-to-date 2017, other revenues were $284 million compared to $302 million for the corresponding period in 2016. The decrease was primarily due to a $14 million adjustment in 2016 for customer temporary facilities services revenues and a $12 million decrease in open access transmission tariff revenues, primarily as a result of the expiration of long-term transmission services contracts, partially offset by a $10 million increase in outdoor lighting sales revenues primarily attributable to LED conversions.

Fuel and Purchased Power Expenses

	Third Quarter 2017 vs. Third Quarter 2016					Year-to-Date 2017 vs. Year-to-Date 2016
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	(93	)	(16.2	)	$	(93	)	(6.7	)
Purchased power – non-affiliates	17			16.7		33			11.9
Purchased power – affiliates	19			13.4		78			19.9
Total fuel and purchased power expenses	$	(57	)			$	18

In the third quarter 2017, total fuel and purchased power expenses were $762 million compared to $819 million in the corresponding period in 2016. The decrease was primarily due to a $59 million decrease related to the volume of KWHs generated primarily due to milder weather, resulting in lower customer demand, and slight decreases in the volume of KWHs purchased and the average cost of fuel. These decreases were partially offset by a $7 million increase in the average cost of purchased power primarily related to higher natural gas prices.

For year-to-date 2017, total fuel and purchased power expenses were $2.08 billion compared to $2.06 billion in the corresponding period in 2016. The increase was primarily due to a $97 million increase in the average cost of fuel and purchased power primarily related to higher natural gas prices, partially offset by a net decrease of $79 million related to the volume of KWHs generated and purchased primarily due to milder weather, resulting in lower customer demand.

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

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	Third Quarter 2017	Third Quarter 2016	Year-to-Date 2017	Year-to-Date 2016
Total generation (in billions of KWHs)	18	20	48	53
Total purchased power (in billions of KWHs)	7	7	20	19
Sources of generation (percent) —
Coal	35	44	33	37
Nuclear	23	22	24	23
Gas	41	34	41	38
Hydro	1	—	2	2
Cost of fuel, generated (in cents per net KWH)—
Coal	3.08	3.16	3.17	3.32
Nuclear	0.84	0.85	0.84	0.85
Gas	2.63	2.61	2.71	2.27
Average cost of fuel, generated (in cents per net KWH)	2.38	2.47	2.40	2.34
Average cost of purchased power (in cents per net KWH)(*)	4.68	4.57	4.63	4.46

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

Fuel

In the third quarter 2017, fuel expense was $482 million compared to $575 million in the corresponding period in 2016. The decrease was primarily due to a 9.6% decrease in the volume of KWHs generated largely due to milder weather, resulting in lower customer demand, and a 3.6% decrease in the average cost of fuel per KWH generated primarily resulting from lower coal prices.

For year-to-date 2017, fuel expense was $1.30 billion compared to $1.39 billion in the corresponding period in 2016. The decrease was primarily due to an 8.4% decrease in the volume of KWHs generated largely due to milder weather, resulting in lower customer demand, partially offset by a 19.4% increase in the average cost of natural gas per KWH generated.

Purchased Power – Non-Affiliates

In the third quarter 2017, purchased power expense from non-affiliates was $119 million compared to $102 million in the corresponding period in 2016. For year-to-date 2017, purchased power expense from non-affiliates was $310 million compared to $277 million in the corresponding period in 2016. The increases were primarily due to increases in the volume of KWHs purchased of 14.2% and 12.6% in the third quarter and year-to-date 2017, respectively, primarily due to unplanned outages at Georgia Power-owned generating units. The increase for year-to-date 2017 was partially offset by a 1.5% decrease in the average cost per KWH purchased.

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

Purchased Power – Affiliates

In the third quarter 2017, purchased power expense from affiliates was $161 million compared to $142 million in the corresponding period in 2016. The increase was primarily due to a 1.5% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices, partially offset by a 5.6% decrease in the volume of

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KWHs purchased due to the expiration of a PPA in May 2017 and milder weather, resulting in lower customer demand.

For year-to-date 2017, purchased power expense from affiliates was $470 million compared to $392 million in the corresponding period in 2016. The increase was primarily the result of a 4.3% increase in the volume of KWHs purchased to support Southern Company system transmission reliability and due to unplanned outages at Georgia Power-owned generating units and a 5.9% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices.

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 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(83)	(16.7)	$(199)	(14.3)

In the third quarter 2017, other operations and maintenance expenses were $413 million compared to $496 million in the corresponding period in 2016. The decrease was primarily due to cost containment and modernization activities implemented in the third quarter 2016 that contributed to decreases of $29 million in generation maintenance costs, $9 million in customer accounts, service, and sales costs, $8 million in employee benefits, and $8 million in transmission and distribution overhead line maintenance. Other factors include decreases of $12 million in charges related to employee attrition plans and $8 million in scheduled generation outage costs.

For year-to-date 2017, other operations and maintenance expenses were $1.19 billion compared to $1.39 billion in the corresponding period in 2016. The decrease was primarily due to cost containment and modernization activities implemented in the third quarter 2016 that contributed to decreases of $56 million in generation maintenance costs, $34 million in other employee compensation and benefits, and $23 million in transmission and distribution overhead line maintenance. Other factors include a $19 million increase in gains from sales of integrated transmission system assets, a $16 million decrease in customer assistance expenses primarily in demand-side management costs related to the timing of new programs, an $8 million decrease in charges related to employee attrition plans, and a $7 million decrease in billing adjustments with integrated transmission system owners.

Depreciation and Amortization

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$10	4.7	$30	4.7

In the third quarter 2017, depreciation and amortization was $225 million compared to $215 million in the corresponding period in 2016. The increase was primarily due to an $8 million increase related to additional plant in service and a $4 million decrease in amortization of regulatory liabilities related to other cost of removal obligations that expired in December 2016.

For year-to-date 2017, depreciation and amortization was $669 million compared to $639 million in the corresponding period in 2016. The increase was primarily due to a $25 million increase related to additional plant in service and an $11 million decrease in amortization of regulatory liabilities related to other cost of removal obligations that expired in December 2016, partially offset by a $5 million decrease in depreciation related to generating unit retirements in 2016.

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Interest Expense, Net of Amounts Capitalized

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$7	7.1	$20	6.9

In the third quarter 2017, interest expense, net of amounts capitalized was $105 million compared to $98 million in the corresponding period in 2016. For year-to-date 2017, interest expense, net of amounts capitalized was $310 million compared to $290 million in the corresponding period in 2016. The increases were primarily due to increases in outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information.

Other Income (Expense), Net

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(6)	(54.5)	$6	17.1

In the third quarter 2017, other income (expense), net was $5 million compared to $11 million in the corresponding period in 2016. The decrease was primarily due to a decrease of $9 million in AFUDC equity resulting from higher short-term borrowings, partially offset by increases of $3 million in customer contributions in aid of construction and $3 million in contract services revenue.

For year-to-date 2017, other income (expense), net was $41 million compared to $35 million in the corresponding period in 2016. The increase was primarily due to increases of $6 million in contract services revenue, $4 million in customer contributions in aid of construction, and $4 million in gains on purchases of state tax credits, partially offset by a $7 million decrease in AFUDC equity resulting from higher short-term borrowings.

Income Taxes

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(13)	(3.6)	$(29)	(4.0)

In the third quarter 2017, income taxes were $350 million compared to $363 million in the corresponding period in 2016. For year-to-date 2017, income taxes were $705 million compared to $734 million in the corresponding period in 2016. The decreases were primarily due to lower pre-tax earnings and increased state ITCs.

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. Matters related to 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 higher multi-family home construction. 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

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growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.

Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability of nuclear PTCs, is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Georgia Power's financial statements.

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 and RISK FACTORS in Item 1A herein.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations 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. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher 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. 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 Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's eight-hour ozone National Ambient Air Quality Standard (NAAQS).

On June 2, 2017, the EPA published a final rule redesignating a 15-county area within metropolitan Atlanta to attainment for the 2008 eight-hour ozone NAAQS.

On June 18, 2017, the EPA published a notice delaying attainment designations for the 2015 eight-hour ozone NAAQS by one year, setting a revised deadline of October 1, 2018. However, on August 2, 2017, the EPA issued a withdrawal notice of the one-year extension and reinstated the original October 1, 2017 designation deadline. The ultimate outcome of this matter cannot be determined at this time.

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the final effluent guidelines rule and the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.

On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.

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On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.

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 Georgia Power in Item 7 of the Form 10-K for additional information.

On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.

On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.

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

FERC Matters

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 the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.

On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Georgia Power's) and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies (including Georgia Power) and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' (including Georgia Power's) and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.

On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including Georgia Power's) and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Georgia Power) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including Georgia Power) and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.

The ultimate outcome of these matters 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 the construction 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

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– "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information regarding fuel cost recovery.

Renewables

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan" of Georgia Power in Item 7 of the Form 10-K for additional information regarding renewable energy projects.

On May 16, 2017, the Georgia PSC approved Georgia Power's request to build, own, and operate a 139-MW solar generation facility at a U.S. Air Force base that is expected to be placed in service by the end of 2019.

During the nine months ended September 30, 2017, Georgia Power continued construction of a 31-MW solar generation facility at a U.S. Marine Corps base that is expected to be placed in service in the fourth quarter 2017.

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

Integrated Resource Plan

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan" of Georgia Power in Item 7 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan.

On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at a future generation site in Stewart County, Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing of recovery for costs incurred of approximately $50 million will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.

Storm Damage Recovery

Georgia Power is accruing$30 millionannually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. During September 2017, Hurricane Irma caused significant damage to Georgia Power's transmission and distribution facilities.The total amount of incremental restoration costs related to this hurricane is estimated to be approximately $150 million. As of September 30, 2017, Georgia Power had deferred approximately $145 million in a regulatory asset related to storm damage. As of September 30, 2017, the total balance in the regulatory asset related to storm damage was $360 million. The rate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Georgia Power's financial statements. 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.

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, the NCCR tariff, and the Contractor Settlement Agreement.

Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy

In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Georgia Power's proportionate share of Plant Vogtle Units 3 and 4 is 45.7%.

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The Vogtle 3 and 4 Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed.

Under the terms of the Vogtle 3 and 4 Agreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the Vogtle 3 and 4 Agreement was 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest).

On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement, which the bankruptcy court approved on March 30, 2017.

The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided. The Interim Assessment Agreement, as amended, expired on July 27, 2017.

Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through September 30, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which $340 million had been paid or accrued as of September 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $176 million.

On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion, of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, which will reduce CWIP, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million. Georgia Power is considering potential options with respect to its right to future payments under the Guarantee Settlement Agreement and its claims against

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the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to DOE consents and related approvals under the Loan Guarantee Agreement and related agreements.

On August 10, 2017, Toshiba released its financial results for the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $4.5 billion as of June 30, 2017. Toshiba previously announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Georgia Power's financial statements.

Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Services Agreement, which was 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. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Bechtel Agreement, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4. Facility design and engineering remains the responsibility of the EPC Contractor under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a 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 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, 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 connection with the recommendation to continue with construction of Plant Vogtle Units 3 and 4 (described below), the Vogtle Owners agreed on a term sheet to amend the existing joint ownership agreements to provide for additional Vogtle Owner approval requirements. Under the 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 adverse events occur, including (i) the bankruptcy of Toshiba or a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) 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 because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report by more than $1 billion or extension of the project schedule contained in the seventeenth VCM report by more than one year. In addition, under the term sheet, 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 Services Agreement or agreements with the primary construction contractor or Southern Nuclear.

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The term sheet also confirms 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.

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 nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. As of September 30, 2017, Georgia Power had recovered approximately $1.5 billion of financing costs. Georgia Power expects to file on November 1, 2017 to increase the NCCR tariff by approximately $90 million, effective January 1, 2018, pending Georgia PSC approval.

On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not placed in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.

The Georgia PSC has approved sixteen VCM reports covering the periods through December 31, 2016, including construction capital costs incurred, which through that date totaled $3.9 billion. Georgia Power filed its seventeenth VCM report, covering the period from January 1 through June 30, 2017, requesting approval of $542 million of construction capital costs incurred during that period, with the Georgia PSC on August 31, 2017.

In the seventeenth VCM report, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4. Georgia Power's recommendation to go forward with completion of Vogtle Units 3 and 4 is based on the following assumptions about the regulatory treatment of this recommendation, if the recommendation to go forward

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is adopted by the Georgia PSC: (i) that pursuant to Georgia law, the Georgia PSC in the seventeenth VCM proceeding approves the new cost and schedule forecast and finds that it is a reasonable basis for going forward, and that if the Georgia PSC disapproves all or part of the proposed cost and schedule revisions, Georgia Power may cancel Plant Vogtle Units 3 and 4 and recover its actual investment in Plant Vogtle Units 3 and 4; (ii) that the Vogtle Cost Settlement Agreement remains in full force and effect, including Georgia Power retaining the burden of proving all capital costs above $5.680 billion were prudent; (iii) that while the Georgia PSC will make no prudence finding in the seventeenth VCM proceeding, nor will the certified amount be amended consistent with the Vogtle Cost Settlement Agreement, the Georgia PSC recognizes that the certified amount is not a cap, and all costs that are approved and presumed or shown to be prudently incurred will be recoverable by Georgia Power; (iv) that Georgia Power is not a guarantor of the Toshiba Guarantee, and the failure of Toshiba to pay the Toshiba Guarantee, the failure of the U.S. Congress to extend the PTCs for Plant Vogtle Units 3 and 4, or the failure of the DOE to extend the Loan Guarantee Agreement with Georgia Power to reflect the increased capital amounts, will not reduce the amount of investment Georgia Power is otherwise allowed to collect; and (v) that as conditions change and assumptions are either proven or disproven, Georgia Power and the Georgia PSC may reconsider the decision to go forward. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.

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

Revised Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 is as follows:

	(in billions)
Estimated cost to complete	$	4.2
CWIP as of September 30, 2017	4.6
Guarantee Obligations	(1.7		)
Estimated capital costs	$	7.1
Vogtle Cost Settlement Agreement Revised Forecast	(5.7		)
Estimated net additional capital costs	$	1.4

Georgia Power's estimated financing costs during the construction period total approximately $3.4 billion, of which approximately $1.5 billion had been incurred through September 30, 2017.

Georgia Power's cancellation cost estimate results indicate that its proportionate share of the estimated costs to cancel both units is approximately $350 million. As a result, as of September 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:

	Cancellation Cost Estimate
	(in billions)
CWIP as of September 30, 2017	$	4.6
Financing costs collected, net of tax	1.5
Cancellation costs(*)	0.4
Guarantee Obligations	(1.7		)
Estimated net cancellation cost	$	4.8

(*) The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site.

The Guarantee Obligations continue to exist in the event of cancellation. In addition, under Georgia law, prudently incurred costs related to certificated projects cancelled by the Georgia PSC are allowed recovery, including carrying

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costs, in future retail rates. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery.

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

Other Matters

As of September 30, 2017, 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. On September 28, 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. 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 (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the applicable unit be placed in service prior to 2021. The net present value of Georgia Power's PTCs is estimated at approximately $400 million per unit.

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 while construction proceeds. 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 and the related approvals by the NRC, may arise while construction proceeds, 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.

While construction continues, the risk remains that challenges with management of contractors, subcontractors, and vendors, labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost.

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

See RISK FACTORS of Georgia Power in Item 1A of 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. See additional risks in Item 1A herein regarding the EPC Contractor's bankruptcy.

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 regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, 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.

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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.

Georgia Power regularly reviews its business to transform and modernize. Primarily in response to changing customer expectations and payment patterns, including electronic payments and alternative payment locations, and ongoing efforts to increase overall operating efficiencies, Georgia Power initiated the closure of its remaining payment offices and an employee attrition plan affecting approximately 300 positions. Charges associated with these activities did not have a material impact on Georgia Power's results of operations, financial position, or cash flows. The efficiencies gained are expected to place downward pressure on operating costs in 2018.

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 related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.

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.

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. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While Georgia Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Georgia Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Georgia Power expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.

Georgia Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Georgia Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Georgia Power expects CIAC to be out of the scope of ASC 606.

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Georgia Power intends to use the modified retrospective method of adoption effective January 1, 2018. Georgia Power has

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also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Georgia Power's financial statements, Georgia Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.

On March 10, 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 income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Georgia Power's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Georgia Power's financial statements.

On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. 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 and interim periods within those fiscal years, with early adoption permitted. Georgia Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Georgia Power's financial statements.

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, 2017. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $1.48 billion for the first nine months of 2017 compared to $2.27 billion for the corresponding period in 2016. The decrease was primarily due to the timing of vendor payments and fossil fuel stock purchases and an increase in under-recovered fuel costs. Net cash used for investing activities totaled $1.83 billion for the first nine months of 2017 compared to $1.76 billion for the corresponding period in 2016 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Net cash provided from financing activities totaled $617 million for the first nine months of 2017 compared to $528 million used for financing activities in the

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corresponding period in 2016. The increase in cash provided from financing activities is primarily due to an increase in short-term borrowings, higher issuances of senior notes and junior subordinated notes, and a decrease in maturities of senior notes, partially offset by a decrease in borrowings from the FFB for construction of Plant Vogtle Units 3 and 4 and an increase in redemptions of 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 2017 include increases of $1.2 billion in property, plant, and equipment to comply with environmental standards and the construction of generation, transmission, and distribution facilities, $1.2 billion in long-term debt primarily due to issuances of senior notes and junior subordinated notes, $423 million in accounts payable, other primarily due to charges for restoration costs related to Hurricane Irma and liabilities for the removal of subcontractor liens related to the EPC Contractor's bankruptcy, and $423 million in paid-in capital primarily due to capital contributions received from Southern Company. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Storm Damage Recovery" and " – Nuclear Construction" for additional information regarding Hurricane Irma and the EPC Contractor's bankruptcy, respectively.

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 for its construction program, including estimated capital expenditures for Plant Vogtle Units 3 and 4 and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $261 million will be required through September 30, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information. Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. 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 "Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures, including Georgia Power's cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.

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, short-term debt, external security issuances, term loans, equity contributions from Southern Company, and, to the extent available, borrowings from the FFB. 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 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

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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 (i) Eligible Project Costs, less (ii) amounts received from Toshiba under the Guarantee Settlement Agreement and amounts received from the Westinghouse bankruptcy proceeding) 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, 2017, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. On July 27, 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.

On September 28, 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. 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 (E) 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, and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

At September 30, 2017, Georgia Power's current liabilities exceeded current assets by $698 million. Georgia Power's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt ($261 million at September 30, 2017) and the periodic use of short-term debt as a funding source ($400 million at September 30, 2017), as well as significant seasonal fluctuations in cash needs. Georgia Power intends to utilize operating cash flows, short-term debt, external security issuances, term loans, equity contributions from Southern Company, and, to the extent available, borrowings from the FFB 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, 2017, Georgia Power had approximately $266 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks at September 30, 2017 was $1.75 billion of which $1.73 billion was unused. In May 2017, Georgia Power amended its multi-year credit arrangement, which, among other things, extended the maturity date from 2020 to 2022.

This bank credit arrangement, as well as Georgia Power's term loan arrangements, 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, 2017, 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 (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

A portion of the 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, 2017 was approximately $550 million as compared to $868 million at December 31, 2016. In June 2017, Georgia Power remarketed $318 million of variable rate pollution control bonds in index rate modes, reducing the liquidity support utilized under Georgia Power's bank

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credit arrangement. In addition, at September 30, 2017, Georgia Power had $509 million of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2017, $40 million of these pollution control revenue bonds which were in an index rate mode were remarketed to the public in a long-term fixed rate mode.

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. Commercial paper is included in notes payable in the balance sheets.

Details of short-term borrowings were as follows:

	Short-term Debt at September 30, 2017				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	$	—	—	%	$	109	1.5	%	$	428
Short-term bank debt	400		2.0	%	568		2.0	%	800
Total	$	400	2.0	%	$	677	2.0	%

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017.

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, 2017, Georgia Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

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

The maximum potential collateral requirements under these contracts at September 30, 2017 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	87
Below BBB- and/or Baa3	$	1,021

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

On March 20, 2017, Moody's revised its rating outlook for Georgia Power from stable to negative.

On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Georgia Power) from stable to negative.

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On March 30, 2017, Fitch placed the ratings of Georgia Power on rating watch negative.

Financing Activities

In March 2017, Georgia Power issued $450 million aggregate principal amount of Series 2017A 2.00% Senior Notes due March 30, 2020 and $400 million aggregate principal amount of Series 2017B 3.25% Senior Notes due March 30, 2027. The proceeds were used to repay a portion of Georgia Power's short-term indebtedness and for general corporate purposes, including Georgia Power's continuous construction program.

In April 2017, Georgia Power purchased and held $27 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995. Subsequent to September 30, 2017, Georgia Power remarketed these bonds to the public.

In June 2017, Georgia Power repaid at maturity $450 million aggregate principal amount of Series 2007B 5.70% Senior Notes.

In June 2017, Georgia Power entered into three floating rate bank loans in aggregate principal amounts of $50 million, $150 million, and $100 million, with maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, which bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds from these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes, including Georgia Power's continuous construction program.

In August 2017, Georgia Power repaid $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. Also in August 2017, Georgia Power amended its $100 million floating rate bank loan to extend the maturity date from June 28, 2018 to October 26, 2018.

Also in August 2017, Georgia Power issued $500 million aggregate principal amount of Series 2017C 2.00% Senior Notes due September 8, 2020. The proceeds were used to repay Georgia Power's $50 million floating rate bank loan due December 1, 2017 and outstanding commercial paper borrowings and for general corporate purposes.

Also in August 2017, Georgia Power purchased and held $38 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1997. Subsequent to September 30, 2017, Georgia Power remarketed these bonds to the public.

In September 2017, Georgia Power issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used in October 2017 to redeem all 1.8 million shares ($45 million aggregate liquidation amount) of Georgia Power's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of Georgia Power's 6.50% Series 2007A Preference Stock.

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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CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	375		$	377		$	972		$	978
Wholesale revenues, non-affiliates	14			17			44			48
Wholesale revenues, affiliates	28			23			75			59
Other revenues	20			19			53			51
Total operating revenues	437			436			1,144			1,136
Operating Expenses:
Fuel	127			141			323			342
Purchased power, non-affiliates	37			33			104			95
Purchased power, affiliates	2			3			13			9
Other operations and maintenance	81			86			252			239
Depreciation and amortization	42			49			95			129
Taxes other than income taxes	33			34			88			93
Loss on Plant Scherer Unit 3	—			—			33			—
Total operating expenses	322			346			908			907
Operating Income	115			90			236			229
Other Income and (Expense):
Interest expense, net of amounts capitalized	(13		)	(11		)	(37		)	(36		)
Other income (expense), net	1			(2		)	—			(4		)
Total other income and (expense)	(12		)	(13		)	(37		)	(40		)
Earnings Before Income Taxes	103			77			199			189
Income taxes	40			30			78			74
Net Income	63			47			121			115
Dividends on Preference Stock	—			2			4			7
Net Income After Dividends on Preference Stock	$	63		$	45		$	117		$	108

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2017		2016		2017			2016
	(in millions)				(in millions)
Net Income	$	63	$	47	$	121		$	115
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $-, $(1), and $(3), respectively	—		—		(1		)	(4		)
Total other comprehensive income (loss)	—		—		(1		)	(4		)
Comprehensive Income	$	63	$	47	$	120		$	111

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

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CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2017			2016
	(in millions)
Operating Activities:
Net income	$	121		$	115
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	100			134
Deferred income taxes	57			15
Loss on Plant Scherer Unit 3	33			—
Other, net	(5		)	(2		)
Changes in certain current assets and liabilities —
-Receivables	(65		)	(9		)
-Fossil fuel stock	7			49
-Other current assets	11			3
-Accrued taxes	21			40
-Accrued compensation	(10		)	(5		)
-Over recovered regulatory clause revenues	(8		)	26
-Other current liabilities	10			8
Net cash provided from operating activities	272			374
Investing Activities:
Property additions	(142		)	(106		)
Cost of removal, net of salvage	(16		)	(8		)
Change in construction payables	(9		)	(7		)
Other investing activities	(6		)	(6		)
Net cash used for investing activities	(173		)	(127		)
Financing Activities:
Decrease in notes payable, net	(268		)	(42		)
Proceeds —
Common stock issued to parent	175			—
Capital contributions from parent company	7			10
Senior notes	300			—
Redemptions —
Preference stock	(150		)	—
Senior notes	(85		)	(125		)
Payment of common stock dividends	(94		)	(90		)
Other financing activities	(3		)	(5		)
Net cash used for financing activities	(118		)	(252		)
Net Change in Cash and Cash Equivalents	(19		)	(5		)
Cash and Cash Equivalents at Beginning of Period	56			74
Cash and Cash Equivalents at End of Period	$	37		$	69
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $- and $- capitalized for 2017 and 2016, respectively)	$	24		$	29
Income taxes, net	19			14
Noncash transactions — Accrued property additions at end of period	25			13

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

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Assets	At September 30, 2017			At December 31, 2016
	(in millions)
Current Assets:
Cash and cash equivalents	$	37		$	56
Receivables —
Customer accounts receivable	96			72
Unbilled revenues	68			55
Under recovered regulatory clause revenues	15			17
Income taxes receivable, current	15			—
Other accounts and notes receivable	12			6
Affiliated	13			17
Accumulated provision for uncollectible accounts	(1		)	(1		)
Fossil fuel stock	64			71
Materials and supplies	58			55
Other regulatory assets, current	55			44
Other current assets	15			30
Total current assets	447			422
Property, Plant, and Equipment:
In service	5,181			5,140
Less: Accumulated provision for depreciation	1,457			1,382
Plant in service, net of depreciation	3,724			3,758
Construction work in progress	75			51
Total property, plant, and equipment	3,799			3,809
Deferred Charges and Other Assets:
Deferred charges related to income taxes	56			58
Other regulatory assets, deferred	499			512
Other deferred charges and assets	22			21
Total deferred charges and other assets	577			591
Total Assets	$	4,823		$	4,822

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

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Liabilities and Stockholder's Equity	At September 30, 2017			At December 31, 2016
	(in millions)
Current Liabilities:
Securities due within one year	$	7		$	87
Notes payable	—			268
Accounts payable —
Affiliated	46			59
Other	55			54
Customer deposits	35			35
Accrued taxes	41			20
Accrued interest	20			8
Accrued compensation	30			40
Deferred capacity expense, current	22			22
Other regulatory liabilities, current	1			16
Other current liabilities	37			40
Total current liabilities	294			649
Long-term Debt	1,285			987
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,003			948
Employee benefit obligations	90			96
Deferred capacity expense	103			119
Asset retirement obligations, deferred	125			120
Other cost of removal obligations	218			249
Other regulatory liabilities, deferred	45			47
Other deferred credits and liabilities	71			71
Total deferred credits and other liabilities	1,655			1,650
Total Liabilities	3,234			3,286
Preference Stock	—			147
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — September 30, 2017: 7,392,717 shares
— December 31, 2016: 5,642,717 shares	678			503
Paid-in capital	600			589
Retained earnings	312			296
Accumulated other comprehensive income (loss)	(1		)	1
Total common stockholder's equity	1,589			1,389
Total Liabilities and Stockholder's Equity	$	4,823		$	4,822

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

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THIRD QUARTER 2017 vs. THIRD QUARTER 2016

AND

YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016

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.

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 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.

On April 4, 2017, the Florida PSC approved a settlement agreement (2017 Rate Case Settlement Agreement) among Gulf Power and three intervenors with respect to Gulf Power's request to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%), is deemed to have an equity ratio of 52.5% for all retail regulatory purposes, and implemented new dismantlement accruals effective July 1, 2017. Gulf Power will also begin amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and will implement new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.

Gulf 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 preference stock.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$18	40.0	$9	8.3

Gulf Power's net income after dividends on preference stock for the third quarter 2017 was $63 million compared to $45 million for the corresponding period in 2016. The increase was primarily due to an increase in retail base revenues and a decrease in depreciation.

Gulf Power's net income after dividends on preference stock for year-to-date 2017 was $117 million compared to $108 million for the corresponding period in 2016. The increase was primarily due to a decrease in depreciation and

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an increase in retail base revenues, partially offset by a write-down of $32.5 million ($20 million after tax) of Gulf Power's ownership of Plant Scherer Unit 3 resulting from the 2017 Rate Case Settlement Agreement and higher operations and maintenance expenses. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.

Retail Revenues

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	(0.5)	$(6)	(0.6)

In the third quarter 2017, retail revenues were $375 million compared to $377 million for the corresponding period in 2016. For year-to-date 2017, retail revenues were $972 million compared to $978 million for the corresponding period in 2016.

Details of the changes in retail revenues were as follows:

	Third Quarter 2017					Year-to-Date 2017
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	377				$	978
Estimated change resulting from –
Rates and pricing	21			5.6		28			2.9
Sales growth	3			0.8		1			0.1
Weather	(9		)	(2.4	)	(14		)	(1.4	)
Fuel and other cost recovery	(17		)	(4.5	)	(21		)	(2.2	)
Retail – current year	$	375		(0.5	)%	$	972		(0.6	)%

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 increased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to an increase in retail base revenues effective July 2017, as well as an increase in environmental cost recovery effective November 2016 resulting from Gulf Power's ownership of Plant Scherer Unit 3 being rededicated to retail service.

Revenues attributable to changes in sales increased slightly in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016. For the third quarter 2017, weather-adjusted KWH sales to residential and commercial customers increased 5.2% and 1.5%, respectively. Weather-adjusted KWH sales to residential customers increased 1.3% year-to-date 2017. These increases were primarily due to customer growth, partially offset by lower customer usage primarily resulting from efficiency improvements in appliances and lighting. Weather-adjusted KWH sales to commercial customers decreased slightly year-to-date 2017 as a result of lower customer usage primarily resulting from efficiency improvements in appliances and lighting, mostly offset by customer growth. KWH sales to industrial customers decreased 7.1% and 6.1% for the third quarter and year-to-date 2017, respectively, primarily due to changes in customers' operations and energy efficiency improvements.

Fuel and other cost recovery revenues decreased in the third quarter and year-to-date 2017 when compared to the corresponding periods in 2016, primarily due to lower fuel, purchased power capacity, and energy conservation recoverable costs, partially offset by higher environmental recoverable costs. Fuel and other cost recovery

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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 Rate Case Settlement Agreement. 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 cost recovery clauses and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.

Wholesale Revenues – Non-Affiliates

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(3)	(17.6)	$(4)	(8.3)

Wholesale revenues from sales to non-affiliates consist of long-term sales agreements to other utilities in Florida and Georgia and short-term opportunity sales. Capacity revenues from long-term sales agreements represent the greatest contribution to net income. The energy is generally sold at variable cost. Short-term opportunity sales are made at market-based rates that generally provide a margin above Gulf Power's variable cost of energy. Wholesale energy revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Gulf 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.

In the third quarter 2017, wholesale revenues from sales to non-affiliates were $14 million compared to $17 million for the corresponding period in 2016. The decrease was primarily due to a 28.4% decrease in KWH sales attributable to decreased market demand for energy as a result of milder weather.

For year-to-date 2017, wholesale revenues from sales to non-affiliates were $44 million compared to $48 million for the corresponding period in 2016. The decrease was primarily due to a 20.9% decrease in capacity revenues resulting from the expiration of a Plant Scherer Unit 3 long-term sales agreement in 2016.

Wholesale Revenues – Affiliates

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$5	21.7	$16	27.1

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

In the third quarter 2017, wholesale revenues from sales to affiliates were $28 million compared to $23 million for the corresponding period in 2016. The increase was primarily due to a 24.1% increase in KWH sales resulting from outages of affiliate generation resources.

For year-to-date 2017, wholesale revenues from sales to affiliates were $75 million compared to $59 million for the corresponding period in 2016. The increase was primarily due to a 19.5% increase in KWH sales as a result of the availability of lower-cost Gulf Power generation resources.

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Fuel and Purchased Power Expenses

	Third Quarter 2017 vs. Third Quarter 2016					Year-to-Date 2017 vs. Year-to-Date 2016
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	(14	)	(9.9	)	$	(19	)	(5.6	)
Purchased power – non-affiliates	4			12.1		9			9.5
Purchased power – affiliates	(1		)	(33.3	)	4			44.4
Total fuel and purchased power expenses	$	(11	)			$	(6	)

In the third quarter 2017, total fuel and purchased power expenses were $166 million compared to $177 million for the corresponding period in 2016. The decrease was primarily the result of a $7 million net decrease due to the lower average cost of fuel and a $6 million net decrease related to the volume of KWHs generated and purchased due to milder weather in 2017 reducing demand.

For year-to-date 2017, total fuel and purchased power expenses were $440 million compared to $446 million for the corresponding period in 2016. The decrease was primarily the result of a $19 million net decrease related to the volume of KWHs generated and purchased due to milder weather in 2017 reducing demand, partially offset by a $12 million net increase related to the higher average cost of fuel and purchased power.

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.

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

	Third Quarter 2017	Third Quarter 2016	Year-to-Date 2017	Year-to-Date 2016
Total generation (in millions of KWHs)	2,780	2,775	7,000	6,654
Total purchased power(in millions of KWHs)	1,686	1,906	4,362	5,295
Sources of generation (percent) –
Coal	59	68	55	57
Gas	41	32	45	43
Cost of fuel, generated (in cents per net KWH) –
Coal	3.04	3.55	3.15	3.80
Gas	3.71	4.38	3.60	4.06
Average cost of fuel, generated(in cents per net KWH)	3.31	3.81	3.35	3.91
Average cost of purchased power (in cents per net KWH)(*)	4.32	3.79	4.70	3.51

(*) 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 2017, fuel expense was $127 million compared to $141 million for the corresponding period in 2016. The decrease was primarily due to a 13.1% decrease in the average cost of fuel resulting from lower coal and natural gas prices, partially offset by a 29.3% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.

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For year-to-date 2017, fuel expense was $323 million compared to $342 million for the corresponding period in 2016. The decrease was primarily due to a 14.3% decrease in the average cost of fuel resulting from lower coal and natural gas prices, partially offset by a 10.3% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.

Purchased Power – Non-Affiliates

In the third quarter 2017, purchased power expense from non-affiliates was $37 million compared to $33 million for the corresponding period in 2016. For year-to-date 2017, purchased power expense from non-affiliates was $104 million compared to $95 million for the corresponding period in 2016. These increases were primarily due to increases of 16.3% and 35.9% for the third quarter and year-to-date 2017, respectively, in the average cost per KWH purchased, partially offset by decreases of 11.1% and 20.2% for the third quarter and year-to-date 2017, respectively, in the volume of KWHs purchased due to lower territorial load.

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

Purchased Power – Affiliates

In the third quarter 2017, purchased power expense from affiliates was $2 million compared to $3 million for the corresponding period in 2016. The decrease was primarily due to a 38.3% decrease in the average cost per KWH purchased primarily resulting from lower priced power pool resources and a 20.5% decrease in the volume of KWHs purchased due to lower territorial load.

For year-to-date 2017, purchased power expense from affiliates was $13 million compared to $9 million for the corresponding period in 2016. The increase was primarily due to a 13.2% increase in the volume of KWHs purchased due to more planned outages for Gulf Power generation resources and a 29.3% increase in the average cost per KWH purchased primarily due to increased natural gas prices.

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

Other Operations and Maintenance Expenses

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(5)	(5.8)	$13	5.4

In the third quarter 2017, other operations and maintenance expenses were $81 million compared to $86 million for the corresponding period in 2016. The decrease was primarily due to lower employee compensation and benefits, including pension costs, and the suspension of the property damage reserve accrual in accordance with the 2017 Rate Case Settlement Agreement.

For year-to-date 2017, other operations and maintenance expenses were $252 million compared to $239 million for the corresponding period in 2016. The increase was primarily due to higher expenses at generation facilities associated with routine and planned maintenance.

See Note (A) to the Condensed Financial Statements under "Property Damage Reserve" herein for additional information regarding Gulf Power's property damage reserve accrual suspension and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.

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Depreciation and Amortization

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(7)	(14.3)	$(34)	(26.4)

In the third quarter 2017, depreciation and amortization was $42 million compared to $49 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $95 million compared to $129 million for the corresponding period in 2016. These decreases were primarily due to changes in the reductions in depreciation, as authorized in a settlement agreement approved by the Florida PSC in 2013 (2013 Rate Case Settlement Agreement), of $6 million and $34 million in the third quarter and year-to-date 2017, respectively, compared to the corresponding periods in 2016. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information.

Income Taxes

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$10	33.3	$4	5.4

In the third quarter 2017, income taxes were $40 million compared to $30 million for the corresponding period in 2016. For year-to-date 2017, income taxes were $78 million compared to $74 million for the corresponding period in 2016. These increases were primarily due to higher pre-tax earnings.

Dividends on Preference Stock

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	N/M	$(3)	(42.9)

N/M - Not meaningful

In the third quarter 2017, there were no dividends on preference stock compared to $2 million for the corresponding period in 2016. For year-to-date 2017, dividends on preference stock were $4 million compared to $7 million for the corresponding period in 2016. These decreases were the result of the redemption of all preference stock in June 2017. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein for additional information.

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. 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. Current proposals related to

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potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Gulf Power's financial statements. 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.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in retail rates or through long-term wholesale agreements on a timely basis or through market-based contracts. 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. The full impact of any such legislative or regulatory changes cannot be determined at this time. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates or long-term wholesale agreements could contribute to reduced demand for electricity as well as impact the cost competitiveness of wholesale capacity, which could negatively affect results of operations, cash flows, and financial condition. 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.

Environmental Statutes and Regulations

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the final effluent guidelines rule and the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.

On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.

On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.

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 March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind

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those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.

On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.

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

FERC Matters

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 the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.

On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Gulf Power's) and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies (including Gulf Power) and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' (including Gulf Power's) and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.

On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including Gulf Power's) and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Gulf Power) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including Gulf Power) and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.

The ultimate outcome of these matters 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.

Retail Base Rate Cases

The 2013 Rate Case Settlement Agreement authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction could not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. For 2014 and 2015, Gulf Power recognized reductions in depreciation of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016. Through June 2017, Gulf Power recognized the remaining allowable reductions in depreciation totaling $34.0 million.

On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and three intervenors with respect to Gulf Power's request to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for

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certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%), is deemed to have an equity ratio of 52.5% for all retail regulatory purposes, and implemented new dismantlement accruals effective July 1, 2017. Gulf Power will also begin amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 over 15 years effective January 1, 2018 and will implement new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3, which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.

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

As discussed previously, the 2017 Rate Case Settlement Agreement resolved the remaining issues related to Gulf Power's inclusion of certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 in the environmental cost recovery clause and no adjustment to the environmental cost recovery clause rate approved by the Florida PSC in November 2016 was made.

On October 25, 2017, 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 2018. The net effect of the approved changes is a $63 million increase in annual revenues effective in January 2018, the majority of which will be offset by related expense increases.

Renewables

In 2015, the Florida PSC approved three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. Purchases under these agreements began in the summer of 2017.

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 regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, 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 related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.

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.

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. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While Gulf Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Gulf Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Gulf Power expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.

Gulf Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Gulf Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Gulf Power expects CIAC to be out of the scope of ASC 606.

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Gulf Power intends to use the modified retrospective method of adoption effective January 1, 2018. Gulf Power has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Gulf Power's financial statements, Gulf Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.

On March 10, 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

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costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Gulf Power's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Gulf Power's financial statements.

On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. 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 and interim periods within those fiscal years, with early adoption permitted. Gulf Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Gulf Power's financial statements.

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, 2017. 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.

Net cash provided from operating activities totaled $272 million for the first nine months of 2017 compared to $374 million for the corresponding period in 2016. The $102 million decrease in net cash was primarily due to decreases related to certain cost recovery clauses, the timing of fossil fuel stock purchases, and a federal income tax refund received in 2016. Net cash used for investing activities totaled $173 million in the first nine months of 2017 primarily due to property additions to utility plant. Net cash used for financing activities totaled $118 million for the first nine months of 2017 primarily due to the payment of short-term debt, redemptions of preference stock and long-term debt, and common stock dividend payments, partially offset by proceeds from issuances of long-term debt and 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 2017 primarily reflect the financing activities described above. Other significant changes include an increase in accumulated deferred income taxes due to accelerated depreciation and repair deductions and a decrease in other cost of removal obligations, as authorized in the 2013 Rate Case Settlement Agreement. See "Financing Activities" herein and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" 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 Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power's capital requirements for its construction program, including estimated capital expenditures to comply

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with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, derivative obligations, purchase commitments, and trust funding requirements. Approximately $7 million will be required through September 30, 2018 to fund maturities of long-term debt. 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 statutes and regulations; the outcome of any legal challenges to the 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, short-term debt, external security issuances, term loans, 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.

Gulf Power's current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as significant seasonal fluctuations in cash 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 its commercial paper program which is supported by bank credit facilities.

At September 30, 2017, Gulf Power had approximately $37 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:

Expires												Executable Term Loans				Expires Within One Year
2017		2018		2019		2020		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)
$	30	$	195	$	25	$	30	$	280	$	280	$	45	$	—	$	—	$	40

See Note 6 to the financial statements of Gulf Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) 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, 2017, Gulf 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, 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.

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Most of the unused credit arrangements with banks are 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, 2017 was approximately $82 million. In addition, at September 30, 2017, Gulf Power had approximately $140 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 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)
Commercial paper	$	23	1.4	%	$	78

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017. No short-term debt was outstanding at September 30, 2017.

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.

Credit Rating Risk

At September 30, 2017, 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, 2017 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	167
Below BBB- and/or Baa3	$	579

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

On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Gulf Power) from stable to negative.

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Market Price Risk

Gulf Power's market risk exposure relative to interest rate changes for the third quarter and year-to-date 2017 has not changed materially compared to the December 31, 2016 reporting period. Gulf Power's exposure to market volatility in commodity fuel prices and prices of electricity with respect to its wholesale generating capacity is limited because its long-term sales agreement shifts substantially all fuel cost responsibility to the purchaser.

In connection with the 2017 Rate Case Settlement Agreement, Gulf Power recorded a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 in the first quarter 2017 to resolve the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates and no adjustment to the environmental cost recovery clause rate approved by the Florida PSC in November 2016 was made. The 2017 Rate Case Settlement Agreement provides that 100% of Gulf Power's ownership of Plant Scherer Unit 3 will be included in retail rates. This resolved the market price risk concern around Gulf Power's uncontracted wholesale generating capacity related to Plant Scherer Unit 3. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.

The Florida PSC extended the moratorium on Gulf Power's fuel-hedging program until January 1, 2021 in connection with the 2017 Rate Case Settlement Agreement. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program.

For additional discussion of Gulf Power's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power in Item 7 of the Form 10-K.

Financing Activities

In January 2017, Gulf Power issued 1,750,000 shares of common stock to Southern Company and realized proceeds of $175 million. The proceeds were used for general corporate purposes, including Gulf Power's continuous construction program.

In March 2017, Gulf Power extended the maturity of a $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017.

In May 2017, Gulf Power issued $300 million aggregate principal amount of Series 2017A 3.30% Senior Notes due May 30, 2027. The proceeds, together with other funds, were used to repay at maturity $85 million aggregate principal amount of Series 2007A 5.90% Senior Notes due June 15, 2017; to repay outstanding commercial paper borrowings; to repay a $100 million short-term floating rate bank loan, as discussed above; and to redeem, in June 2017, 550,000 shares ($55 million aggregate liquidation amount) of 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Series 2013A 5.60% Preference Stock.

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.

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CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	243		$	263		$	665		$	652
Wholesale revenues, non-affiliates	72			78			196			198
Wholesale revenues, affiliates	21			7			40			23
Other revenues	5			4			14			12
Total operating revenues	341			352			915			885
Operating Expenses:
Fuel	120			112			301			268
Purchased power, non-affiliates	4			3			7			4
Purchased power, affiliates	2			5			13			14
Other operations and maintenance	66			74			206			211
Depreciation and amortization	39			30			120			114
Taxes other than income taxes	25			31			77			81
Estimated loss on Kemper IGCC	34			88			3,155			222
Total operating expenses	290			343			3,879			914
Operating Income (Loss)	51			9			(2,964		)	(29		)
Other Income and (Expense):
Allowance for equity funds used during construction	1			31			72			90
Interest expense, net of amounts capitalized	13			(15		)	(23		)	(46		)
Other income (expense), net	(1		)	(1		)	(3		)	(4		)
Total other income and (expense)	13			15			46			40
Earnings (Loss) Before Income Taxes	64			24			(2,918		)	11
Income taxes (benefit)	24			(2		)	(885		)	(29		)
Net Income (Loss)	40			26			(2,033		)	40
Dividends on Preferred Stock	—			—			1			1
Net Income (Loss) After Dividends on Preferred Stock	$	40		$	26		$	(2,034	)	$	39

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2017			2016		2017			2016
	(in millions)					(in millions)
Net Income (Loss)	$	40		$	26	$	(2,033	)	$	40
Other comprehensive income (loss)
Qualifying hedges:
Changes in fair value, net of tax of $-, $-, $-, 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)	$	39		$	26	$	(2,032	)	$	40

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

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CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2017			2016
	(in millions)
Operating Activities:
Net income (loss)	$	(2,033	)	$	40
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	144			115
Deferred income taxes	(1,159		)	34
Allowance for equity funds used during construction	(72		)	(90		)
Estimated loss on Kemper IGCC	3,148			222
Other, net	(26		)	(1		)
Changes in certain current assets and liabilities —
-Receivables	438			3
-Fossil fuel stock	21			8
-Other current assets	(9		)	34
-Accounts payable	(21		)	5
-Accrued taxes	20			96
-Accrued compensation	(12		)	(5		)
-Over recovered regulatory clause revenues	(47		)	(20		)
-Customer liability associated with Kemper refunds	—			(73		)
-Other current liabilities	(31		)	5
Net cash provided from operating activities	361			373
Investing Activities:
Property additions	(411		)	(592		)
Construction payables	(47		)	(25		)
Government grant proceeds	—			137
Other investing activities	(25		)	(29		)
Net cash used for investing activities	(483		)	(509		)
Financing Activities:
Decrease in notes payable, net	(23		)	—
Proceeds —
Capital contributions from parent company	1,002			227
Long-term debt to parent company	40			200
Other long-term debt	—			900
Short-term borrowings	113			—
Redemptions —
Short-term borrowings	(109		)	(475		)
Long-term debt to parent company	(591		)	(225		)
Other long-term debt	(300		)	(425		)
Other financing activities	(3		)	(5		)
Net cash provided from financing activities	129			197
Net Change in Cash and Cash Equivalents	7			61
Cash and Cash Equivalents at Beginning of Period	224			98
Cash and Cash Equivalents at End of Period	$	231		$	159
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $73 and $72, net of $28 and $36 capitalized for 2017 and 2016, respectively)	$	45		$	36
Income taxes, net	(209		)	(231		)
Noncash transactions — Accrued property additions at end of period	32			80

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

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CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2017		At December 31, 2016
	(in millions)
Current Assets:
Cash and cash equivalents	$	231	$	224
Receivables —
Customer accounts receivable	38		29
Unbilled revenues	41		42
Income taxes receivable, current	102		544
Other accounts and notes receivable	15		14
Affiliated	15		15
Fossil fuel stock	20		100
Materials and supplies	45		76
Other regulatory assets, current	113		115
Other current assets	8		8
Total current assets	628		1,167
Property, Plant, and Equipment:
In service	4,836		4,865
Less: Accumulated provision for depreciation	1,312		1,289
Plant in service, net of depreciation	3,524		3,576
Construction work in progress	75		2,545
Total property, plant, and equipment	3,599		6,121
Other Property and Investments	28		12
Deferred Charges and Other Assets:
Deferred charges related to income taxes	62		361
Other regulatory assets, deferred	436		518
Accumulated deferred income taxes	279		—
Other deferred charges and assets	23		56
Total deferred charges and other assets	800		935
Total Assets	$	5,055	$	8,235

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

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CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2017			At December 31, 2016
	(in millions)
Current Liabilities:
Securities due within one year —
Parent	$	—		$	551
Other	1,028			78
Notes payable	4			23
Accounts payable —
Affiliated	56			62
Other	82			135
Customer deposits	16			16
Accrued taxes	78			99
Unrecognized tax benefits	2			383
Accrued interest	16			46
Accrued compensation	29			42
Asset retirement obligations, current	15			32
Over recovered fuel clause liabilities	4			51
Other current liabilities	67			20
Total current liabilities	1,397			1,538
Long-term Debt	1,167			2,424
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	—			756
Employee benefit obligations	109			115
Asset retirement obligations, deferred	150			146
Other cost of removal obligations	175			170
Other regulatory liabilities, deferred	87			84
Other deferred credits and liabilities	23			26
Total deferred credits and other liabilities	544			1,297
Total Liabilities	3,108			5,259
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	4,529			3,525
Accumulated deficit	(2,650		)	(616		)
Accumulated other comprehensive loss	(3		)	(4		)
Total common stockholder's equity	1,914			2,943
Total Liabilities and Stockholder's Equity	$	5,055		$	8,235

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2017 vs. THIRD QUARTER 2016

AND

YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016

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 the Kemper County energy facility, projected long-term demand growth, reliability, fuel, and stringent environmental standards, as well as ongoing capital expenditures required for maintenance 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.

The Kemper IGCC was approved by the Mississippi PSC in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (construction cost increase demonstrated to produce efficiencies that result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). The combined cycle and associated common facilities portion of the Kemper IGCC were placed in service in August 2014.

In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation (2015 Stipulation) between Mississippi Power and the Mississippi Public Utilities Staff (MPUS), authorizing rates that provide for the recovery of approximately $126 million annually related to the combined cycle and associated common facilities portion of Kemper IGCC assets previously placed in service. As required by the In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable. At September 30, 2017, the related regulatory liability totaled $7 million.

The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO₂, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has increased significantly since certification.

On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global

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settlement of costs of the Kemper IGCC (Kemper IGCC Settlement Docket). The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.

On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants).

While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.

Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($4.0 billion after tax) through September 30, 2017.

Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the MPUS), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.

As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.

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For additional information on the Kemper IGCC, including information on the project economic viability analysis, pending lawsuits, and an ongoing SEC investigation, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and "Other Matters" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein.

In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan; (ii) repay $591 million of the outstanding principal amount of promissory notes to Southern Company; and (iii) repay $10 million of the outstanding principal amount of bank loans.

Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Going Concern" herein.

In addition to the rate recovery of the Kemper County energy facility, 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 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$14	53.8	$(2,073)	N/M

N/M - Not meaningful

Mississippi Power's net income after dividends on preferred stock for the third quarter 2017 was $40 million compared to $26 million for the corresponding period in 2016. The increase was due to lower pre-tax charges associated with the Kemper IGCC and a decrease in interest expense, net of amounts capitalized, partially offset by an increase in income taxes and decreases in retail revenues and AFUDC equity.

Mississippi Power's net loss after dividends on preferred stock for year-to-date 2017 was $2.03 billion compared to net income of $39 million for the corresponding period in 2016. The decrease in net income was related to higher pre-tax charges associated with the Kemper IGCC.

See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

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Retail Revenues

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(20)	(7.6)	$13	2.0

In the third quarter 2017, retail revenues were $243 million compared to $263 million for the corresponding period in 2016. For year-to-date 2017, retail revenues were $665 million compared to $652 million for the corresponding period in 2016.

Details of the changes in retail revenues were as follows:

	Third Quarter 2017					Year-to-Date 2017
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	263				$	652
Estimated change resulting from –
Rates and pricing	(10		)	(3.8	)	9			1.4
Sales growth	1			0.4		4			0.6
Weather	(9		)	(3.4	)	(16		)	(2.5	)
Fuel and other cost recovery	(2		)	(0.8	)	16			2.5
Retail – current year	$	243		(7.6	)%	$	665		2.0	%

Revenues associated with changes in rates and pricing decreased in the third quarter 2017 when compared to the corresponding period in 2016 primarily due to recognition of a regulatory liability as directed by the Mississippi PSC in a July 6, 2017 order following full amortization of certain regulatory assets and an ECO Plan rate decrease implemented in the second quarter 2017.

Revenues associated with changes in rates and pricing increased in year-to-date 2017 when compared to the corresponding period in 2016 primarily due to an ECO Plan rate increase implemented in the third quarter 2016, partially offset by the recognition of a regulatory liability as directed by the Mississippi PSC in a July 6, 2017 order following full amortization of certain regulatory assets and an ECO Plan rate decrease implemented in the second quarter 2017.

See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power – Environmental Compliance Overview Plan" and "Integrated Coal Gasification Combined Cycle" herein for additional information.

Revenues attributable to changes in sales increased slightly for the third quarter 2017 when compared to the corresponding period in 2016. Weather-adjusted KWH sales to residential customers increased 2.9% due to higher customer usage. Weather-adjusted KWH sales to commercial customers decreased 1.2% due to lower customer usage, partially offset by customer growth. KWH sales to industrial customers decreased 2.4% primarily due to an unplanned outage by a large customer in 2017, the impacts of Hurricane Harvey on petroleum pipeline customers, and a decrease in the number of mid-size customers.

Revenues attributable to changes in sales increased slightly for year-to-date 2017 when compared to the corresponding period in 2016. Weather-adjusted KWH sales to residential customers increased 0.8% due to higher customer usage. Weather-adjusted KWH sales to commercial customers decreased 0.7% due to lower customer usage, partially offset by customer growth. KWH sales to industrial customers decreased 1.1% primarily due to unplanned outages by a large customer in 2017, the impacts of Hurricane Harvey on petroleum pipeline customers, and a decrease in the number of mid-size customers.

Fuel and other cost recovery revenues decreased in the third quarter 2017 when compared to the corresponding period in 2016 primarily as a result of lower recoverable fuel costs. Fuel and other cost recovery revenues increased

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for year-to-date 2017 when compared to the corresponding period in 2016 primarily as a result of higher recoverable fuel costs. See "Fuel and Purchased Power Expenses" herein for additional information. 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 – Affiliates

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$14	N/M	$17	73.9

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.

In the third quarter 2017, wholesale revenues from sales to affiliates were $21 million compared to $7 million for the corresponding period in 2016. The increase was due to a $13 million increase in KWH sales as a result of supporting Southern Company system transmission reliability and a $1 million increase primarily due to higher natural gas prices.

For year-to-date 2017, wholesale revenues from sales to affiliates were $40 million compared to $23 million for the corresponding period in 2016. The increase was primarily due to higher KWH sales as a result of supporting Southern Company system transmission reliability and higher natural gas prices.

Fuel and Purchased Power Expenses

	Third Quarter 2017 vs. Third Quarter 2016				Year-to-Date 2017 vs. Year-to-Date 2016
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	8		7.1	$	33		12.3
Purchased power – non-affiliates	1			33.3	3			75.0
Purchased power – affiliates	(3		)	(60.0)	(1		)	(7.1)
Total fuel and purchased power expenses	$	6			$	35

In the third quarter 2017, total fuel and purchased power expenses were $126 million compared to $120 million for the corresponding period in 2016. The increase was due to a $6 million increase in the volume of KWHs generated and purchased.

For year-to-date 2017, total fuel and purchased power expenses were $321 million compared to $286 million for the corresponding period in 2016. The increase was primarily due to a $42 million increase in the average cost of natural gas and purchased power, partially offset by a $4 million decrease in coal prices and a $3 million decrease in the volume of KWHs generated and purchased.

Fuel and purchased power energy transactions do not have a significant impact on earnings since 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 2017	Third Quarter 2016	Year-to-Date 2017	Year-to-Date 2016
Total generation (in millions of KWHs)	4,453	4,255	11,542	11,570
Total purchased power (in millions of KWHs)(*)	164	288	527	877
Sources of generation (percent) –
Coal	8	10	8	9
Gas	92	90	92	91
Cost of fuel, generated (in cents per net KWH)–
Coal	3.80	4.02	3.60	4.09
Gas	2.77	2.64	2.72	2.34
Average cost of fuel, generated (in cents per net KWH)	2.86	2.79	2.80	2.50
Average cost of purchased power (in cents per net KWH)(*)	3.74	2.59	3.78	2.04

(*) Includes energy produced during the test period for the Kemper IGCC, which is accounted for in accordance with FERC guidance.

Fuel

In the third quarter 2017, total fuel expense was $120 million compared to $112 million for the corresponding period in 2016. The increase was due to a 2.5% increase in the average cost of fuel per KWH generated, primarily due to a 4.5% higher cost of natural gas, and a 5.4% increase in the volume of KWHs generated.

For year-to-date 2017, total fuel expense was $301 million compared to $268 million for the corresponding period in 2016. The increase was due to a 12.0% increase in the average cost of fuel per KWH generated primarily due to a 16.2% higher cost of natural gas.

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. Energy purchases from affiliates are made in accordance with the IIC, as approved by the FERC.

Other Operations and Maintenance Expenses

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(8)	(10.8)	$(5)	(2.4)

In the third quarter 2017, other operations and maintenance expenses were $66 million compared to $74 million for the corresponding period in 2016. The decrease was primarily due to a $5 million decrease in transmission and distribution expenses related to overhead line maintenance and a $4 million decrease related to decreases in employee compensation and benefits and corporate advertising.

For year-to-date 2017, other operations and maintenance expenses were $206 million compared to $211 million for the corresponding period in 2016. The decrease was primarily due to a $6 million decrease in transmission and distribution expenses related to overhead line maintenance and a $5 million decrease related to decreases in employee compensation and benefits and corporate advertising, partially offset by a $5 million increase associated with the Kemper IGCC in-service assets.

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See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" herein for additional information.

Depreciation and Amortization

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$9	30.0	$6	5.3

In the third quarter 2017, depreciation and amortization was $39 million compared to $30 million for the corresponding period in 2016. The increase was primarily related to $6 million in amortization and deferrals associated with regulatory assets and liabilities and $3 million in depreciation related to additional plant in service.

For year-to-date 2017, depreciation and amortization was $120 million compared to $114 million for the corresponding period in 2016. The increase was primarily related to $5 million in depreciation related to additional plant in service.

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

Taxes Other Than Income Taxes

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(6)	(19.4)	$(4)	(4.9)

In the third quarter 2017, taxes other than income taxes were $25 million compared to $31 million for the corresponding period in 2016. For year-to-date 2017, taxes other than income taxes were $77 million compared to $81 million for the corresponding period in 2016. These decreases were primarily due to a decrease in franchise taxes of $5 million and $4 million for the third quarter and year-to-date 2017, respectively, as well as a decrease in payroll taxes of $1 million for the third quarter 2017.

Estimated Loss on Kemper IGCC

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(54)	(61.4)	$2,933	N/M

N/M - Not meaningful

Estimated probable losses on the Kemper IGCC of $34 million and $3.2 billion were recorded in the third quarter and year-to-date 2017, respectively, compared to $88 million and $222 million in the third quarter and year-to-date 2016, respectively. While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable. As a result, Mississippi Power suspended the project on June 28, 2017, and recorded $34 million and $2.9 billion of additional charges to income in the third quarter and year-to-date 2017, respectively, for the estimated costs associated with the gasification portions of the plant and lignite mine.

Prior to the project's suspension, Mississippi Power recorded losses for revisions of estimated costs expected to be incurred on construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions.

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See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Allowance for Equity Funds Used During Construction

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(30)	(96.8)	$(18)	(20.0)

In the third quarter 2017, AFUDC equity was $1 million compared to $31 million for the corresponding period in 2016. For year-to-date 2017, AFUDC equity was $72 million compared to $90 million for the corresponding period in 2016. The decreases resulted from the Kemper IGCC project suspension in June 2017.

See Note 3 to the financial statements of Mississippi Power under "FERC Matters" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "FERC Matters" and "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(28)	N/M	$(23)	50.0

N/M - Not meaningful

In the third quarter 2017, interest expense, net of amounts capitalized was $(13) million compared to $15 million for the corresponding period in 2016. The decrease was primarily associated with a $33 million net reduction in interest following a settlement with the IRS related to research and experimental (R&E) deductions. Also contributing to the decrease was a $4 million decrease in interest related to long-term debt. These decreases were partially offset by an $11 million reduction in interest capitalized following suspension of the Kemper IGCC construction.

For year-to-date 2017, interest expense, net of amounts capitalized was $23 million compared to $46 million for the corresponding period in 2016. The decrease was primarily associated with a $33 million net reduction in interest following a settlement with the IRS related to R&E deductions. Also contributing to the decrease was a $2 million decrease in interest related to short-term debt and a $1 million decrease in interest related to long-term debt. These decreases were partially offset by an $8 million reduction in interest capitalized following suspension of the Kemper IGCC construction and the amortization of $7 million in interest deferrals in accordance with the In-Service Asset Rate Order.

See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Income Taxes (Benefit)

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$26	N/M	$(856)	N/M

N/M - Not meaningful

In the third quarter 2017, income taxes were $24 million compared to an income tax benefit of $2 million for the corresponding period in 2016. For year-to-date 2017, income tax benefit was $885 million compared to $29 million

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for the corresponding period in 2016. The changes were primarily due to the estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion and the related state valuation allowances.

See Note (G) 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, including those related to the remainder of the Kemper County energy facility not included in current rates, in a timely manner during a time of increasing costs and its ability to prevail against legal challenges associated with the Kemper County energy facility. Future earnings will be driven primarily by 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. 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.

On October 4, 2017, Mississippi Power executed agreements with its largest retail customer, Chevron Products Company (Chevron), to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038, subject to the approval of the Mississippi PSC. The new agreements are not expected to have a material impact on Mississippi Power's earnings; however, the co-generation assets located at the refinery are expected to be accounted for as a sales-type lease in accordance with the new lease accounting rules that become effective in 2019. These assets are also subject to a security interest granted to Chevron. See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Mississippi Power's financial statements.

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 and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through long-term wholesale agreements. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Mississippi

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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 Statutes and Regulations

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the final effluent guidelines rule and the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs.

On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.

On June 27, 2017, the EPA and the U.S. Army Corps of Engineers proposed to rescind the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.

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 Mississippi Power in Item 7 of the Form 10-K for additional information.

On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.

On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.

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

FERC Matters

Municipal and Rural Associations Tariff

See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding a settlement agreement entered into by Mississippi Power regarding the establishment of a regulatory asset for Kemper IGCC-related costs. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding the Kemper IGCC.

In March 2016, Mississippi Power reached a settlement agreement with its wholesale customers, which was subsequently approved by the FERC, for an increase in wholesale base revenues under the MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking under the In-Service Asset Rate Order. This regulatory treatment primarily includes (i) recovery of the Kemper IGCC assets currently operational and providing service to customers and other related costs, (ii)

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amortization of the Kemper IGCC-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper IGCC-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper IGCC CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC totaled approximately $22 million through the suspension of Kemper IGCC start-up activities.

See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Fuel Cost Recovery

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At September 30, 2017, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $3 million compared to $13 million at December 31, 2016. Over-recovered wholesale MB fuel costs included in the balance sheets were immaterial at September 30, 2017 and December 31, 2016.

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 the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.

On May 17, 2017, the FERC accepted the traditional electric operating companies' (including Mississippi Power's) and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies (including Mississippi Power) and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' (including Mississippi Power's) and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.

On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' (including Mississippi Power's) and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies (including Mississippi Power) and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies (including Mississippi Power) and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.

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

Cooperative Energy Shared Service Agreement and PPA

Mississippi Power provides electricity to a municipality and various rural electric cooperative associations located in southeastern Mississippi, including Cooperative Energy. These generation services are provided under long-term contracts subject to a cost-based, FERC regulated MRA electric tariff and a long-term market-based wholesale contract.

On September 18, 2017, Mississippi Power and Cooperative Energy executed a Shared Service Agreement (SSA), as part of the MRA tariff, under which Mississippi Power and Cooperative Energy will share in providing electricity to all Cooperative Energy delivery points, in lieu of the current arrangement under which each delivery point is specifically assigned to either entity. The SSA becomes effective on January 1, 2018, subject to the FERC's acceptance, and may be cancelled by Cooperative Energy with 10 years notice after December 31, 2021.

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The SSA provides Cooperative Energy the option to decrease its use of Mississippi Power's generation services under the MRA tariff, subject to annual and cumulative caps and a one-year notice requirement. In the event Cooperative Energy elects to reduce these services, the related reduction in Mississippi Power's revenues is not expected to be significant through 2020.

In 2008, Mississippi Power entered into a 10-year Power Supply Agreement (PSA) with Cooperative Energy for approximately 152 MWs, which became effective in 2011. Following certain plant retirements, the current PSA capacity is 86 MWs. On September 28, 2017, Mississippi Power and Cooperative Energy executed an amendment to the PSA effective October 1, 2017, increasing the capacity to 286 MWs under the PSA.

Cooperative Energy also has a 10-year Network Integration Transmission Service Agreement (NITSA) with SCS for transmission service to certain delivery points on the Mississippi Power transmission system that became effective in 2011. As a result of the PSA amendments, Cooperative Energy and SCS are amending the terms of the NITSA to provide for the purchase of incremental transmission capacity for service beginning April 1, 2018. This NITSA amendment remains subject to execution and acceptance by the FERC.

The ultimate outcome of these matters 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 and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are expected to be recovered through Mississippi Power's base rates. See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power" and "Integrated Coal Gasification Combined Cycle" herein for additional information.

Renewables

Mississippi Power placed in service three solar projects in January, June, and October 2017. Mississippi Power may retire the renewable energy credits (REC) generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.

On August 17, 2017, the Mississippi PSC approved Mississippi Power's CPCN for the construction, operation, and maintenance of a 52.5-MW solar energy generating facility, which is expected to be placed in service by January 2020. The ultimate outcome of this matter cannot be determined at this time.

Performance Evaluation Plan

On March 15, 2017, Mississippi Power submitted its annual PEP lookback filing for 2016, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC.

On November 15, 2017, Mississippi Power is expected to make its annual PEP filing for 2018. Retail rate adjustments under PEP are limited to 4% of annual retail revenue and are subject to Mississippi PSC approval.

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

Energy Efficiency

On July 6, 2017, the Mississippi PSC issued an order approving Mississippi Power's Energy Efficiency Cost Rider compliance filing, which increased annual retail revenues by approximately $2 million effective with the first billing cycle for August 2017.

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Environmental Compliance Overview Plan

On May 4, 2017, the Mississippi PSC approved Mississippi Power's ECO Plan filing for 2017, which requested the maximum 2% annual increase in revenues, approximately $18 million, primarily related to the Plant Daniel Units 1 and 2 scrubbers placed in service in 2015. The rates became effective with the first billing cycle for June 2017. Approximately $26 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2018 filing.

Fuel Cost Recovery

At September 30, 2017, the amount of over-recovered retail fuel costs included on the condensed balance sheet was $2 million compared to $37 million at December 31, 2016.

On November 15, 2017, Mississippi Power is expected 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.

Ad Valorem Tax Adjustment

On July 6, 2017, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2017, which included an annual rate increase of 0.85%, or $8 million in annual retail revenues, primarily due to increased assessments.

Provision for Property Damage

On October 8, 2017, Hurricane Nate hit the Gulf Coast of Mississippi causing minor damage to Mississippi Power's distribution infrastructure. Preliminary storm damage repair costs have been estimated to be immaterial. These costs may be charged to the retail property damage reserve and addressed in a subsequent System Restoration Rider rate filing. The ultimate outcome of this matter cannot be determined at this time.

Integrated Coal Gasification Combined Cycle

See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.

Kemper IGCC Overview

The Kemper IGCC was designed to utilize IGCC technology with an expected output capacity of 582 MWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed approximately 61 miles of CO₂ pipeline infrastructure for the transport of captured CO₂ for use in enhanced oil recovery.

Kemper IGCC Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of Initial DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014.

The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured

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CO₂, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has increased significantly since certification.

On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014.

Mississippi Power's Kemper IGCC 2010 project estimate totaled $2.97 billion, which included capped costs of $2.4 billion. At the time of project suspension in June 2017, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.

Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap for the Kemper IGCC of $196 million ($121 million after tax) in the second quarter through May 31, 2017 and a total of $305 million ($188 million after tax) for year-to-date through May 31, 2017. In the aggregate, Mississippi Power incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. The May 31, 2017 cost estimate included approximately $175 million of estimated costs to be incurred beyond the then-estimated in-service date of June 30, 2017 that were expected to be subject to the $2.88 billion cost cap.

While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred. In the aggregate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC totaling $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017.

As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC. The Kemper combined cycle balances as presented in the condensed balance sheet at September 30, 2017 include $1.1 billion in property, plant, and equipment, net of $80 million in accumulated depreciation; $15 million in materials and supplies; $10 million in other deferred charges and assets; and $113 million in regulatory assets, net of accumulated amortization of $63 million, of which $21 million is included in other regulatory assets, current and $92 million in other regulatory assets, deferred.

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Rate Recovery of Kemper IGCC Costs

Given the variety of potential scenarios and the uncertainty of the outcome of future regulatory proceedings with the Mississippi PSC (and any subsequent related legal challenges), the ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, cannot now be determined but could result in further material charges that could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity.

Kemper IGCC Settlement Docket

On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.

On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.

Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the MPUS), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.

While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.

As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which

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$0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.

Prudence

On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceedings and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years after the Kemper IGCC was to be placed in service. Compared to amounts presented in the 2010 CPCN proceedings, operations and maintenance expenses have increased an average of $105 million annually and maintenance capital has increased an average of $44 million annually for the first full five years of operations for the Kemper IGCC. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. On November 17, 2016, Mississippi Power submitted a supplemental filing to the October 3, 2016 compliance filing to present revised non-fuel operations and maintenance expense projections for the first year after the Kemper IGCC was to be placed in service. This supplemental filing included approximately $68 million in additional estimated operations and maintenance costs expected to be required to support the operations of the Kemper IGCC during that period.

Mississippi Power responded to numerous requests for information from interested parties in the discovery docket, which is now complete. Mississippi Power expects the Mississippi PSC to utilize this information in connection with the ultimate resolution of Kemper IGCC cost recovery.

Economic Viability Analysis

In the fourth quarter 2016, as a part of its Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected. As a result of the updated long-term natural gas forecast, as well as the revised operating expense projections reflected in the discovery docket filings discussed above, on February 21, 2017, Mississippi Power filed an updated project economic viability analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order confirming authorization of the Kemper IGCC. The project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis.

Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.

2015 Rate Case

On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full the 2015 Stipulation entered into between Mississippi Power and the MPUS regarding the Kemper IGCC assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual

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average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by Cooperative Energy but reserved Mississippi Power's right to seek recovery in a future proceeding. See "Termination of Proposed Sale of Undivided Interest" herein for additional information.

In 2011, the Mississippi PSC authorized Mississippi Power to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date. In connection with the implementation of the In-Service Asset Order and wholesale rates, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of September 30, 2017, the balance associated with these regulatory assets was $113 million, of which $21 million is included in current assets. See "FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.

The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, for the May 31, 2016 and 2017 calculations. At September 30, 2017, Mississippi Power's related regulatory liability totaled approximately $10 million.

As required by the In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in the In-Service Asset Order in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable. At September 30, 2017, the related regulatory liability totaled $7 million.

2013 MPSC Rate Order

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC was placed in service, based on a mirror CWIP methodology (Mirror CWIP rate).

On February 12, 2015, the Mississippi Supreme Court reversed the 2013 MPSC Rate Order and, on July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million previously collected, along with associated carrying costs of $29 million.

Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continued to record AFUDC on the Kemper IGCC. Between the original May 2014 estimated in-service date and the June 2017 project suspension date, Mississippi Power recorded $494 million of AFUDC on the Kemper IGCC subject to the $2.88 billion cost cap and Cost Cap Exception amounts, of which $460 million related to the gasification portions of the Kemper IGCC.

Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.

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Lignite Mine and CO₂ Pipeline Facilities

In conjunction with the Kemper IGCC, Mississippi Power owns the lignite mine and equipment and mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.

In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is responsible for the mining operations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. During the suspension period, these costs are approximately $2 million per month and are being recognized in income as incurred. See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.

In addition, Mississippi Power constructed the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery. Mississippi Power entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC (Treetop), pursuant to which Denbury would purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop would purchase 30% of the CO₂ captured from the Kemper IGCC. On June 3, 2016, Mississippi Power cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury's agreement to purchase 100% of the CO₂ captured from the Kemper IGCC and an initial contract term of 16 years. Denbury has the right to terminate the contract at any time because Mississippi Power did not place the Kemper IGCC in service by July 1, 2017.

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

Termination of Proposed Sale of Undivided Interest

In 2010 and as amended in 2012, Mississippi Power and Cooperative Energy (formerly known as SMEPA) entered into an agreement whereby Cooperative Energy agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, Cooperative Energy notified Mississippi Power of its termination of the agreement. Mississippi Power previously received a total of $275 million of deposits from Cooperative Energy that were required to be returned to Cooperative Energy with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to Cooperative Energy. Subsequently, Mississippi Power issued a promissory note in the aggregate principal amount of approximately $301 million to Southern Company, which was repaid in June 2017.

Litigation

On April 26, 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 on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have 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 IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal.

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On June 9, 2016, Treetop, Greenleaf CO₂ Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO₂ contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO₂ contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages.

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

Baseload Act

In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery or implement credits, refunds, or rebates to customers for costs incurred in connection with such cancelled generating plant.

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 Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information on bonus depreciation, investment tax credits, and the Section 174 research and experimental deduction.

Bonus Depreciation

All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. If the suspension of the Kemper IGCC start-up activities ultimately results in an abandonment for income tax purposes, the related deduction would be claimed in the year of the abandonment. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein and Note (G) to the Condensed Financial Statements herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

Section 174 Research and Experimental Deduction

Southern Company, on behalf of Mississippi Power, has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the JCT approval, Mississippi Power recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Section 174 Research and Experimental Deduction," respectively, herein for additional information.

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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 regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, 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.

The SEC is conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company and Mississippi Power believe the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on the Kemper IGCC. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Mississippi Power.

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 related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, AFUDC, Unbilled Revenues, and Contingent Obligations.

Kemper IGCC Rate Recovery

For periods prior to the second quarter 2017, significant accounting estimates included Kemper IGCC estimated construction costs, project completion date, and rate recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery" of Mississippi Power in Item 7 of the Form 10-K for additional information. Mississippi Power recorded total pre-tax charges to income related to the Kemper IGCC of $428 million ($264 million after tax) in 2016, $365 million ($226 million after tax) in 2015, $868 million ($536 million after tax) in 2014, and $1.2 billion ($729 million after tax) in prior years.

As a result of the Mississippi PSC's June 21, 2017 stated intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant rather than an IGCC plant, as well as Mississippi Power's June 28, 2017 suspension of the operation and start-up of the gasifier portion of the Kemper IGCC, the estimated construction costs and

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project completion date are no longer considered significant accounting estimates. Significant accounting estimates for the September 30, 2017 financial statements presented herein include the overall assessment of rate recovery for the Kemper County energy facility and the estimated costs for the potential cancellation of the Kemper IGCC.

While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.

As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.

In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.00 billion ($3.96 billion after tax) through September 30, 2017. Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $34 million ($21 million after tax) and $88 million ($54 million after tax) in the third quarter 2017 and the third quarter 2016, respectively, and total pre-tax charges of $3.2 billion ($2.2 billion after tax) and $222 million ($137 million after tax) year-to-date in 2017 and 2016, respectively.

Given the significant judgment involved in estimating the costs to cancel the gasifier portion of the Kemper IGCC, the ultimate rate recovery for the Kemper IGCC, including the $0.5 billion of combined cycle-related costs not yet in rates, and the impact on Mississippi Power's results of operations, Mississippi Power considers these items to be critical accounting estimates. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" 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.

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. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While Mississippi Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Mississippi Power's revenue, including

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energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Mississippi Power expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.

Mississippi Power's ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Mississippi Power's financial statements, if material. In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Mississippi Power expects CIAC to be out of the scope of ASC 606.

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Mississippi Power intends to use the modified retrospective method of adoption effective January 1, 2018. Mississippi Power has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Mississippi Power's financial statements, Mississippi Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.

On March 10, 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 income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Mississippi Power's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Mississippi Power's financial statements.

On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. 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 and interim periods within those fiscal years, with early adoption permitted. Mississippi Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Mississippi Power's financial statements.

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FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Earnings for the nine months ended September 30, 2017 were negatively affected by revisions to the cost estimate for the Kemper IGCC.

Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows through 2022. Projected capital expenditures in that period include investments to maintain existing generation facilities, to add environmental modifications to existing generating units, and to expand and improve transmission and distribution facilities.

In the second quarter 2017, Mississippi Power borrowed an additional $40 million under a promissory note issued to Southern Company. In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of the proceeds to prepay $901 million of outstanding debt.

As of September 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $769 million primarily due to $935 million in long-term debt that matures within the next 12 months and $94 million of short-term debt. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans, as market conditions permit, as well as, under certain circumstances, commercial paper and/or equity contributions and/or loans from Southern Company to fund Mississippi Power's short-term capital needs.

Net cash provided from operating activities totaled $361 million for the first nine months of 2017, a decrease of $12 million as compared to the corresponding period in 2016. The decrease in cash provided from operating activities is primarily due to deferred income taxes related to the Kemper IGCC, partially offset by the timing of payments received from affiliates and customers and the completion of Mirror CWIP refunds in 2016. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" herein for additional information. Net cash used for investing activities totaled $483 million for the first nine months of 2017 primarily due to gross property additions related to the Kemper IGCC. Net cash provided from financing activities totaled $129 million for the first nine months of 2017 primarily due to capital contributions from Southern Company, partially offset by redemptions of long-term debt 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 2017 include an increase in paid-in capital of $1.0 billion due to capital contributions from Southern Company, a portion of which was used to repay $300 million of securities due within one year, $591 million of long-term debt, and $10 million of short-term debt. Securities due within one year decreased $551 million due to the repayment of promissory notes to Southern Company. Long-term debt decreased primarily due to the reclassification of $1.2 billion in unsecured term loans to securities due within one year. Other significant changes include decreases of $2.5 billion in CWIP, $756 million in accumulated deferred income taxes, and $299 million in deferred charges related to income taxes. All of these changes primarily resulted from the Kemper IGCC suspension and related estimated loss. Income taxes receivable and unrecognized tax benefits also decreased due to tax refunds associated with the IRS Section 174 R&E settlement. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Section 174 Research and Experimental Deduction," respectively, herein for additional information.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power's capital requirements for its construction program, including estimated capital expenditures for new generating resources and to comply with existing environmental statutes and regulations,

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scheduled maturities of long-term debt, as well as related interest, leases, purchase commitments, derivative obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. Approximately $935 million will be required through September 30, 2018 to fund maturities of long-term debt and $4 million will be required to fund maturities of short-term debt. In addition, Mississippi Power has $40 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilities and $50 million of fixed rate pollution control revenue bonds that are required to be remarketed over the next 12 months. See "Sources of Capital" and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information.

The construction program of Mississippi Power is currently estimated to be $582 million for 2017, $203 million for 2018, $177 million for 2019, $204 million for 2020, $199 million for 2021, and $240 million for 2022. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or future state plans that would limit CO₂ emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.

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 statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing 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.

Sources of Capital

Mississippi Power plans to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, and/or short-term debt, as well as, under certain circumstances, equity contributions and/or loans from Southern Company. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which includes resolution of the Kemper County energy facility cost recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" and – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" of Mississippi Power in Item 7 of the Form 10-K for additional information.

On February 28, 2017, the maturity dates for $551 million in promissory notes to Southern Company were extended to July 31, 2018. In the second quarter 2017, Mississippi Power borrowed an additional $40 million under a promissory note issued to Southern Company. In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay $10 million of the outstanding principal amount of bank loans.

In September 2017, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. Mississippi Power borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures. See Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information.

As of September 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $769 million primarily due to $935 million in long-term debt that matures within the next 12 months and $94 million of short-term debt. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans, as

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market conditions permit, as well as, under certain circumstances, commercial paper and/or equity contributions and/or loans from Southern Company to fund Mississippi Power's short-term capital needs. Specifically, Mississippi Power has been informed by Southern Company that in the event sufficient funds are not available from external sources, Southern Company intends to provide Mississippi Power with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Going Concern" herein.

At September 30, 2017, Mississippi Power had approximately $231 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:

Expires						Executable Term Loans				Expires Within One Year
2017		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)
$	100	$	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 (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

Most of these bank credit arrangements, as well as Mississippi Power's term loan agreement, contain covenants that limit debt levels and typically 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, 2017, Mississippi Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.

Subject to applicable market conditions, Mississippi Power expects to 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 pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2017 was approximately $40 million. In addition, at September 30, 2017, Mississippi Power had approximately $50 million of fixed rate pollution control 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 at September 30, 2017			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)
Short-term bank debt	$	4	3.8%	$	28	2.8%	$	126

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017.

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Credit Rating Risk

At September 30, 2017, 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 4, 2017, Mississippi Power executed agreements with its largest retail customer, Chevron, 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 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, 2017, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $255 million.

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

On March 1, 2017, Moody's downgraded the senior unsecured debt rating of Mississippi Power to Ba1 from Baa3.

On March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Mississippi Power) from stable to negative.

On March 30, 2017, Fitch placed the ratings of Mississippi Power on rating watch negative.

On June 22, 2017, Moody's placed the ratings of Mississippi Power on review for downgrade. On September 21, 2017, Moody's revised its rating outlook for Mississippi Power from under review to stable.

Financing Activities

In March 2017, Mississippi Power issued a $9 million short-term bank note bearing interest at 5% per annum, which was repaid in April 2017.

In February 2017, Mississippi Power amended $551 million in promissory notes to Southern Company extending the maturity dates of the notes from December 1, 2017 to July 31, 2018. In the second quarter 2017, Mississippi Power borrowed an additional $40 million under a promissory note issued to Southern Company.

In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay a $10 million short-term bank loan.

In August 2017, Mississippi Power repaid a $12.5 million short-term bank note.

In September 2017, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. Mississippi Power borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures. See Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information.

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In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Mississippi Power plans, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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AND SUBSIDIARY COMPANIES

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	510		$	387		$	1,293		$	866
Wholesale revenues, affiliates	105			110			295			313
Other revenues	3			3			9			10
Total operating revenues	618			500			1,597			1,189
Operating Expenses:
Fuel	189			154			460			341
Purchased power, non-affiliates	36			25			90			60
Purchased power, affiliates	7			8			23			16
Other operations and maintenance	83			81			272			246
Depreciation and amortization	131			93			379			247
Taxes other than income taxes	13			5			37			17
Total operating expenses	459			366			1,261			927
Operating Income	159			134			336			262
Other Income and (Expense):
Interest expense, net of amounts capitalized	(47		)	(35		)	(144		)	(78		)
Other income (expense), net	3			2			3			3
Total other income and (expense)	(44		)	(33		)	(141		)	(75		)
Earnings Before Income Taxes	115			101			195			187
Income taxes (benefit)	(39		)	(102		)	(129		)	(167		)
Net Income	154			203			324			354
Less: Net income attributable to noncontrolling interests	30			27			48			39
Net Income Attributable to Southern Power	$	124		$	176		$	276		$	315

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Net Income	$	154		$	203		$	324		$	354
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $15, $14, $35, and $(1), respectively	25			23			58			(1		)
Reclassification adjustment for amounts included in net income, net of tax of $(12), $(1), $(42), and $7, respectively	(20		)	(1		)	(68		)	13
Total other comprehensive income (loss)	5			22			(10		)	12
Comprehensive Income	159			225			314			366
Less: Comprehensive income attributable to noncontrolling interests	30			27			48			39
Comprehensive Income Attributable to Southern Power	$	129		$	198		$	266		$	327

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,
	2017			2016
	(in millions)
Operating Activities:
Net income	$	324		$	354
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	404			262
Deferred income taxes	240			(668		)
Amortization of investment tax credits	(42		)	(25		)
Collateral deposits	(1		)	(80		)
Income taxes receivable, non-current	(42		)	—
Other, net	(2		)	19
Changes in certain current assets and liabilities —
-Receivables	(77		)	(82		)
-Other current assets	38			(15		)
-Accounts payable	(31		)	7
-Accrued taxes	79			483
-Other current liabilities	5			14
Net cash provided from operating activities	895			269
Investing Activities:
Business acquisitions	(1,032		)	(1,134		)
Property additions	(218		)	(1,702		)
Change in construction payables	(166		)	(69		)
Payments pursuant to LTSAs	(99		)	(58		)
Investment in restricted cash	(16		)	(750		)
Distribution of restricted cash	33			746
Other investing activities	7			(41		)
Net cash used for investing activities	(1,491		)	(3,008		)
Financing Activities:
Increase (decrease) in notes payable, net	(89		)	692
Proceeds —
Senior notes	—			1,531
Capital contributions from parent company	—			800
Other long-term debt	43			63
Redemptions — Other long-term debt	(4		)	(84		)
Distributions to noncontrolling interests	(89		)	(22		)
Capital contributions from noncontrolling interests	79			367
Purchase of membership interests from noncontrolling interests	—			(129		)
Payment of common stock dividends	(238		)	(204		)
Other financing activities	(27		)	(14		)
Net cash provided from (used for) financing activities	(325		)	3,000
Net Change in Cash and Cash Equivalents	(921		)	261
Cash and Cash Equivalents at Beginning of Period	1,099			830
Cash and Cash Equivalents at End of Period	$	178		$	1,091
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $7 and $32 capitalized for 2017 and 2016, respectively)	$	144		$	49
Income taxes, net	(343		)	71
Noncash transactions — Accrued property additions at end of period	16			210

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2017		At December 31, 2016
	(in millions)
Current Assets:
Cash and cash equivalents	$	178	$	1,099
Receivables —
Customer accounts receivable	148		102
Other	61		34
Affiliated	74		57
Fossil fuel stock	15		15
Materials and supplies	351		337
Prepaid income taxes	51		74
Other current assets	26		39
Total current assets	904		1,757
Property, Plant, and Equipment:
In service	13,734		12,728
Less: Accumulated provision for depreciation	1,823		1,484
Plant in service, net of depreciation	11,911		11,244
Construction work in progress	425		398
Total property, plant, and equipment	12,336		11,642
Other Property and Investments:
Intangible assets, net of amortization of $41 and $22 at September 30, 2017 and December 31, 2016, respectively	417		436
Total other property and investments	417		436
Deferred Charges and Other Assets:
Prepaid LTSAs	77		101
Accumulated deferred income taxes	400		594
Income taxes receivable, non-current	53		11
Other deferred charges and assets — affiliated	6		13
Other deferred charges and assets — non-affiliated	455		615
Total deferred charges and other assets	991		1,334
Total Assets	$	14,648	$	15,169

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At September 30, 2017		At December 31, 2016
	(in millions)
Current Liabilities:
Securities due within one year	$	864	$	560
Notes payable	120		209
Accounts payable —
Affiliated	93		88
Other	84		278
Accrued taxes —
Accrued income taxes	101		148
Other accrued taxes	30		7
Accrued interest	36		36
Acquisitions payable	—		461
Contingent consideration	15		46
Other current liabilities	58		70
Total current liabilities	1,401		1,903
Long-term Debt	4,946		5,068
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	191		152
Accumulated deferred ITCs	1,900		1,839
Asset retirement obligations	76		64
Other deferred credits and liabilities	232		304
Total deferred credits and other liabilities	2,399		2,359
Total Liabilities	8,746		9,330
Redeemable Noncontrolling Interests	59		164
Common Stockholder's Equity:
Common stock, par value $.01 per share —
Authorized — 1,000,000 shares
Outstanding — 1,000 shares	—		—
Paid-in capital	3,661		3,671
Retained earnings	762		724
Accumulated other comprehensive income	25		35
Total common stockholder's equity	4,448		4,430
Noncontrolling interests	1,395		1,245
Total stockholders' equity	5,843		5,675
Total Liabilities and Stockholders' Equity	$	14,648	$	15,169

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 2017 vs. THIRD QUARTER 2016

AND

YEAR-TO-DATE 2017 vs. YEAR-TO-DATE 2016

OVERVIEW

Southern Power 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 and sales of assets, construction and development of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, and other load-serving entities, as well as commercial and industrial customers. In general, Southern Power has constructed or acquired new generating capacity only after entering into or assuming long-term PPAs for the new facilities.

During the nine months ended September 30, 2017, Southern Power acquired or completed the construction of, and placed in service, approximately 498 MWs of solar and wind facilities. In addition, Southern Power began construction at the recently acquired Cactus Flats wind facility, continued development of its portfolio of wind projects, and continued expansion of the Mankato natural gas facility by 345 MWs of capacity. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.

Southern Power is considering the sale of up to a one-third equity interest in its solar asset portfolio. The ultimate outcome of this matter cannot be determined at this time.

At September 30, 2017, Southern Power had an average investment coverage ratio of 91% through 2021 and 90% through 2026, with an average remaining contract duration of approximately 16 years. These ratios include the PPAs and capacity associated with facilities currently under construction and acquisitions discussed herein. See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein for additional information.

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.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$(52)	(29.5)	$(39)	(12.4)

Net income attributable to Southern Power for the third quarter 2017 was $124 million compared to $176 million for the corresponding period in 2016. The decrease was primarily due to decreased income tax benefits from solar ITCs and increased interest expense primarily due to a decrease in capitalized interest associated with completing construction of and placing in service solar facilities, partially offset by additional operating income related to new generating facilities.

Net income attributable to Southern Power for year-to-date 2017 was $276 million compared to $315 million for the corresponding period in 2016. The decrease was primarily due to decreased income tax benefits resulting from a reduction in solar ITCs, partially offset by an increase in wind PTCs, and increased interest expense from debt issuances to fund Southern Power's growth strategy and continuous construction program, partially offset by additional operating income from new generating facilities.

For additional information on new generating facilities placed in service during 2016 and 2017, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and

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"Construction Projects" of Southern Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein.

Operating Revenues

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$118	23.6	$408	34.3

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, which include sales from Southern Power's natural gas, biomass, solar, and wind 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 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, and other factors.

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

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

	Third Quarter 2017		Third Quarter 2016		Year-to-Date 2017		Year-to-Date 2016
	(in millions)
PPA capacity revenues	$	169	$	149	$	466	$	406
PPA energy revenues	299		247		765		532
Total PPA revenues	468		396		1,231		938
Non-PPA revenues	147		101		357		241
Other revenues	3		3		9		10
Total operating revenues	$	618	$	500	$	1,597	$	1,189

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the third quarter 2017, total operating revenues were $618 million, reflecting a $118 million, or 24%, increase from the corresponding period in 2016. The increase in operating revenues was primarily due to the following:

• PPA capacity revenues increased $20 million, or 13%, primarily due to additional customer capacity requirements and a new PPA related to natural gas facilities.

• PPA energy revenues increased $52 million, or 21%, primarily due to a $55 million increase in sales from new solar and wind facilities, partially offset by a $3 million decrease in sales from natural gas PPAs due to a $24 million decrease in volume primarily due to the expiration of a PPA and reduced customer load, partially offset by a $21 million increase in the average cost of fuel.

• Non-PPA revenues increased $46 million, or 46%, due to a $58 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, offset by a $12 million decrease in the price of energy in the wholesale markets.

For year-to-date 2017, total operating revenues were $1.6 billion, reflecting a $408 million, or 34%, increase from the corresponding period in 2016. The increase in operating revenues was primarily due to the following:

• PPA capacity revenues increased $60 million, or 15%, primarily due to additional customer capacity requirements and a new PPA related to natural gas facilities.

• PPA energy revenues increased $233 million, or 44%, primarily due to a $188 million increase in sales from new solar and wind facilities and a $35 million increase in sales from natural gas PPAs primarily due to a $69 million increase in the average cost of fuel, partially offset by a $34 million decrease in volume primarily due to the expiration of a PPA and reduced customer load.

• Non-PPA revenues increased $116 million, or 48%, due to a $104 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, as well as a $12 million increase in the price of energy in the wholesale markets.

Fuel and Purchased Power Expenses

Fuel costs constitute the single largest expense for Southern Power. In addition, Southern Power purchases a portion of its electricity needs from the wholesale market. Details of Southern Power's generation and purchased power were as follows:

	Third Quarter 2017	Third Quarter 2016	Year-to-Date 2017	Year-to-Date 2016
	(in billions of KWHs)
Generation	12.5	11.1	33.2	27.9
Purchased power	1.2	0.9	3.4	2.5
Total generation and purchased power	13.7	12.0	36.6	30.4
Total generation and purchased power, excluding solar, wind, and tolling agreements	7.2	6.7	17.8	17.7

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.

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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 2017 vs. Third Quarter 2016			Year-to-Date 2017 vs. Year-to-Date 2016
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	35	22.7	$	119	34.9
Purchased power	10		30.3	37		48.7
Total fuel and purchased power expenses	$	45		$	156

In the third quarter 2017, total fuel and purchased power expenses increased $45 million, or 24.1%, compared to the corresponding period in 2016. Fuel expense increased $35 million primarily due to a $29 million increase in the average cost of natural gas per KWH generated and an $8 million increase in the volume of KWHs generated, excluding solar, wind, and tolling agreements. Purchased power expense increased $10 million primarily due to an increase in the volume of KWHs purchased.

For year-to-date 2017, total fuel and purchased power expenses increased $156 million, or 37.4%, compared to the corresponding period in 2016. Fuel expense increased $119 million primarily due to a $139 million increase in the average cost of natural gas per KWH generated, partially offset by a $19 million decrease in the volume of KWHs generated, excluding solar, wind, and tolling agreements. Purchased power expense increased $37 million due to a $28 million increase in the volume of KWHs purchased and a $9 million increase associated with the average cost of purchased power.

Other Operations and Maintenance Expenses

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$2	2.5	$26	10.6

In the third quarter 2017, other operations and maintenance expenses were $83 million compared to $81 million for the corresponding period in 2016. The increase was primarily due to a $13 million increase associated with new solar, wind, and gas facilities, partially offset by a $5 million decrease in scheduled outage maintenance expenses and a $5 million decrease in non-outage operations and maintenance expenses.

For year-to-date 2017, other operations and maintenance expenses were $272 million compared to $246 million for the corresponding period in 2016. The increase was primarily due to a $48 million increase associated with new solar, wind, and gas facilities and an $8 million increase associated with employee compensation and expenses in support of Southern Power's overall growth strategy, partially offset by a $22 million decrease in scheduled outage maintenance expenses and an $8 million decrease in non-outage operations and maintenance expenses.

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Depreciation and Amortization

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$38	40.9	$132	53.4

In the third quarter 2017, depreciation and amortization was $131 million compared to $93 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $379 million compared to $247 million for the corresponding period in 2016. The increases were primarily due to new solar, wind, and gas facilities placed in service.

Taxes Other Than Income Taxes

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$8	160.0	$20	117.6

In the third quarter 2017, taxes other than income taxes were $13 million compared to $5 million for the corresponding period in 2016. For year-to-date 2017, taxes other than income taxes were $37 million compared to $17 million for the corresponding period in 2016. These increases were primarily due to additional property taxes due to new solar, wind, and gas facilities.

Interest Expense, net of Amounts Capitalized

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$12	34.3	$66	84.6

In the third quarter 2017, interest expense, net of amounts capitalized was $47 million compared to $35 million for the corresponding period in 2016. The increase was primarily due to an $8 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities and an increase of $3 million in interest expense due to an increase in average outstanding long-term debt, primarily to fund Southern Power's growth strategy and continuous construction program.

For year-to-date 2017, interest expense, net of amounts capitalized was $144 million compared to $78 million for the corresponding period in 2016. The increase was primarily due to an increase of $39 million in interest expense due to an increase in average outstanding long-term debt, primarily to fund Southern Power's growth strategy and continuous construction program, as well as a $25 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities.

Other Income (Expense), Net

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$1	50.0	$—	—

In the third quarter 2017, other income (expense), net was $3 million compared to $2 million for the corresponding period in 2016. Other income (expense), net was $3 million for both year-to-date 2017 and 2016. The changes include increases of $36 million and $152 million from currency losses arising from translation of €1.1 billion euro-denominated fixed-rate notes into U.S. dollars for the third quarter and year-to-date 2017, respectively, fully offset by an equal change in gains on the foreign currency hedges that were reclassified from accumulated OCI into earnings. See Note (H) to the Condensed Financial Statements herein for additional information.

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Income Taxes (Benefit)

Third Quarter 2017 vs. Third Quarter 2016		Year-to-Date 2017 vs. Year-to-Date 2016
(change in millions)	(% change)	(change in millions)	(% change)
$63	61.8	$38	22.8

In the third quarter 2017, income tax benefit was $39 million compared to $102 million for the corresponding period in 2016. The decrease was primarily due to a $61 million decrease in income tax benefits from solar ITCs.

For year-to-date 2017, income tax benefit was $129 million compared to $167 million for the corresponding period in 2016. The decrease was primarily due to a $102 million decrease in income tax benefits from solar ITCs, partially offset by a $58 million increase in wind PTCs and a $4 million increase resulting from state apportionment rate changes.

See Note (G) to the Condensed Financial Statements herein for additional information on income taxes and Note 1 to the financial statements of Southern Power under "Income and Other Taxes" in Item 8 of the Form 10-K for additional information on ITCs and PTCs.

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; Southern Power's ability to execute its growth strategy, including successful additional investments in renewable and other energy projects, and to develop and construct generating facilities. Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals, including any potential changes to the availability or realizability of ITCs and PTCs, is dependent on the final form of any legislation enacted and the related transition rules, and cannot be determined at this time, but could have a material impact on Southern Power's consolidated financial statements.

Southern Power is considering the sale of up to a one-third equity interest in its solar asset portfolio. 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, demand, cost of generation from facilities 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, 2017, Southern Power's average investment coverage ratio for its generating assets, based on the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction) as the investment amount, was 91% through 2021 and 90% through 2026, with an average remaining contract duration of approximately 16 years.

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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.

Environmental Statutes and Regulations

Water Quality

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

On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. On September 18, 2017, the EPA published a final rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.

The ultimate outcome of this matter 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 Power in Item 7 of the Form 10-K for additional information.

On March 28, 2017, the U.S. President signed an executive order directing agencies to review actions that potentially burden the development or use of domestically produced energy resources. The executive order specifically directs the EPA to review the Clean Power Plan and final greenhouse gas emission standards for new, modified, and reconstructed electric generating units and, if appropriate, take action to suspend, revise, or rescind those rules. On October 16, 2017, the EPA published a proposed rule to repeal the Clean Power Plan. The EPA has not determined whether or when it will promulgate a replacement rule.

On June 1, 2017, the U.S. President announced that the United States will withdraw from the non-binding Paris Agreement and begin renegotiation of its terms.

The ultimate outcome of these matters 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 the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.

On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.

On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017

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order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.

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

Acquisitions

During the nine months ended September 30, 2017, in accordance with Southern Power's overall growth strategy, one of Southern Power's wholly-owned subsidiaries acquired the project discussed below. Acquisition-related costs were expensed as incurred and were not material. See Note (I) 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
Bethel	Wind	276	Castro County, TX	100	%	January 2017	Google Energy, LLC	12 years

The aggregate amounts of revenue and net income recognized by Southern Power related to the Bethel facility included in Southern Power's condensed consolidated statements of income for year-to-date 2017 were immaterial. The Bethel facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service; therefore, supplemental pro forma information as though the acquisition occurred as of the beginning of 2017 and for the comparable 2016 period is not meaningful and has been omitted.

Subsequent to September 30, 2017, Southern Power purchased all of the redeemable noncontrolling interests, representing10%of the membership interests, in Southern Turner Renewable Energy, LLC and repaid$14 millionof notes payable to Turner Renewable Energy, LLC.

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 Completed and in Progress

During the nine months ended September 30, 2017, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through September 30, 2017, total costs of construction incurred for these projects were $494 million, of which $122 million remained in CWIP. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $360 million and $415 million for the Mankato and Cactus Flats facilities. The ultimate outcome of these matters cannot be determined at this time.

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Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Counterparties	PPA Contract Period
Projects Completed During the Nine Months Ended September 30, 2017
East Pecos	Solar	120	Pecos County, TX	March 2017	Austin Energy	15 years
Lamesa	Solar	102	Dawson County, TX	April 2017	City of Garland, Texas	15 years
Projects Under Construction as of September 30, 2017
Cactus Flats(*)	Wind	148	Concho County, TX	Third quarter 2018	General Motors, LLC and General Mills Operations, LLC	12 years and 15 years
Mankato	Natural Gas	345	Mankato, MN	Second quarter 2019	Northern States Power Company	20 years

(*) On July 31, 2017, Southern Power acquired a 100% ownership interest in the Cactus Flats facility, which is in the early stages of construction, from RES America Developments, Inc.

Development Projects

In December 2016, as part of Southern Power's renewable development strategy, one of Southern Power's wholly-owned subsidiaries entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects. Also in December 2016, Southern Power signed agreements and made payments to purchase wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. All of the wind turbine equipment was delivered by April 2017, which allows the projects to qualify for 100% PTCs for 10 years following their expected commercial operation dates between 2018 and 2020. 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 Note (G) to the Condensed Financial Statements herein for additional information.

During the third quarter 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate solar facilities, including certain subsidiaries owned in partnership with various third parties. Southern Power's ownership interests in the various solar entities and facilities will not be affected by the reorganization. The reorganization is expected to result in estimated tax benefits totaling approximately $40 million that will be recorded in the fourth quarter 2017 related to certain changes in state apportionment rates and net operating loss carryforward utilization. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Power is subject to certain claims and legal actions arising in the ordinary course of business. Southern Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, 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

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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.

During 2015, Southern Power indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas, which was under construction by Recurrent Energy, LLC and was subsequently placed in service in November 2016. Prior to placing the facility in service, certain solar panels were damaged during installation. While the facility currently is generating energy consistent with operational expectations and PPA obligations, Southern Power is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. In connection therewith, Southern Power is withholding payments of approximately $26 million from the construction contractor, who has placed a lien on the Roserock facility for the same amount. The amounts withheld are included in other accounts payable and other current liabilities on Southern Power's consolidated balance sheets. On May 18, 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, against X.L. America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from a hail storm and certain installation practices by the construction contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthy in the state district court in Travis County, Texas alleging breach of contract and breach of warranty for the damages sustained at the Roserock facility, which has since been moved to the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filed a counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things, breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. Southern Power intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Power prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in 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 related to Revenue Recognition, Impairment of Long-Lived Assets and Intangibles, Acquisition Accounting, and ITCs.

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.

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. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While Southern Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. However, given Southern Power's core activities of selling generation capacity and energy to high credit rated customers, Southern Power currently does not expect the new standard to have a significant impact to net income. Southern Power's ongoing evaluation of revenue streams and

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related contracts includes the evaluation of identified revenue streams tied to longer-term contractual arrangements, such as certain capacity and energy payments under PPAs that are expected to be excluded from the scope of ASC 606 and included in the scope of the current leasing guidance (ASC 840).

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Power intends to use the modified retrospective method of adoption effective January 1, 2018. Southern Power has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Southern Power's financial statements, Southern Power will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.

On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. 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 and interim periods within those fiscal years, with early adoption permitted. Southern Power is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Southern Power's financial statements.

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, 2017. 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.

Southern Power anticipates utilizing third-party tax equity as one of the financing sources to fund its renewable growth strategy; however, the use of third-party tax equity structures is not expected to have a material impact on future earnings. Subsequent to September 30, 2017, Southern Power secured third-party tax equity funding for the recently acquired Cactus Flats project subject to achieving commercial operation and various other customary conditions to closing. The ultimate outcome of this matter cannot be determined at this time.

Net cash provided from operating activities totaled $895 million for the first nine months of 2017 compared to $269 million for the first nine months of 2016. The increase in net cash provided from operating activities was primarily due to income tax refunds received and an increase in energy sales arising from new solar and wind facilities, partially offset by an increase in interest paid. 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 $1.5 billion for the first nine months of 2017 primarily due to payments for renewable acquisitions and the construction of generating facilities. Net cash used for financing activities totaled $325 million for the first nine months of 2017 primarily due to common stock dividend payments, a decrease in notes payable, and distributions to noncontrolling interests, partially offset by capital contributions from noncontrolling interests. Cash flows from financing activities may vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first nine months of 2017 include a $1.0 billion increase in property, plant,

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and equipment in-service primarily related to acquisitions and completing construction of and placing in service solar facilities, a $921 million decrease in cash and cash equivalents, and a $461 million decrease in acquisitions payable.

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

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, leases, unrecognized tax benefits, and other purchase commitments. Approximately $864 million will be required to repay maturities of long-term debt through September 30, 2018.

Southern Power's construction program includes estimates for potential plant acquisitions, new construction and development, capital improvements, and work to be performed under LTSAs and is subject to periodic review and revision. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Actual capital 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 statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in FERC rules and regulations; changes in load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note (I) to the Condensed Financial Statements 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, short-term debt, securities issuances, term loans, tax equity partnership contributions, 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.

As of September 30, 2017, Southern Power's current liabilities exceeded current assets by $497 million due to long-term debt maturing in the next 12 months, the use of short-term debt as a funding source, and fluctuations in cash needs, due to both seasonality and the stage of acquisitions and construction projects. 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, 2017, Southern Power had cash and cash equivalents of approximately $178 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 sheet at September 30, 2017.

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Details of commercial paper were as follows:

	Short-term Debt at September 30, 2017				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	$	120	1.5	%	$	322	1.5	%	$	416

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2017.

At September 30, 2017, 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. In May 2017, Southern Power amended the Facility, which, among other things, extended the maturity date from 2020 to 2022 and increased Southern Power's borrowing ability under this Facility to $750 million from $600 million. 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 (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

The Facility, as well as Southern Power's term loan agreement, contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 65% and contains a cross-default provision that is restricted only to indebtedness of Southern Power. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of Southern Power to the extent such debt is non-recourse to Southern Power, and capitalization excludes the capital stock or other equity attributable to such subsidiary. Southern Power is currently in compliance with all covenants in the Facility.

Southern Power also has a $120 million continuing letter of credit facility for standby letters of credit expiring in 2019. At September 30, 2017, $111 million has been used for letters of credit and $9 million remains unused.

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.

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The maximum potential collateral requirements under these contracts at September 30, 2017 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	37
At BBB- and/or Baa3	$	398
At BB+ and/or Ba1(*)	$	1,124

(*) 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 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 March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Southern Power) from stable to negative.

Financing Activities

In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate bank loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes.

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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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	Successor												Predecessor
	For the Three Months Ended September 30,			For the Three Months Ended September 30,			For the Nine Months Ended September 30,			July 1, 2016 through September 30,			January 1, 2016 through June 30,
	2017			2016			2017			2016			2016
	(in millions)												(in millions)
Operating Revenues:
Natural gas revenues (includes revenue taxes of $9, $9, $75, $9, and $57 for the periods presented, respectively)	$	532		$	518		$	2,746		$	518		$	1,841
Other revenues	33			25			95			25			64
Total operating revenues	565			543			2,841			543			1,905
Operating Expenses:
Cost of natural gas	134			133			1,085			133			755
Cost of other sales	7			2			20			2			14
Other operations and maintenance	205			216			671			216			454
Depreciation and amortization	125			116			370			116			206
Taxes other than income taxes	26			29			140			29			99
Merger-related expenses	—			35			—			35			56
Total operating expenses	497			531			2,286			531			1,584
Operating Income	68			12			555			12			321
Other Income and (Expense):
Earnings from equity method investments	32			29			100			29			2
Interest expense, net of amounts capitalized	(51		)	(39		)	(145		)	(39		)	(96		)
Other income (expense), net	18			9			26			9			5
Total other income and (expense)	(1		)	(1		)	(19		)	(1		)	(89		)
Earnings Before Income Taxes	67			11			536			11			232
Income taxes	52			7			233			7			87
Net Income	15			4			303			4			145
Less: Net income attributable to noncontrolling interest	—			—			—			—			14
Net Income Attributable to Southern Company Gas	$	15		$	4		$	303		$	4		$	131

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 COMPREHENSIVE INCOME (UNAUDITED)

	Successor											Predecessor
	For the Three Months Ended September 30,		For the Three Months Ended September 30,			For the Nine Months Ended September 30,			July 1, 2016 through September 30,			January 1, 2016 through June 30,
	2017		2016			2017			2016			2016
	(in millions)											(in millions)
Net Income	$	15	$	4		$	303		$	4		$	145
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $(2), $(2), $(2), and $(23), respectively	—		(3		)	(3		)	(3		)	(41		)
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $-, $-, and $-, respectively	—		—			—			—			1
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $(1), $-, and $4, respectively	—		—			—			—			5
Total other comprehensive income (loss)	—		(3		)	(3		)	(3		)	(35		)
Comprehensive Income	15		1			300			1			110
Less: Comprehensive income attributable to noncontrolling interest	—		—			—			—			14
Comprehensive Income Attributable to Southern Company Gas	$	15	$	1		$	300		$	1		$	96

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)

	Successor						Predecessor
	For the Nine Months Ended September 30,			July 1, 2016 through September 30,			January 1, 2016 through June 30,
	2017			2016			2016
	(in millions)						(in millions)
Operating Activities:
Net income	$	303		$	4		$	145
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	370			116			206
Deferred income taxes	265			(30		)	8
Pension, postretirement, and other employee benefits	(4		)	(123		)	5
Stock based compensation expense	25			11			20
Hedge settlements	—			(35		)	(26		)
Mark-to-market adjustments	(32		)	17			162
Other, net	(67		)	(47		)	(82		)
Changes in certain current assets and liabilities —
-Receivables	534			(18		)	181
-Natural gas for sale, net of temporary LIFO liquidation	—			(222		)	273
-Prepaid income taxes	(7		)	1			151
-Other current assets	(42		)	(36		)	37
-Accounts payable	(169		)	78			43
-Accrued taxes	(24		)	(11		)	41
-Accrued compensation	(11		)	(36		)	(21		)
-Other current liabilities	8			(11		)	(30		)
Net cash provided from (used for) operating activities	1,149			(342		)	1,113
Investing Activities:
Property additions	(1,093		)	(287		)	(509		)
Cost of removal, net of salvage	(45		)	(21		)	(32		)
Change in construction payables, net	49			9			(7		)
Investment in unconsolidated subsidiaries	(128		)	(1,421		)	(14		)
Returned investment in unconsolidated subsidiaries	22			2			3
Other investing activities	3			3			—
Net cash used for investing activities	(1,192		)	(1,715		)	(559		)
Financing Activities:
Increase (decrease) in notes payable, net	(323		)	472			(896		)
Proceeds —
First mortgage bonds	200			—			250
Capital contributions from parent company	79			1,089			—
Senior notes	450			900			350
Redemptions and repurchases —
Medium-term notes	(22		)	—			—
First mortgage bonds	—			—			(125		)
Senior notes	—			(300		)	—
Distributions to noncontrolling interest	—			—			(19		)
Payment of common stock dividends	(332		)	(63		)	(128		)
Other financing activities	(7		)	(8		)	10
Net cash provided from (used for) financing activities	45			2,090			(558		)
Net Change in Cash and Cash Equivalents	2			33			(4		)
Cash and Cash Equivalents at Beginning of Period	19			15			19
Cash and Cash Equivalents at End of Period	$	21		$	48		$	15
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $9, $2, and $3 capitalized, respectively)	$	146		$	86		$	119
Income taxes, net	17			54			(100		)
Noncash transactions — Accrued property additions at end of period	112			50			41

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, 2017			At December 31, 2016
	(in millions)
Current Assets:
Cash and cash equivalents	$	21		$	19
Receivables —
Energy marketing receivables	427			623
Customer accounts receivable	221			364
Unbilled revenues	61			239
Other accounts and notes receivable	61			76
Accumulated provision for uncollectible accounts	(26		)	(27		)
Materials and supplies	24			26
Natural gas for sale	631			631
Prepaid expenses	103			80
Assets from risk management activities, net of collateral	103			128
Other regulatory assets, current	96			81
Other current assets	25			10
Total current assets	1,747			2,250
Property, Plant, and Equipment:
In service	15,383			14,508
Less: Accumulated depreciation	4,567			4,439
Plant in service, net of depreciation	10,816			10,069
Construction work in progress	596			496
Total property, plant, and equipment	11,412			10,565
Other Property and Investments:
Goodwill	5,967			5,967
Equity investments in unconsolidated subsidiaries	1,609			1,541
Other intangible assets, net of amortization of $100 and $34 at September 30, 2017 and December 31, 2016, respectively	300			366
Miscellaneous property and investments	21			21
Total other property and investments	7,897			7,895
Deferred Charges and Other Assets:
Other regulatory assets, deferred	944			973
Other deferred charges and assets	190			170
Total deferred charges and other assets	1,134			1,143
Total Assets	$	22,190		$	21,853

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, 2017			At December 31, 2016
	(in millions)
Current Liabilities:
Securities due within one year	$	—		$	22
Notes payable	934			1,257
Energy marketing trade payables	451			597
Accounts payable	368			348
Customer deposits	137			153
Accrued taxes —
Accrued income taxes	—			26
Other accrued taxes	70			68
Accrued interest	66			48
Accrued compensation	46			58
Liabilities from risk management activities, net of collateral	28			62
Other regulatory liabilities, current	126			102
Accrued environmental remediation, current	54			69
Other current liabilities	112			108
Total current liabilities	2,392			2,918
Long-term Debt	5,862			5,259
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	2,214			1,975
Employee benefit obligations	431			441
Other cost of removal obligations	1,656			1,616
Accrued environmental remediation, deferred	345			357
Other regulatory liabilities, deferred	35			51
Other deferred credits and liabilities	88			127
Total deferred credits and other liabilities	4,769			4,567
Total Liabilities	13,023			12,744
Common Stockholder's Equity:
Common stock, par value $0.01 per share —
Authorized — 100 million shares
Outstanding — 100 shares	—			—
Paid in capital	9,185			9,095
Accumulated deficit	(41		)	(12		)
Accumulated other comprehensive income	23			26
Total common stockholder's equity	9,167			9,109
Total Liabilities and Stockholder's Equity	$	22,190		$	21,853

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

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OVERVIEW

Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through utilities in seven states – Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee, and Maryland. 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 (K) to the Condensed Financial Statements herein and "BUSINESS – 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 constructive regulatory environments, to maintain and grow natural gas sales, and to effectively manage and secure timely recovery of costs. Southern Company Gas 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 Southern Company Gas for the foreseeable future.

Merger, Acquisition, and Disposition Activities

On July 1, 2016, Southern Company Gas completed the Merger, which was accounted for by Southern Company using the acquisition method of accounting whereby the assets acquired and liabilities assumed were recognized at fair value as of the acquisition date. Pushdown accounting was applied to create a new cost basis for Southern Company Gas assets, liabilities, and equity as of the acquisition date. Accordingly, the successor financial statements reflect a new basis of accounting and successor and predecessor period financial results (separated by a heavy black line) are presented, but are not comparable. As a result of the application of acquisition accounting, certain discussions herein include disclosure of the predecessor and successor periods. See Note (I) to the Condensed Financial Statements herein for additional information relating to the Merger.

In September 2016, Southern Company Gas paid approximately $1.4 billion to acquire a 50% equity interest in SNG. On March 31, 2017, Southern Company Gas made an additional $50 million contribution to maintain its 50% equity interest in SNG. Southern Company Gas recorded equity investment income of $28 million and $86 million from this investment in the successor third quarter and year-to-date 2017, respectively, and $27 million in September 2016. See Note (J) to the Condensed Financial Statements herein and Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K for additional information.

In October 2016, Southern Company Gas completed its purchase of Piedmont's 15% interest in SouthStar, which eliminated the noncontrolling interest associated with SouthStar. See Note 4 to the financial statements of Southern Company Gas under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.

On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements for the sale 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. As of September 30, 2017, the net book value of the assets to be disposed of in the sale was approximately $1.5 billion, which includes approximately $0.5 billion of goodwill. The goodwill is not deductible for tax purposes and as a result, a deferred tax liability has not yet been provided for goodwill. Through the completion of the sale, Southern Company Gas intends to invest approximately $0.1 billion in capital expenditures which are required for ordinary business operations. The completion of each sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act; (ii) the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC; and (iii) other customary closing conditions. The sales are expected to be completed by the end of the third quarter 2018.

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

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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 – RESULTS OF OPERATIONS – "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 Southern Company Gas' utilities in Illinois and Florida, Southern Company Gas has various regulatory mechanisms, such as weather normalization mechanisms, 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 at gas distribution operations and gas marketing services to reduce negative earnings impact in the event of warmer-than-normal weather, while retaining most of the earnings upside.

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

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

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

Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)	(% change)
$11	N/M

N/M - Not meaningful

Net income attributable to Southern Company Gas was $15 million for the third quarter 2017 compared to $4 million for the corresponding period in 2016. This increase was primarily due to $11 million of additional income from infrastructure replacement programs and base rate increases, net of associated depreciation, and a $7 million gain from the settlement of contractor litigation claims, partially offset by $12 million lower net income at wholesale gas services. Also contributing to the increase was $24 million in Merger-related expenses in the third quarter 2016, partially offset by $23 million of additional deferred income tax expense in the third quarter 2017.

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	Successor				Predecessor
	Year-to-Date 2017		July 1, 2016 through September 30, 2016		January 1, 2016 through June 30, 2016
	(in millions)		(in millions)		(in millions)
Net Income Attributable to Southern Company Gas	$	303	$	4	$	131

Net income attributable to Southern Company Gas for the successor year-to-date 2017 included $28 million of net income from wholesale gas services and $38 million in earnings from the SNG investment, net of related interest expense. Also included in net income for this period was $29 million generated from the continued investment in infrastructure replacement programs and base rate increases, primarily at Atlanta Gas Light effective March 1, 2017, less the associated increases in depreciation. For additional information, see FUTURE EARNINGS POTENTIAL– "Regulatory Matters – Base Rate Cases" herein. These increases were partially offset by $23 million of additional deferred income tax expense.

Net income attributable to Southern Company Gas for the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016 included $11 million and $42 million, respectively, in net losses from wholesale gas services. The successor period of July 1, 2016 through September 30, 2016 also included $16 million in earnings from the SNG investment, net of related interest expense. Also included in net income for these periods were $24 million and $41 million, respectively, of Merger-related expenses and $14 million of net income attributable to noncontrolling interest in the predecessor period of January 1, 2016 through June 30, 2016. As a result of purchasing the remaining interest in SouthStar in October 2016, all net income was attributable to Southern Company Gas in the successor periods.

Natural Gas Revenues

Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)	(% change)
$14	2.7

In the third quarter 2017, natural gas revenues were $532 million compared to $518 million for the corresponding period in 2016.

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

	Third Quarter 2017
	(in millions)			(% change)
Natural gas – prior year	$	518
Estimated change resulting from –
Infrastructure replacement programs and base rate increases	25			4.8	%
Gas costs and other cost recovery	1			0.2
Mark-to-market adjustments at gas marketing services	3			0.6
Wholesale gas services	(16		)	(3.1	)
Other	1			0.2
Natural gas – current year	$	532		2.7	%

The increase in natural gas revenue primarily relates to gas distribution operations as a result of continued investment in infrastructure replacement programs and increases in base rate revenues, primarily at Atlanta Gas Light effective March 1, 2017, as well as the positive impact from the amortization of assets established in the application of acquisition accounting at gas marketing services. These increases were partially offset by mark-to-

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market losses from derivative instruments at wholesale gas services and gas marketing services due to changes in natural gas prices and a decrease in commercial activity at wholesale gas services. For information on commercial activity at wholesale gas services, see "Segment Information – Wholesale Gas Services – Change in Commercial Activity" herein.

	Successor				Predecessor
	Year-to-Date 2017		July 1, 2016 through September 30, 2016		January 1, 2016 through June 30, 2016
	(in millions)		(in millions)		(in millions)
Natural gas revenues	$	2,746	$	518	$	1,841

For the successor year-to-date 2017, natural gas revenues included recovery of $1.1 billion in cost of natural gas and $95 million in net revenues from wholesale gas services, net of $14 million of amortization associated with assets established in the application of acquisition accounting. Also included in natural gas revenues were $69 million in additional revenues generated from gas distribution operations as a result of continued investment in infrastructure replacement programs and increases in base rate revenues, primarily at Atlanta Gas Light effective March 1, 2017, partially offset by a $16 million decrease attributable to warmer-than-normal weather, net of hedging.

For the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016, natural gas revenues included recovery of $133 million and $755 million, respectively, in cost of natural gas, as well as $8 million and $32 million, respectively, in net losses from wholesale gas services. Also included in natural gas revenues for the predecessor period of January 1, 2016 through June 30, 2016 was a $7 million decrease attributable to warmer-than-normal weather, net of hedging.

See "Segment Information" herein for additional information on wholesale gas services' revenues and losses.

Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, recoverable natural gas revenues generally equal the 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 during the non-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			2017 vs. 2016		2017 vs. normal
	Normal(a)	2017	2016	(warmer)		(warmer)
Illinois(b)	3,817	3,146	3,353	(6.2	)%	(17.6	)%
Georgia	1,631	1,008	1,449	(30.4	)%	(38.2	)%

(a) Normal represents the 10-year average from January 1, 2007 through September 30, 2016 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.

(b) The 10-year average Heating Degree Days established by the Illinois Commission in Nicor Gas' 2009 rate case is 3,580 for the first nine months from 1998 through 2007.

For the third quarters 2017 and 2016, the weather-related pre-tax income impact was immaterial.

Southern Company Gas hedged its exposure to warmer-than-normal weather at Nicor Gas in Illinois; therefore, the weather-related negative pre-tax income impact on gas distribution operations was limited to $6 million ($3 million after tax) and $7 million ($5 million after tax) for year-to-date 2017 and 2016, respectively. Southern Company Gas also hedged its exposure at gas marketing services to warmer-than-normal weather in Georgia and Illinois;

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therefore, the weather-related negative pre-tax income impact on gas marketing services was limited to $10 million ($6 million after tax) for year-to-date 2017 and there was no impact for year-to-date 2016.

The following table provides the number of customers served by Southern Company Gas at September 30, 2017 and 2016:

	September 30,
	2017		2016		2017 vs. 2016
	(in thousands, except market share %)				(% change)
Gas distribution operations	4,555		4,522		0.7	%
Gas marketing services
Energy customers(*)	756		626		20.8	%
Market share of energy customers in Georgia	28.8	%	29.4	%
Service contracts	1,183		1,189		(0.5	)%

(*) Includes approximately 140,000 customers as of September 30, 2017 that were contracted to serve beginning April 1, 2017.

Southern Company Gas anticipates overall customer growth trends at gas distribution operations to continue as it expects continued improvement in the new housing market and low natural gas prices.

Gas marketing services' market share in Georgia decreased at September 30, 2017 compared to the corresponding period in 2016 as a result of a highly competitive marketing environment, which Southern Company Gas expects to continue for the foreseeable future. Southern Company Gas will continue efforts at gas marketing services to enter into targeted markets and expand its energy customers and service contracts.

Cost of Natural Gas

Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)	(% change)
$1	0.8

In the third quarter 2017, cost of natural gas was $134 million compared to $133 million for the corresponding period in 2016. This increase reflected 7% higher natural gas prices during the third quarter 2017 compared to the corresponding period in 2016, partially offset by lower demand for natural gas.

	Successor				Predecessor
	Year-to-Date 2017		July 1, 2016 through September 30, 2016		January 1, 2016 through June 30, 2016
	(in millions)		(in millions)		(in millions)
Cost of natural gas	$	1,085	$	133	$	755

Cost of natural gas primarily reflected an increase of 38% in natural gas prices during the year-to-date 2017 compared to the corresponding period in 2016, partially offset by lower demand for natural gas driven by warmer-than-normal weather.

Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, recoverable natural gas revenues generally equal the cost of natural gas and do not affect net income from gas distribution operations. Cost of natural gas at gas distribution operations represented approximately 79% of total cost of natural gas for year-to-date 2017 and will be recovered in this manner. For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Cost of Natural Gas" of Southern Company Gas in Item 7 of the Form 10-K and "Natural Gas Revenues" herein.

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

	Third Quarter		2017 vs. 2016		Year-to-Date		2017 vs. 2016
	2017	2016	% Change		2017	2016	% Change
Gas distribution operations(mmBtu in millions)
Firm	73	71	2.8	%	438	467	(6.2	)%
Interruptible	22	22	—	%	71	71	—	%
Total	95	93	2.2	%	509	538	(5.4	)%
Gas marketing services(mmBtu in millions)
Firm:
Georgia	3	3	—	%	11	25	(56.0	)%
Illinois	1	1	—	%	4	8	(50.0	)%
Other emerging markets	2	2	—	%	7	9	(22.2	)%
Interruptible:
Large commercial and industrial	3	3	—	%	8	10	(20.0	)%
Total	9	9	—	%	30	52	(42.3	)%
Wholesale gas services (mmBtu in millions/day)
Daily physical sales	6.3	7.6	(17.1	)%	6.4	7.6	(15.8	)%

Other Operations and Maintenance Expenses

Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)	(% change)
$(11)	(5.1)

In the third quarter 2017, other operations and maintenance expenses were $205 million compared to $216 million for the corresponding period in 2016. The decrease was primarily related to $8 million of expenses associated with certain benefit arrangements recorded in 2016, $2 million lower marketing expenses at gas marketing services, and a $3 million decrease in other employee benefit and incentive costs.

	Successor				Predecessor
	Year-to-Date 2017		July 1, 2016 through September 30, 2016		January 1, 2016 through June 30, 2016
	(in millions)		(in millions)		(in millions)
Other operations and maintenance	$	671	$	216	$	454

Other operations and maintenance expenses for the successor year-to-date 2017 reflected increased compensation expenses due to timing, partially offset by low bad debt expense. For all periods presented, other operations and maintenance expenses primarily includes professional services, including pipeline compliance and maintenance and legal services, as well as compensation and benefit costs.

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Depreciation and Amortization

Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)	(% change)
$9	7.8

In the third quarter 2017, depreciation and amortization was $125 million compared to $116 million for the corresponding period in 2016. The increase was primarily due to $7 million in additional depreciation at gas distribution operations associated with additional plant in service primarily related to continued investment in infrastructure replacement programs.

	Successor				Predecessor
	Year-to-Date 2017		July 1, 2016 through September 30, 2016		January 1, 2016 through June 30, 2016
	(in millions)		(in millions)		(in millions)
Depreciation and amortization	$	370	$	116	$	206

Depreciation and amortization for the successor year-to-date 2017 included $29 million of additional amortization of intangible assets established in the application of acquisition accounting primarily at gas marketing services, $21 million in additional depreciation at gas distribution operations due to additional assets placed in service primarily related to continued investment in infrastructure replacement programs, and $7 million from the acceleration of depreciation relating to certain assets.

Taxes Other Than Income Taxes

Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)	(% change)
$(3)	(10.3)

In the third quarter 2017, taxes other than income taxes were $26 million compared to $29 million for the corresponding period in 2016. The decrease primarily reflects establishing a regulatory asset related to Nicor Gas' invested capital tax. For additional information, see FUTURE EARNINGS POTENTIAL– "Regulatory Matters – Riders" herein.

	Successor				Predecessor
	Year-to-Date 2017		July 1, 2016 through September 30, 2016		January 1, 2016 through June 30, 2016
	(in millions)		(in millions)		(in millions)
Taxes other than income taxes	$	140	$	29	$	99

Taxes other than income taxes in the successor periods reflected increased revenue-based taxes due to higher revenues at gas distribution operations during the successor periods.

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Earnings from Equity Method Investments

Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)	(% change)
$3	10.3

In the third quarter 2017, earnings from equity method investments were $32 million compared to $29 million for the corresponding period in 2016. The increase was primarily due to higher earnings from SNG, PennEast Pipeline, and Horizon Pipeline.

	Successor				Predecessor
	Year-to-Date 2017		July 1, 2016 through September 30, 2016		January 1, 2016 through June 30, 2016
	(in millions)		(in millions)		(in millions)
Earnings from equity method investments	$	100	$	29	$	2

Earnings from equity method investments in the successor year-to-date 2017 consisted of $86 million in earnings from SNG and $14 million in earnings from all other investments.

See Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K and Note (J) to the Condensed Financial Statements under "Southern Company Gas – Equity Method Investments" herein for additional information.

Other Income (Expense), Net

Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)	(% change)
$9	100.0

In the third quarter 2017, other income (expense), net was $18 million compared to $9 million for the corresponding period in 2016. The increase was primarily due to a $14 million gain from the settlement of contractor litigation claims.

	Successor				Predecessor
	Year-to-Date 2017		July 1, 2016 through September 30, 2016		January 1, 2016 through June 30, 2016
	(in millions)		(in millions)		(in millions)
Other income (expense), net	$	26	$	9	$	5

The successor year-to-date 2017 reflects a $16 million gain from the settlement of contractor litigation claims. The successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016 primarily represent the tax gross-up on contributions in aid of construction and AFUDC.

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Interest Expense, Net of Amounts Capitalized

Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)	(% change)
$12	30.8

In the third quarter 2017, interest expense, net of amounts capitalized was $51 million compared to $39 million for the corresponding period in 2016. The increase was primarily due to additional interest expense on new debt issuances.

	Successor				Predecessor
	Year-to-Date 2017		July 1, 2016 through September 30, 2016		January 1, 2016 through June 30, 2016
	(in millions)		(in millions)		(in millions)
Interest expense, net of amounts capitalized	$	145	$	39	$	96

The successor year-to-date 2017 and the period of July 1, 2016 through September 30, 2016 reflect additional interest expense on new debt issuances, partially offset by reductions of $29 million and $9 million, respectively, resulting from the fair value adjustment of long-term debt in acquisition accounting.

Income Taxes

Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)	(% change)
$45	N/M

N/M - Not meaningful

In the third quarter 2017, income taxes were $52 million compared to $7 million for the corresponding period in 2016. The increase reflects $23 million of additional deferred income tax expense associated with State of Illinois tax legislation enacted during the third quarter 2017 and the allocation of new tax apportionment factors in several states for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings, as well as higher pre-tax earnings. See FUTURE EARNINGS POTENTIAL herein for additional information.

	Successor				Predecessor
	Year-to-Date 2017		July 1, 2016 through September 30, 2016		January 1, 2016 through June 30, 2016
	(in millions)		(in millions)		(in millions)
Income taxes	$	233	$	7	$	87

The successor year-to-date 2017 income taxes reflect $23 million of additional deferred income tax expense associated with State of Illinois tax legislation and the allocation of new tax apportionment factors, as well as increased income taxes from higher pre-tax earnings. See FUTURE EARNINGS POTENTIAL herein for additional information.

Performance and Non-GAAP Measures

Prior to the Merger, Southern Company Gas evaluated segment performance using earnings before interest and taxes (EBIT), which includes operating income, earnings from equity method investments, and other income

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(expense), net. EBIT excludes interest expense, net of amounts capitalized and income taxes (benefit), which were evaluated on a consolidated basis for those periods. EBIT is used herein to discuss the results of Southern Company Gas' segments for the predecessor period, as EBIT was the primary measure of segment profit or loss for that period. Subsequent to the Merger, Southern Company Gas changed its segment performance measure from EBIT to net income to better align with the performance measure utilized by Southern Company. EBIT for the successor third quarters 2017 and 2016 and the successor year-to-date 2017 presented herein is considered a non-GAAP measure. Southern Company Gas also discusses consolidated EBIT, which is considered a non-GAAP measure for all periods presented. The presentation of consolidated EBIT is believed to provide useful supplemental information regarding a consolidated measure of profit or loss. Southern Company Gas further believes that the presentation of segment EBIT for the successor third quarters 2017 and 2016 and the successor year-to-date 2017 is useful as it allows for a measure of comparability to other companies with different capital and legal structures, which accordingly may be subject to different interest rates and effective tax rates. The applicable reconciliations of net income to consolidated EBIT and segment EBIT are provided herein.

Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues minus 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, and Merger-related expenses, which are included in the calculation of operating income as calculated in accordance with GAAP and reflected in the consolidated 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 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.

EBIT and adjusted operating margin should not be considered alternatives to, or more meaningful indicators of, Southern Company Gas' operating performance than consolidated net income attributable to Southern Company Gas or operating income as determined in accordance with GAAP. In addition, Southern Company Gas' adjusted operating margin may not be comparable to similarly titled measures of other companies.

	Successor												Predecessor
	Third Quarter 2017			Third Quarter 2016			Year-to-Date 2017			July 1, 2016 through September 30, 2016			January 1, 2016 through June 30, 2016
	(in millions)												(in millions)
Operating Income	$	68		$	12		$	555		$	12		$	321
Other operating expenses(a)	356			396			1,181			396			815
Revenue taxes(b)	(8		)	(8		)	(74		)	(8		)	(56		)
Adjusted Operating Margin	$	416		$	400		$	1,662		$	400		$	1,080

(a) Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, and Merger-related expenses.

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

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	Successor								Predecessor
	Third Quarter 2017		Third Quarter 2016		Year-to-Date 2017		July 1, 2016 through September 30, 2016		January 1, 2016 through June 30, 2016
	(in millions)								(in millions)
Consolidated Net Income Attributable to Southern Company Gas	$	15	$	4	$	303	$	4	$	131
Net income attributable to noncontrolling interest (*)			—		—		—		14
Income taxes	52		7		233		7		87
Interest expense, net of amounts capitalized	51		39		145		39		96
EBIT	$	118	$	50	$	681	$	50	$	328

(*) See Note 4 to the financial statements of Southern Company Gas under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.

Segment Information

Adjusted operating margin, operating expenses, and Southern Company Gas' primary performance metric for each segment is illustrated in the tables below. See Note (K) to the Condensed Financial Statements herein for additional information.

	Successor
	Third Quarter 2017									Third Quarter 2016
	Adjusted Operating			Operating			Net Income			Adjusted Operating			Operating			Net Income
	Margin(*)			Expenses(*)			(Loss)			Margin(*)			Expenses(*)			(Loss)
	(in millions)									(in millions)
Gas distribution operations	$	379		$	271		$	52		$	353		$	284		$	27
Gas marketing services	51			48			1			45			51			(4		)
Wholesale gas services	(25		)	11			(23		)	(8		)	10			(11		)
Gas midstream operations	12			13			14			9			13			14
All other	2			8			(29		)	2			31			(22		)
Intercompany eliminations	(3		)	(3		)	—			(1		)	(1		)	—
Consolidated	$	416		$	348		$	15		$	400		$	388		$	4

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

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	Successor																		Predecessor
	Year-to-Date 2017									July 1, 2016 through September 30, 2016									January 1, 2016 through June 30, 2016
	Adjusted Operating			Operating			Net Income			Adjusted Operating			Operating			Net Income			Adjusted Operating			Operating
	Margin(*)			Expenses(*)			(Loss)			Margin(*)			Expenses(*)			(Loss)			Margin(*)			Expenses(*)			EBIT
	(in millions)																		(in millions)
Gas distribution operations	$	1,329		$	866		$	223		$	353		$	284		$	27		$	911		$	560		$	353
Gas marketing services	213			149			36			45			51			(4		)	190			81			109
Wholesale gas services	93			40			28			(8		)	10			(11		)	(36		)	33			(68		)
Gas midstream operations	28			38			38			9			13			14			15			24			(6		)
All other	7			22			(22		)	2			31			(22		)	4			65			(60		)
Intercompany eliminations	(8		)	(8		)	—			(1		)	(1		)	—			(4		)	(4		)	—
Consolidated	$	1,662		$	1,107		$	303		$	400		$	388		$	4		$	1,080		$	759		$	328

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

Gas Distribution Operations

Gas distribution operations is the largest component of Southern Company Gas' business and is subject to regulation and oversight by agencies in each of the states it serves. 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 utilities' service territories.

Successor Third Quarter 2017 vs. Third Quarter 2016

In the third quarter 2017, net income was $52 million compared to $27 million for the corresponding period in 2016. The increase in net income relates to an increase of $26 million in adjusted operating margin, a decrease of $13 million in operating expenses, and an increase of $11 million in other income (expense), net. The change in net income also includes an increase of $7 million in interest expense, net of amounts capitalized, and an increase of $18 million in income tax expense. The increase in adjusted operating margin primarily reflects $24 million in additional revenue from the continued investment in infrastructure replacement programs and base rate increases, primarily at Atlanta Gas Light effective March 1, 2017. The decrease in operating expenses primarily reflects $18 million in rate credits provided to customers of Elizabethtown Gas in 2016 as a condition of the Merger, partially offset by $7 million in additional depreciation due to continued investment in infrastructure programs. The increase in other income (expense), net primarily reflects a $14 million gain from the settlement of contractor litigation claims in 2017. The increase in interest expense includes the impact of intercompany promissory notes executed in December 2016 and the issuance of first mortgage bonds at Nicor Gas on August 10, 2017. The increase in income tax expense relates primarily to higher pre-tax earnings.

Successor Year-to-Date 2017

Net income of $223 million includes $1.3 billion in adjusted operating margin, $866 million in operating expenses, and $23 million in other income (expense), net, which resulted in EBIT of $486 million. Net income also includes

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$119 million in interest expense, net of amounts capitalized and $144 million in income tax expense. Adjusted operating margin reflects $69 million in additional revenue from continued investment in infrastructure replacement programs and base rate increases, primarily at Atlanta Gas Light effective March 1, 2017. Also included in adjusted operating margin was increased customer growth, partially offset by a $6 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect a $21 million increase in depreciation associated with additional assets placed in service, as well as increased compensation expense, legal expenses, and pipeline compliance and maintenance activities. Other income (expense), net reflects a $16 million gain from the settlement of contractor litigation claims. Interest expense reflects the impact of intercompany promissory notes executed in December 2016 and the issuance of first mortgage bonds at Nicor Gas on August 10, 2017.

Successor Period of July 1, 2016 through September 30, 2016

Net income of $27 million includes $353 million in adjusted operating margin, $284 million in operating expenses, including $18 million in rate credits provided to customers, and $6 million in other income (expense), net, which resulted in EBIT of $75 million. Net income also includes $32 million in interest expense and $16 million in income tax expense.

Predecessor Period of January 1, 2016 through June 30, 2016

EBIT of $353 million includes $911 million in adjusted operating margin, $560 million in operating expenses, and $2 million in other income (expense), net. Adjusted operating margin reflects revenue from continued investment in infrastructure replacement programs and increased usage and customer growth, partially offset by a $7 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect depreciation associated with additional assets placed in service.

Gas Marketing Services

Gas marketing services consists of several businesses that provide energy-related products and services to natural gas markets, including warranty sales. 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. Operating expenses primarily reflect employee costs, marketing, and bad debt expenses.

Successor Third Quarter 2017 vs. Third Quarter 2016

In the third quarter 2017, net income was $1 million compared to a net loss of $4 million for the corresponding period in 2016. The increase in net income primarily relates to a $6 million increase in adjusted operating margin and a $3 million decrease in operating expenses. The change in net income also includes increases of $1 million and $3 million in interest expense and income tax expense, respectively. Adjusted operating margin primarily reflects a $3 million decrease in unrealized hedge losses, net of recoveries, and a $4 million increase from the elimination of deferred revenue in the third quarter 2016 from the application of acquisition accounting. Operating expenses reflect decreased amortization of intangible assets established in the application of acquisition accounting.

Successor Year-to-Date 2017

Net income of $36 million includes $213 million in adjusted operating margin and $149 million in operatingexpenses, which resulted in EBIT of $64 million. Net income also includes $4 million in interest expense and $24 million in income tax expense. Adjusted operating margin reflects a $10 million negative impact of warmer-than-normal weather, net of hedging, and $7 million in unrealized hedge losses, net of recoveries. Operating expenses include $30 million in additional amortization of intangible assets established in the application of acquisition accounting.

Successor Period of July 1, 2016 through September 30, 2016

Net loss of $4 million includes $45 million in adjusted operating margin and $51 million in operating expenses, which resulted in a loss before interest and taxes of $6 million. Also included in net loss is $2 million in income tax benefit.

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Predecessor Period of January 1, 2016 through June 30, 2016

EBIT of $109 million includes $190 million in adjusted operating margin and $81 million in operating expenses. Adjusted operating margin reflects $9 million in unrealized hedge gains. Earnings in the predecessor period include $14 million attributable to noncontrolling interest.

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.

Successor Third Quarter 2017 vs. Third Quarter 2016

In the third quarter 2017, net loss was $23 million compared to a net loss of $11 million for the corresponding period in 2016. The increase in net loss relates primarily to a $17 million decrease in adjusted operating margin, partially offset by an increase of $8 million in income tax benefit due to higher losses. The decrease in adjusted gross margin includes $22 million in additional mark-to-market losses and a $7 million decrease in gains from commercial activity, partially offset by a $12 million positive impact from the amortization of liabilities recorded in the application of acquisition accounting.

Successor Year-to-Date 2017

Net income of $28 million includes $93 million in adjusted operating margin and $40 million in operating expenses, which resulted in EBIT of $53 million. Net income also includes $5 million in interest expense and $20 million in income tax expense.

Successor Period of July 1, 2016 through September 30, 2016

Net loss of $11 million includes $(8) million in adjusted operating margin and $10 million in operating expenses, which resulted in a loss before interest and taxes of $17 million. Also included in net loss is $1 million in interest expense and $7 million in income tax benefit.

Predecessor Period of January 1, 2016 through June 30, 2016

Loss before interest and taxes of $68 million includes $(36) million in adjusted operating margin, $33 million in operating expenses, and $1 million in other income (expense), net.

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The following table illustrates the components of wholesale gas services' adjusted operating margin for the periods presented.

	Successor												Predecessor
	Third Quarter 2017			Third Quarter 2016			Year-to-Date 2017			July 1, 2016 through September 30, 2016			January 1, 2016 through June 30, 2016
	(in millions)												(in millions)
Commercial activity recognized	$	3		$	10		$	80		10			$	34
Gain (loss) on storage derivatives	4			11			13			11			(38		)
Gain (loss) on transportation and forward commodity derivatives	(22		)	(7		)	14			(7		)	(31		)
LOCOM adjustments, net of current period recoveries	—			—			—			—			(1		)
Purchase accounting adjustments	(10		)	(22		)	(14		)	(22		)	—
Adjusted Operating Margin	$	(25	)	$	(8	)	$	93		$	(8	)	$	(36	)

Change in Commercial Activity

The commercial activity at wholesale gas services includes recognition of storage and transportation values that were generated in prior periods, which reflect the impact of prior period hedge gains and losses as associated physical transactions occur. Warmer-than-normal weather during the 2016/2017 Heating Season, lower power generation volumes, and build-out of new U.S. pipeline infrastructure, along with increases in natural gas supply, caused low volatility and a tightening of locational or transportation spreads in 2017, negatively impacting the amount of commercial activity revenues generated relative to demand fees for contracted pipeline transportation and storage capacity, and minimum sharing under asset management agreements. However, as natural gas prices and forward storage or time spreads increased, wholesale gas services was able to capture higher storage values that it expects to recognize as commercial activity revenues when natural gas is physically withdrawn from storage. Southern Company Gas anticipates continued low volatility in certain areas of wholesale gas services' portfolio.

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. In 2017 and 2016, there was little price volatility; however, the potential exists for market fundamentals indicating some level of increased volatility that would benefit Southern Company Gas' portfolio of pipeline transportation capacity. Additionally, during the first nine months of 2017, forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions resulted in storage derivative gains. Transportation and forward commodity derivative gains are primarily the result of narrowing transportation basis spreads due to some reduction in supply constraints resulting from new U.S. pipeline infrastructure and increases in natural gas supply and warmer-than-normal 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

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charges, but are net of the estimated impact of profit sharing under its 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, 2017. 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 (WACOG $2.67)	Expected net operating gains(a)		Physical transportation transactions – expected net operating gains (losses)(b)
	(in mmBtu in millions)	(in millions)		(in millions)
2017	22.0	$	4	$	(13	)
2018 and thereafter	40.0	17		28
Total at September 30, 2017	62.0	$	21	$	15

(a) 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.

(b) Represents the periods associated with the transportation derivative gains during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative gains and losses that were previously recognized.

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.

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 (J) to the Condensed Financial Statements herein and Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K for additional information.

Successor Third Quarter 2017 vs. Third Quarter 2016

In both the third quarter 2017 and the corresponding period in 2016 net income was $14 million. Net income reflects a $3 million increase in adjusted operating margin and a $4 million increase in earnings from equity method investments at SNG, PennEast Pipeline, and Horizon Pipeline. The change in net income also includes a $9 million increase in interest expense, net of amounts capitalized and a $2 million decrease in income taxes. The increase in interest expense includes the impact of intercompany promissory notes executed in December 2016.

Successor Year-to-Date 2017

Net income of $38 million includes $28 million in adjusted operating margin, $38 million in operating expenses, $97 million in earnings from equity method investments, consisting primarily of earnings from equity method investments at SNG, and $3 million in other income (expense), net, which resulted in EBIT of $90 million. Also included in net income are $25 million in interest expense and $27 million in income tax expense.

Successor Period of July 1, 2016 through September 30, 2016

Net income of $14 million includes $9 million in adjusted operating margin, $13 million in operating expenses, $28 million in earnings from equity method investments, consisting primarily of earnings from equity method

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investments at SNG, and $1 million in other income (expense), net, which resulted in EBIT of $25 million. Also included in net income is $11 million in income tax expense.

Predecessor Period of January 1, 2016 through June 30, 2016

Loss before interest and taxes of $6 million includes $15 million in adjusted operating margin, $24 million in operating expenses, and $3 million of other income (expense), net.

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.

Successor Third Quarter 2017 vs. Third Quarter 2016

In the third quarter 2017, net loss was $29 million compared to $22 million in the corresponding period in 2016. The increase in net loss reflects a $23 million decrease in operating expenses and a decrease of $2 million in other income (expense), net. Net loss also reflected a $6 million increase in interest expense, net of amounts capitalized and an increase of $34 million in income taxes. The decrease in operating expenses reflects a $35 million decrease in Merger-related expenses, partially offset by a $10 million increase in other operations and maintenance expenses and a $3 million increase from the acceleration of depreciation relating to certain assets. Interest expense decreased as a result of intercompany promissory notes executed in December 2016. The increase in income taxes primarily reflects additional deferred income tax expenses associated with State of Illinois tax legislation enacted during the third quarter 2017, as well as the allocation of new tax apportionment factors in several states for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings.

Successor Year-to-Date 2017, Successor Period of July 1, 2016 through September 30, 2016, and Predecessor Period of January 1, 2016 through June 30, 2016

For the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016, Merger-related expenses were $35 million and $56 million, respectively. There were no Merger-related expenses during the successor year-to-date 2017. In the successor year-to-date 2017, depreciation and amortization includes $7 million from the acceleration of depreciation relating to certain assets. Interest expense, net of amounts capitalized was $8 million, $6 million, and $34 million, respectively, in the successor year-to-date 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016. Income taxes were $18 million in the successor year-to-date 2017 and income tax benefit was $11 million and $35 million, respectively, in the successor period of July 1, 2016 through September 30, 2016 and the predecessor period of January 1, 2016 through June 30, 2016. In the successor year-to-date 2017, income taxes reflect $23 million of additional deferred income tax expense associated with State of Illinois tax legislation enacted during the third quarter 2017 and the allocation of new tax apportionment factors in several states for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings.

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Segment Reconciliations

Reconciliations of consolidated net income attributable to Southern Company Gas to EBIT for the successor third quarter and year-to-date 2017, and operating income to adjusted operating margin for all periods presented, are in the following tables. See Note (K) to the Condensed Financial Statements herein for additional information.

	Successor
	Third Quarter 2017
	Gas Distribution Operations		Gas Marketing Services		Wholesale Gas Services			Gas Midstream Operations		All Other			Intercompany Elimination		Consolidated
	(in millions)
Consolidated Net Income (Loss)	$	52	$	1	$	(23	)	$	14	$	(29	)	$	—	$	15
Income taxes (benefit)	34		1		(15		)	9		23			—		52
Interest expense, net of amounts capitalized	39		1		2			9		—			—		51
EBIT	$	125	$	3	$	(36	)	$	32	$	(6	)	$	—	$	118

	Successor
	Third Quarter 2016
	Gas Distribution Operations		Gas Marketing Services			Wholesale Gas Services			Gas Midstream Operations		All Other			Intercompany Elimination		Consolidated
	(in millions)
Consolidated Net Income (Loss)	$	27	$	(4	)	$	(11	)	$	14	$	(22	)	$	—	$	4
Income taxes (benefit)	16		(2		)	(7		)	11		(11		)	—		7
Interest expense, net of amounts capitalized	32		—			1			—		6			—		39
EBIT	$	75	$	(6	)	$	(17	)	$	25	$	(27	)	$	—	$	50

	Successor
	Year-to-Date 2017
	Gas Distribution Operations		Gas Marketing Services		Wholesale Gas Services		Gas Midstream Operations		All Other			Intercompany Elimination		Consolidated
	(in millions)
Consolidated Net Income (Loss)	$	223	$	36	$	28	$	38	$	(22	)	$	—	$	303
Income taxes	144		24		20		27		18			—		233
Interest expense, net of amounts capitalized	119		4		5		25		(8		)	—		145
EBIT	$	486	$	64	$	53	$	90	$	(12	)	$	—	$	681

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	Successor
	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)	$	108		$	3	$	(36	)	$	(1	)	$	(6	)	$	—		$	68
Other operating expenses(a)	279			48		11			13			8			(3		)	356
Revenue tax expense(b)	(8		)	—		—			—			—			—			(8		)
Adjusted Operating Margin	$	379		$	51	$	(25	)	$	12		$	2		$	(3	)	$	416

	Successor
	Third Quarter 2016
	Gas Distribution Operations			Gas Marketing Services			Wholesale Gas Services			Gas Midstream Operations			All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	69		$	(6	)	$	(18	)	$	(4	)	$	(29	)	$	—		$	12
Other operating expenses(a)	292			51			10			13			31			(1		)	396
Revenue tax expense(b)	(8		)	—			—			—			—			—			(8		)
Adjusted Operating Margin	$	353		$	45		$	(8	)	$	9		$	2		$	(1	)	$	400

	Successor
	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)	$	463		$	64	$	53	$	(10	)	$	(15	)	$	—		$	555
Other operating expenses(a)	940			149		40		38			22			(8		)	1,181
Revenue tax expense(b)	(74		)	—		—		—			—			—			(74		)
Adjusted Operating Margin	$	1,329		$	213	$	93	$	28		$	7		$	(8	)	$	1,662

	Predecessor
	January 1, 2016 through June 30, 2016
	Gas Distribution Operations			Gas Marketing Services		Wholesale Gas Services			Gas Midstream Operations			All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	351		$	109	$	(69	)	$	(9	)	$	(61	)	$	—		$	321
Other operating expenses(a)	616			81		33			24			65			(4		)	815
Revenue tax expense(b)	(56		)	—		—			—			—			—			(56		)
Adjusted Operating Margin	$	911		$	190	$	(36	)	$	15		$	4		$	(4	)	$	1,080

(a) Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, and Merger-related expenses.

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

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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 its primary business of natural gas distribution and complementary businesses in the gas marketing services, wholesale gas services, and gas midstream operations sectors. These factors include Southern Company Gas' ability to maintain a constructive regulatory environment that allows for the timely recovery of prudently-incurred costs, the completion and subsequent operation of ongoing infrastructure and other construction projects, creditworthiness of customers, Southern Company Gas' ability to optimize its transportation and storage positions, and its ability to re-contract storage rates at favorable prices. Future earnings in the near term will depend, in part, upon maintaining and growing sales and customers which are subject to a number of 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 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.

Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Southern Company Gas' financial statements.

On July 6, 2017, the State of Illinois enacted tax legislation that repealed its non-combination tax rule and increased the effective corporate income tax rate from 5.25% to 7.0% (making the total corporate tax rate 9.5% when combined with the 2.5% personal property replacement tax) effective July 1, 2017. In addition to increasing taxes on future earnings, this legislation required Southern Company Gas to increase accumulated deferred income tax liabilities by $24 million during the third quarter 2017 to reflect these changes, $15 million of which was expensed and $9 million was recorded as a regulatory asset. In addition, during the third quarter 2017, Southern Company calculated new apportionment factors in several states to include Southern Company Gas in its consolidated tax filings, which resulted in $8 million of additional deferred income tax expenses.

On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements for the sale of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. The execution of the asset purchase agreements triggered an interim assessment of goodwill, which is currently being performed with the assistance of a third-party valuation specialist. The preliminary results of this valuation indicate that the estimated fair values of the reporting units with goodwill exceed their carrying amounts and are not at risk of impairment. See OVERVIEW – "Merger, Acquisition, and Disposition Activities" and Note (I) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on the sales.

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.

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For additional information relating to these issues, see "Risk Factors" of Southern Company Gas in Item 1A of the Form 10-K.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through market-based contracts. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher 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. 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.

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 (LDNR). 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, 2017, the facility's property, plant, and equipment had a net book value of $111 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including the results of ongoing third-party technical engineering reviews, testing, and compliance with an order from the LDNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining a core sample to determine the composition of the sheath surrounding the edge of the salt dome. Early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a material impact on Southern Company Gas' financial statements.

FERC Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Company Gas in Item 7 and Note 4 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K for additional information regarding the Dalton Pipeline project.

On August 1, 2017, the Dalton Pipeline was placed in service as authorized by the FERC and transportation service for customers commenced.

On October 13, 2017, the Atlantic Coast Pipeline project received FERC approval.

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

Nicor Gas has established a variable tax cost adjustment rider, which was approved by the Illinois Commission effective July 16, 2017. This rider provides for recovery of the invested capital tax imposed on Nicor Gas through an annual true-up and reconciliation mechanism based on amounts approved in prior rate cases. Accordingly, this rider will not have a significant effect on Southern Company Gas' net income.

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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.

Base Rate Cases

Settled Base Rate Cases

On February 21, 2017, the Georgia PSC approved the Georgia Rate Adjustment Mechanism (GRAM) and a $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, based on the previously approved ROE of 10.75% and does not collect revenue through special riders and surcharges. Various infrastructure programs previously authorized by the Georgia PSC under Atlanta Gas Light's STRIDE program, which include the Integrated Vintage Plastic Replacement Program and Integrated System Reinforcement Program, will continue under GRAM and the recovery of and return on the infrastructure program investments will be included in annual base rate adjustments. The Georgia PSC will review Atlanta Gas Light's performance annually under GRAM.

Pursuant to the GRAM approval, Atlanta Gas Light and the staff of the Georgia PSC agreed to a variation to the Integrated Customer Growth Program that was formerly part of Atlanta Gas Light's STRIDE program. As a result, a new tariff was created, effective October 10, 2017, to provide $15 million annually for Atlanta Gas Light to commit to strategic economic development projects.

Beginning with the next rate adjustment in June 2018, Atlanta Gas Light's recovery of the previously unrecovered Pipeline Replacement Program revenue through 2014, as well as the mitigation costs associated with the Pipeline Replacement Program that were not previously included in its rates, will also be included in GRAM. In connection with the GRAM approval, the last monthly Pipeline Replacement Program surcharge increase became effective March 1, 2017.

In September 2016, Elizabethtown Gas filed a general base rate case with the New Jersey BPU requesting a $19 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year ending March 31, 2017 and a ROE of 10.25%. On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on a ROE of 9.6%. Also included in the settlement was a new composite depreciation rate that is expected to result in a $3 million annual reduction of depreciation. See OVERVIEW – "Merger, Acquisition, and Disposition Activities" and Note (I) to the Condensed Financial Statements under "Southern Company Gas" herein for information on the proposed sale of Elizabethtown Gas.

Pending Base Rate Cases

On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase in December 2017, after which rate adjustments will be effective.

On March 31, 2017, Virginia Natural Gas filed a general base rate case with the Virginia Commission requesting a $44 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year beginning September 1, 2017 and a ROE of 10.25%. The requested increase included $13 million related to the recovery of investments under the Steps to Advance Virginia's Energy (SAVE) program. On October 3, 2017, Virginia Natural Gas entered into a proposed stipulation with the Staff of the Virginia Commission, the Office of the Attorney General, Division of Consumer Counsel, and the Virginia Industrial Gas Users' Association resolving all related issues. The proposed stipulation includes a $34 million increase in annual base rate revenues, including $13 million related to the recovery of investments under the SAVE program. An authorized ROE range of 9.0% to 10.0% with a midpoint of 9.5% will be used to determine the revenue requirement in any filing, other than for a

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change in base rates. The Virginia Commission is expected to rule on the proposed stipulation in the fourth quarter 2017. Rate adjustments based on the proposed stipulation became effective September 1, 2017, subject to refund.

On October 23, 2017, Florida City Gas filed a general base rate case with the Florida PSC requesting a $19 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 11.25%. The requested increase includes $3 million related to the recovery of investments under the Safety, Access, and Facility Enhancement (SAFE) program. Additionally, Florida City Gas requested interim rates of $5 million to be effective in January 2018, subject to refund. The Florida PSC is expected to rule on the requested increase in mid-2018.

The ultimate outcome of these pending base rate cases 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 ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs.

Nicor Gas

In 2014, the Illinois Commission approved Nicor Gas' nine-year regulatory infrastructure program, Investing in Illinois. Under this program, Nicor Gas placed into service $178 million of qualifying assets during the first nine months of 2017.

Atlanta Gas Light

Atlanta Gas Light's STRIDE program, which started in 2009, consists of three individual programs that update and expand gas distribution systems and LNG facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, Atlanta Gas Light invested $127 million during the first nine months of 2017. The recovery of and return on current and future capital investments under the STRIDE program are included in the annual base rate revenue adjustment under GRAM.

In August 2016, Atlanta Gas Light filed a petition with the Georgia PSC for approval of a four-year extension of its Integrated System Reinforcement Program (i-SRP) seeking approval to invest an additional $177 million to improve and upgrade its core gas distribution system in years 2017 through 2020. Subsequently, the proposed capital investments associated with the extension of i-SRP were included in the 2017 annual base rate revenue under GRAM approved by the Georgia PSC on February 21, 2017.

See "Base Rate Cases" herein for additional information.

Elizabethtown Gas

In 2013, the New Jersey BPU approved the extension of Elizabethtown Gas' Aging Infrastructure Replacement program, under which Elizabethtown Gas invested $16 million during the first nine months of 2017. Effective July 1, 2017, investments under this program are being recovered through base rate revenues.

Virginia Natural Gas

In March 2016, the Virginia Commission approved an extension to the SAVE program, under which Virginia Natural Gas invested $21 million during the first nine months of 2017.

Florida City Gas

The Florida PSC approved Florida City Gas' SAFE program in 2015. Under the program, Florida City Gas invested $9 million during the first nine months of 2017.

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

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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.

Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. were defendants in a putative class action initially filed in 2011 in the state court in Cook County, Illinois. The plaintiffs purported to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously alleged that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs sought, on behalf of the classes they purported to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On February 8, 2017, the judge denied the plaintiffs' motion for class certification and Southern Company Gas' motion for summary judgment. On March 7, 2017, the parties reached a settlement, which was finalized and effective on April 3, 2017. The settlement did not have a material impact on Southern Company Gas' financial statements.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Company Gas prepares its financial statements in accordance with GAAP. Significant accounting policies are described in 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 related to Utility Regulation, Pushdown of Acquisition Accounting, Assessment of Assets, Derivatives and Hedging Activities, Pension and Other Postretirement Benefits, and Contingent Obligations.

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.

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. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While Southern Company Gas expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Southern Company Gas' revenue, including energy provided to customers, is from tariff offerings that provide natural gas without a defined contractual term, as well as longer-term contractual agreements, including non-derivative natural gas asset management and optimization arrangements. Southern Company Gas expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.

Southern Company Gas' ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company Gas' financial statements.In addition, the power

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and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company Gas expects CIAC to be out of the scope of ASC 606.

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company Gas intends to use the modified retrospective method of adoption effective January 1, 2018. Southern Company Gas has also elected to utilize practical expedients which allow it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in Southern Company Gas' financial statements, Southern Company Gas will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.

On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017. Southern Company Gas is evaluating the standard and expects to early adopt ASU 2017-04 effective January 1, 2018.

On March 10, 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 income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company Gas' operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Southern Company Gas' financial statements.

On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. 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 and interim periods within those fiscal years, with early adoption permitted. Southern Company Gas is evaluating the standard and expects to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on Southern Company Gas' financial statements.

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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. As a result of the Merger that closed on July 1, 2016, the results reported herein include disclosure of the successor third quarter and year-to-date 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016. See OVERVIEW – "Merger, Acquisition, and Disposition Activities" and Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information.

Southern Company Gas' financial condition remained stable at September 30, 2017. 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. Due to the increased working capital requirements associated with Nicor Gas' Investing in Illinois infrastructure replacement program, since 2015, Nicor Gas has temporarily ceased distributing dividends to Southern Company Gas. Elizabethtown Gas is restricted by its dividend policy as established by the New Jersey BPU in the amount it can dividend to its parent company to the extent of 70% of its quarterly net income. Additionally, as stipulated in the New Jersey BPU's order approving the Merger, Southern Company Gas is prohibited from paying dividends to its parent company, Southern Company, if Southern Company Gas' senior unsecured debt rating falls below investment grade. As of September 30, 2017, the amount of subsidiary retained earnings and net income available to dividend totaled $752 million. These restrictions did not have any impact on Southern Company Gas' ability to meet its cash obligations, nor does management expect such restrictions to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.

Net cash provided from (used for) operating activities totaled $1.1 billion for the successor first nine months of 2017, $(342) million for the successor period of July 1, 2016 through September 30, 2016, and $1.1 billion for the predecessor period of January 1, 2016 through June 30, 2016. These cash flows were primarily driven by the sale of natural gas inventory during the respective periods.

Net cash used for investing activities totaled $1.2 billion for the successor first nine months of 2017, primarily due to gross property additions related to capital expenditures for infrastructure replacement programs at gas distribution operations and capital contributed to equity method investments in pipelines. Net cash used for investing activities totaled $1.7 billion for the successor period of July 1, 2016 through September 30, 2016 and $559 million for the predecessor period of January 1, 2016 through June 30, 2016 primarily due to gross property additions related to capital expenditures for infrastructure replacement programs at gas distribution operations and the acquisition of Southern Company Gas' ownership interest in SNG in September 2016.

Net cash provided from financing activities totaled $45 million for the successor first nine months of 2017, primarily due to proceeds from debt issuances and capital contributions from Southern Company, partially offset by net repayments of commercial paper borrowings and common stock dividend payments to Southern Company. Net cash provided from (used for) financing activities totaled $2.1 billion for the successor period of July 1, 2016 through September 30, 2016 and $(558) million for the predecessor period of January 1, 2016 through June 30, 2016 primarily due to net repayments of commercial paper borrowings, the redemption of long-term debt, and common stock dividend payments to shareholders, partially offset by proceeds from debt issuances. The successor period of July 1, 2016 through September 30, 2016 also includes capital contributions from Southern Company to fund the investment in SNG. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

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Significant balance sheet changes at September 30, 2017 include an increase of $847 million in total property, plant, and equipment primarily due to capital expenditures for infrastructure replacement programs, an increase in long-term debt of $603 million primarily due to $450 million of senior notes and $200 million of first mortgage bonds at Nicor Gas issued in May 2017 and August 2017, respectively, and a decrease of $323 million in notes payable related primarily to net repayments of commercial paper borrowings at Nicor Gas. Other significant balance sheet changes include an increase of $239 million in accumulated deferred income taxes, primarily as a result of tax depreciation related to infrastructure assets placed in service as well as the impact of State of Illinois tax legislation, and decreases of $196 million and $146 million in energy marketing receivables and payables, respectively, due to lower natural gas prices.

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 for its infrastructure programs, scheduled maturities of long-term debt and the related interest, as well as pipeline charges, storage capacity, and gas supply, operating leases, asset management agreements, standby letters of credit and performance/surety bonds, financial derivative obligations, pension and other postretirement benefit plans, and other purchase commitments, primarily related to environmental remediation liabilities. There are no scheduled maturities of long-term debt through September 30, 2018. 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, short-term debt borrowings under its commercial paper programs, external securities issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, depend upon regulatory approval, prevailing market conditions, and other factors. 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.

At September 30, 2017, Southern Company Gas' current liabilities exceeded current assets by $645 million primarily as a result of $934 million in notes payable. 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, commercial paper, and debt securities issuances, as market conditions permit, as well as equity contributions from Southern Company 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.

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At September 30, 2017, Southern Company Gas had approximately $21 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2017 were as follows:

Company	Expires 2022		Unused
	(millions)
Southern Company Gas Capital	$	1,200	$	1,161
Nicor Gas	700		700
Total	$	1,900	$	1,861

Additionally, Pivotal Utility Holdings is party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds totaling $200 million have been issued.

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 (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

In May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement (Facility) currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022, as reflected in the table above. Pursuant to the Facility, the allocations may be adjusted.

The Facility contains a covenant that limits the ratio of debt to capitalization (as defined in each 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, 2017, 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.

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 commercial paper borrowings were as follows:

	Commercial Paper at September 30, 2017				Commercial Paper 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	$	836	1.5	%	$	680	1.5	%	$	838
Nicor Gas	98		1.3		40		1.3		120
Total	$	934	1.5	%	$	720	1.5	%

(*) Average and maximum amounts are based upon daily balances during the successor three-month period ended September 30, 2017.

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.

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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 requirements under these contracts at September 30, 2017 were $12 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 March 24, 2017, S&P revised its consolidated credit rating outlook for Southern Company and its subsidiaries (including Southern Company Gas, Southern Company Gas Capital, and Nicor Gas) from stable to negative.

Financing Activities

The long-term debt on Southern Company Gas' consolidated balance sheets includes both principal and non-principal components. As of September 30, 2017, the non-principal components totaled $523 million, which consisted of the unamortized portions of the fair value adjustment recorded in purchase accounting, debt premiums, debt discounts, and debt issuance costs.

In December 2016, Southern Company Gas executed intercompany promissory notes to further allocate interest expense to its reportable segments that previously remained in the "all other" segment. These intercompany promissory notes allow Southern Company Gas to calculate net income, which is its performance measure subsequent to the Merger, at the segment level that incorporates the full impact of interest costs.

In May 2017, Southern Company Gas Capital issued $450 million aggregate principal amount of Series 2017A 4.40% Senior Notes due May 30, 2047. The proceeds were used to repay Southern Company Gas' short-term indebtedness and for general corporate purposes.

In July 2017, Atlanta Gas Light Company repaid at maturity $22 million of Series C medium-term notes.

In July 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage Bonds 3.62% Series due August 10, 2037. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. The remaining $200 million is expected to be issued in November 2017.

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 successor third quarter and year-to-date 2017. 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 (C) and (H) 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.

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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. The following table illustrates the change in the net fair value of Southern Company Gas' derivative instruments during all periods presented, and provides details of the net fair value of contracts outstanding as of the dates presented.

	Successor												Predecessor
	Third Quarter			Third Quarter			Year-to-Date			July 1, 2016 through September 30, 2016			January 1, 2016 through June 30, 2016
	2017			2016			2017
	(in millions)												(in millions)
Contracts outstanding at beginning of period, assets (liabilities), net	$	51		$	(54	)	$	12		$	(54	)	$	75
Contracts realized or otherwise settled	(6		)	(3		)	(22		)	(3		)	(77		)
Current period changes(a)	(16		)	—			39			—			(82		)
Contracts outstanding at the end of period, assets (liabilities), net	29			(57		)	29			(57		)	(84		)
Netting of cash collateral	76			111			76			111			120
Cash collateral and net fair value of contracts outstanding at end of period(b)	$	105		$	54		$	105		$	54		$	36

(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 instruments outstanding includes premiums and the intrinsic values associated with weather derivatives of $13 million at September 30, 2017 and $7 million at September 30, 2016.

The maturities of Southern Company Gas' energy-related derivative contracts at September 30, 2017 were as follows:

				Fair Value Measurements
				Successor – September 30, 2017
	Total Fair Value			Maturity
				Year 1			Years 2 & 3			Years 4 and thereafter
	(in millions)
Level 1(a)	$	(35	)	$	(10	)	$	(20	)	$	(5	)
Level 2(b)	64			12			45			7
Fair value of contracts outstanding at end of period(c)	$	29		$	2		$	25		$	2

(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 $76 million at September 30, 2017.

205

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	207
B	Contingencies and Regulatory Matters	213
C	Fair Value Measurements	236
D	Stockholders' Equity	240
E	Financing	242
F	Retirement Benefits	247
G	Income Taxes	253
H	Derivatives	255
I	Acquisitions and Dispositions	270
J	Joint Ownership Agreements	273
K	Segment and Related Information	275

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
Alabama Power	A, B, C, E, F, G, H
Georgia Power	A, B, C, E, F, G, H
Gulf Power	A, B, C, E, F, G, H
Mississippi Power	A, B, C, E, F, G, H
Southern Power	A, B, C, D, E, G, H, I
Southern Company Gas	A, B, C, E, F, G, H, I, J, K

206

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, 2016 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, 2017 and 2016. 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.

Southern Company's financial statements reflect its investments in its subsidiaries, including Southern Company Gas as a result of the Merger, on a consolidated basis. Southern Company Gas' results of operations and cash flows for the three and nine months ended September 30, 2017 and the three months ended September 30, 2016, as well as its financial condition as of September 30, 2017 and December 31, 2016, are reflected within Southern Company's consolidated amounts in these accompanying notes herein. The equity method is used for entities in which Southern Company has significant influence but does not control, including Southern Company Gas' investment in SNG, and for variable interest entities where Southern Company has an equity investment but is not the primary beneficiary. See Note (I) under "Southern Company– Merger with Southern Company Gas" for additional information regarding the Merger.

Pursuant to the Merger, Southern Company pushed down the application of the acquisition method of accounting to the consolidated financial statements of Southern Company Gas such that the assets and liabilities are recorded at their respective fair values, and goodwill has been established for the excess of the purchase price over the fair value of net identifiable assets. Accordingly, the consolidated financial statements of Southern Company Gas for periods before and after July 1, 2016 (acquisition date) reflect different bases of accounting, and the financial positions and results of operations of those periods are not comparable. Throughout Southern Company Gas' condensed consolidated financial statements and the accompanying notes herein, periods prior to July 1, 2016 are identified as "predecessor," while periods after the acquisition date are identified as "successor."

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.

207

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Recently Issued 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.

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. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While the registrants expect most of their revenue to be included in the scope of ASC 606, they have not fully completed the evaluation of all revenue arrangements. The majority of Southern Company's, the traditional electric operating companies', and Southern Company Gas' revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined contractual term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements. The majority of Southern Power's revenues includes longer-term PPAs for generation capacity and energy. The registrants expect the adoption of ASC 606 will not result in a significant shift from the current timing of revenue recognition for such transactions.

The registrants' ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the registrants' financial statements.In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company, the traditional electric operating companies, and Southern Company Gas expect CIAC to be out of the scope of ASC 606.

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The registrants intend to use the modified retrospective method of adoption effective January 1, 2018. The registrants have also elected to utilize practical expedients which allow them to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in the registrants' financial statements, the registrants will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.

On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017. Southern Company and Southern Company Gas are evaluating the standard and expect to early adopt ASU 2017-04 effective January 1, 2018.

On March 10, 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

208

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's, the traditional electric operating companies', and Southern Company Gas' operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Southern Company's, the traditional electric operating companies', or Southern Company Gas' financial statements.

On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. 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 and interim periods within those fiscal years, with early adoption permitted. The registrants are evaluating the standard and expect to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on the registrants' financial statements.

Affiliate Transactions

Prior to the completion of Southern Company Gas' acquisition of its 50% equity interest in SNG, SCS (as agent for Alabama Power, Georgia Power, and Southern Power) and Southern Company Gas had entered into long-term interstate natural gas transportation agreements with SNG. The interstate transportation service provided to Alabama Power, Georgia Power, Southern Power, and Southern Company Gas by SNG pursuant to these agreements is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the nine months ended September 30, 2017, transportation costs under these agreements for Alabama Power, Georgia Power, Southern Power, and Southern Company Gas were approximately $8 million, $77 million, $19 million, and $24 million, respectively. For the period subsequent to Southern Company Gas' investment in SNG through September 30, 2016, transportation costs under these agreements for Alabama Power, Georgia Power, Southern Power, and Southern Company Gas were approximately $1 million, $8 million, $2 million, and $4 million, respectively.

SCS, as agent for Georgia Power and Southern Power, has agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. For the nine months ended September 30, 2017, natural gas purchases made by Georgia Power and Southern Power from Southern Company Gas' subsidiaries were approximately $18 million and $94 million, respectively. For the period subsequent to Southern Company's acquisition of Southern Company Gas through September 30, 2016, natural gas purchases made by Georgia Power and Southern Power from Southern Company Gas' subsidiaries were approximately $7 million and $2 million, respectively.

209

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Goodwill and Other Intangible Assets

At September 30, 2017 and December 31, 2016, goodwill was as follows:

	Goodwill
	At September 30, 2017		At December 31, 2016
	(in millions)
Southern Company	$	6,267	$	6,251
Southern Power	$	2	$	2
Southern Company Gas
Gas distribution operations	$	4,702	$	4,702
Gas marketing services	1,265		1,265
Southern Company Gas total	$	5,967	$	5,967

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.

210

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Other intangible assets were as follows:

	At September 30, 2017							At December 31, 2016
	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	$	288	$	(70	)	$	218	$	268	$	(32	)	$	236
Trade names	159		(15		)	144		158		(5		)	153
Storage and transportation contracts	64		(27		)	37		64		(2		)	62
PPA fair value adjustments	456		(41		)	415		456		(22		)	434
Other	16		(3		)	13		11		(1		)	10
Total other intangible assets subject to amortization	$	983	$	(156	)	$	827	$	957	$	(62	)	$	895
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	$	75	$	—		$	75	$	75	$	—		$	75
Total other intangible assets	$	1,058	$	(156	)	$	902	$	1,032	$	(62	)	$	970
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	456	$	(41	)	$	415	$	456	$	(22	)	$	434
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	221	$	(65	)	$	156	$	221	$	(30	)	$	191
Trade names	115		(8		)	107		115		(2		)	113
Wholesale gas services
Storage and transportation contracts	64		(27		)	37		64		(2		)	62
Total other intangible assets subject to amortization	$	400	$	(100	)	$	300	$	400	$	(34	)	$	366

211

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Nine Months Ended
	September 30, 2017
	(in millions)
Southern Company	$	29	$	94
Southern Power	$	6	$	19
Southern Company Gas	$	20	$	66

See Note 12 to the financial statements of Southern Company under "Southern Power" and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information regarding Southern Power's PPA fair value adjustments related to its business acquisitions. Also see Note (I) under "Southern Company– Acquisition of PowerSecure" and " –Merger with Southern Company Gas" for additional information.

Property Damage Reserve

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.

Gulf Power's cost of repairing damages from major storms and other uninsured property damages, including uninsured damages to transmission and distribution facilities, generation facilities, and other property is charged to Gulf Power's property damage reserve. In accordance with a settlement agreement approved by the Florida PSC on April 4, 2017 (2017 Rate Case Settlement Agreement), Gulf Power suspended further property damage reserve accruals effective April 2017. Gulf Power may make discretionary accruals and is required to resume accruals of $3.5 million annually if the reserve balance falls below zero. In addition, Gulf Power may initiate a storm surcharge to recover costs associated with any tropical systems named by the National Hurricane Center or other catastrophic storm events that reduce the property damage reserve in the aggregate by approximately $31 million (75% of the April 1, 2017 balance) or more. The storm surcharge would begin, on an interim basis, 60 days following the filing of a cost recovery petition, would be limited to $4.00/month for a 1,000 KWH residential customer unless Gulf Power incurs in excess of $100 million in qualified storm recovery costs in a calendar year, and would replenish the property damage reserve to approximately $40 million. As of September 30, 2017, Gulf Power's property damage reserve totaled approximately $39 million. See Note (B) under "Regulatory Matters–Gulf Power– Retail Base Rate Cases" for additional details regarding the 2017 Rate Case Settlement Agreement.

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, 2017. 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.

212

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(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 regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, 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

On January 20, 2017, a purported 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 IGCC 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. On June 12, 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. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition on September 11, 2017.

On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District 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 defendants caused Southern Company to make false or misleading statements regarding the Kemper IGCC cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.

On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia and, on May 31, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. Each 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 IGCC. Each complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper IGCC schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages

213

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.

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.

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 November 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court for further proceedings. Georgia Power filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted on August 28, 2017. A decision from the Georgia Supreme Court is not expected until 2018. Georgia Power believes the plaintiffs' claims have no merit and intends to vigorously defend itself in this matter. The ultimate outcome of this matter cannot be determined at this time.

Southern Power

During 2015, Southern Power indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas, which was under construction by Recurrent Energy, LLC and was subsequently placed in service in November 2016. Prior to placing the facility in service, certain solar panels were damaged during installation. While the facility currently is generating energy consistent with operational expectations and PPA obligations, Southern Power is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. In connection therewith, Southern Power is withholding payments of approximately $26 million from the construction contractor, who has placed a lien on the Roserock facility for the same amount. The amounts withheld are included in other accounts and notes payable and other current liabilities on Southern Company's consolidated balance sheets and other accounts payable and other current liabilities on Southern Power's consolidated balance sheets. On May 18, 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, against X.L. America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from a hail storm and certain installation practices by the construction contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthy in the state district court in Travis County, Texas alleging breach of contract and breach of warranty for the damages sustained at the Roserock facility, which has since been moved to the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filed a counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things, breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. 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 Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. were defendants in a putative class action initially filed in 2011 in the state court in Cook County, Illinois. The plaintiffs purported to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously alleged that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs sought, on behalf of the classes they

214

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

purported to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On February 8, 2017, the judge denied the plaintiffs' motion for class certification and Southern Company Gas' motion for summary judgment. On March 7, 2017, the parties reached a settlement, which was finalized and effective on April 3, 2017. The settlement did not have a material impact on Southern Company's or Southern Company Gas' financial statements.

Environmental Matters

Environmental Remediation

The Southern Company system must comply with environmental laws and regulations that cover 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, New Jersey, Georgia, and Florida have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.

Georgia Power's environmental remediation liability was $26 million and $17 million as of September 30, 2017 and December 31, 2016, 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 $53 million and $44 million as of September 30, 2017 and December 31, 2016, 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. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.

Southern Company Gas' environmental remediation liability was $399 million and $426 million as of September 30, 2017 and December 31, 2016, respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities, with the exception of one site representing $5 million of the total accrued remediation costs.

The final outcome of these matters cannot be determined at this time. However, 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.

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 (LDNR). 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, 2017, the facility's property, plant, and equipment had a net book value of $111 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including the results of ongoing third-party technical engineering reviews, testing, and compliance with an order from the LDNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining a core sample to determine the composition of the sheath surrounding the edge of the salt dome. Early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage

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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.

Nuclear Fuel Disposal Costs

See Note 3 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Fuel Disposal Costs" in Item 8 of the Form 10-K for additional information regarding legal remedies pursued by Alabama Power and Georgia Power against the U.S. government for its partial breach of contract relating to the disposal of spent nuclear fuel and high level radioactive waste generated at each company's nuclear plants.

On October 10, 2017, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government in the Court of Federal Claims for the costs of continuing to store spent nuclear fuel at Plant Farley, Plant Hatch, and Plant Vogtle Units 1 and 2 for the period from January 1, 2015 through December 31, 2017. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of September 30, 2017 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.

FERC Matters

Municipal and Rural Associations Tariff

See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding a settlement agreement entered into by Mississippi Power regarding the establishment of a regulatory asset for Kemper IGCC-related costs. See "Integrated Coal Gasification Combined Cycle" herein for information regarding the Kemper IGCC.

In March 2016, Mississippi Power reached a settlement agreement with its wholesale customers, which was subsequently approved by the FERC, for an increase in wholesale base revenues under the MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking through an order issued by the Mississippi PSC in December 2015 (In-Service Asset Rate Order). This regulatory treatment primarily includes (i) recovery of the Kemper IGCC assets currently operational and providing service to customers and other related costs, (ii) amortization of the Kemper IGCC-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper IGCC-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper IGCC CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC totaled approximately $22 million through the suspension of Kemper IGCC start-up activities.

See "Integrated Coal Gasification Combined Cycle" herein for additional information.

Fuel Cost Recovery

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At September 30, 2017, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $3 million compared to $13 million at December 31, 2016. Over-recovered wholesale MB fuel costs included in the balance sheets were immaterial at September 30, 2017 and December 31, 2016.

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.

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Market-Based Rate Authority

See Note 3 to the financial statements of Southern Company and Mississippi Power under "FERC Matters – Market-Based Rate Authority" and Note 3 to the financial statements of Alabama Power, Georgia Power, Gulf Power, and Southern Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.

On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.

On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.

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

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, 2017		December 31, 2016
		(in millions)
Rate CNP Compliance	Deferred over recovered regulatory clause revenues	$	9	$	—
Rate CNP Compliance(*)	Deferred under recovered regulatory clause revenues	—		9
Rate CNP PPA	Deferred under recovered regulatory clause revenues	17		142
Retail Energy Cost Recovery(*)	Other regulatory liabilities, current	—		76
Natural Disaster Reserve	Other regulatory liabilities, deferred	51		69

(*) In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its under recovered balance for Rate CNP Compliance and $11 million of its under recovered balance for Retail Energy Cost Recovery to a deferred regulatory asset account.

Georgia Power

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.

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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 the construction 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 "Regulatory Matters – Georgia Power – 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.

Integrated Resource Plan

See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Integrated Resource Plan" and "Retail Regulatory Matters – Integrated Resource Plan," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan.

On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at a future generation site in Stewart County, Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing of recovery for costs incurred of approximately $50 million will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.

As of September 30, 2017, Georgia Power's under recovered fuel balance totaled $100 million and is included in current assets and other deferred charges and assets on Southern Company's and Georgia Power's condensed balance sheets. As of December 31, 2016, Georgia Power's over recovered fuel balance totaled $84 million and is included in other current liabilities on Southern Company's and Georgia Power's condensed balance sheets.

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

Georgia Power is accruing$30 millionannually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. During September 2017, Hurricane Irma caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of incremental restoration costs related to this hurricane is estimated to be approximately $150 million. As of September 30, 2017, Georgia Power had deferred approximately $145 million in a regulatory asset related to storm damage. As of September 30, 2017, the total balance in Georgia Power's regulatory asset related to storm damage was $360 million. Therate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's or Georgia Power's financial statements.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.

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Nuclear Construction

See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – 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, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, and the Contractor Settlement Agreement.

Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy

In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Georgia Power's proportionate share of Plant Vogtle Units 3 and 4 is 45.7%.

The Vogtle 3 and 4 Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed.

Under the terms of the Vogtle 3 and 4 Agreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the Vogtle 3 and 4 Agreement was 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest).

On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the EPC Contractor (Interim Assessment Agreement), which the bankruptcy court approved on March 30, 2017.

The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided. The Interim Assessment Agreement, as amended, expired on July 27, 2017.

Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through September 30, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which $340 million had been paid or accrued as of September 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $176 million.

On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee

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Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, which will reduce CWIP, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million. Georgia Power is considering potential options with respect to its right to future payments under the Guarantee Settlement Agreement and its claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to DOE consents and related approvals under the Loan Guarantee Agreement and related agreements.

On August 10, 2017, Toshiba released its financial results for the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $4.5 billion as of June 30, 2017. Toshiba previously announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's and Georgia Power's financial statements.

Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into a services agreement (Services Agreement), which was 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. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement (Bechtel Agreement) with Bechtel Power Corporation (Bechtel), whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4. Facility design and engineering remains the responsibility of the EPC Contractor under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a 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 at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of

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(UNAUDITED)

the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement, 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 connection with the recommendation to continue with construction of Plant Vogtle Units 3 and 4 (described below), the Vogtle Owners agreed on a term sheet to amend the existing joint ownership agreements to provide for additional Vogtle Owner approval requirements. Under the 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 adverse events occur, including (i) the bankruptcy of Toshiba or a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) 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 because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report by more than $1 billion or extension of the project schedule contained in the seventeenth VCM report by more than one year. In addition, under the term sheet, 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 Services Agreement or agreements with the primary construction contractor or Southern Nuclear.

The term sheet also confirms 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.

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 nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. As of September 30, 2017, Georgia Power had recovered approximately $1.5 billion of financing costs. Georgia Power expects to file on November 1, 2017 to increase the NCCR tariff by approximately $90 million, effective January 1, 2018, pending Georgia PSC approval.

On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia

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Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not placed in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.

The Georgia PSC has approved sixteen VCM reports covering the periods through December 31, 2016, including construction capital costs incurred, which through that date totaled $3.9 billion. Georgia Power filed its seventeenth VCM report, covering the period from January 1 through June 30, 2017, requesting approval of $542 million of construction capital costs incurred during that period, with the Georgia PSC on August 31, 2017.

In the seventeenth VCM report, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4. Georgia Power's recommendation to go forward with completion of Vogtle Units 3 and 4 is based on the following assumptions about the regulatory treatment of this recommendation, if the recommendation to go forward is adopted by the Georgia PSC: (i) that pursuant to Georgia law, the Georgia PSC in the seventeenth VCM proceeding approves the new cost and schedule forecast and finds that it is a reasonable basis for going forward, and that if the Georgia PSC disapproves all or part of the proposed cost and schedule revisions, Georgia Power may cancel Plant Vogtle Units 3 and 4 and recover its actual investment in Plant Vogtle Units 3 and 4; (ii) that the Vogtle Cost Settlement Agreement remains in full force and effect, including Georgia Power retaining the burden of proving all capital costs above $5.680 billion were prudent; (iii) that while the Georgia PSC will make no prudence finding in the seventeenth VCM proceeding, nor will the certified amount be amended consistent with the Vogtle Cost Settlement Agreement, the Georgia PSC recognizes that the certified amount is not a cap, and all costs that are approved and presumed or shown to be prudently incurred will be recoverable by Georgia Power; (iv) that Georgia Power is not a guarantor of the Toshiba Guarantee, and the failure of Toshiba to pay the Toshiba Guarantee, the failure of the U.S. Congress to extend the PTCs for Plant Vogtle Units 3 and 4, or the failure of the DOE to extend the Loan Guarantee Agreement with Georgia Power to reflect the increased capital amounts, will not reduce the amount of investment Georgia Power is otherwise allowed to collect; and (v) that as conditions change and assumptions are either proven or disproven, Georgia Power and the Georgia PSC may reconsider the decision to go forward. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.

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

Revised Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 is as follows:

	(in billions)
Estimated cost to complete	$	4.2
CWIP as of September 30, 2017	4.6
Guarantee Obligations	(1.7		)
Estimated capital costs	$	7.1
Vogtle Cost Settlement Agreement Revised Forecast	(5.7		)
Estimated net additional capital costs	$	1.4

Georgia Power's estimated financing costs during the construction period total approximately $3.4 billion, of which approximately $1.5 billion had been incurred through September 30, 2017.

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Georgia Power's cancellation cost estimate results indicate that its proportionate share of the estimated costs to cancel both units is approximately $350 million. As a result, as of September 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:

	Cancellation Cost Estimate
	(in billions)
CWIP as of September 30, 2017	$	4.6
Financing costs collected, net of tax	1.5
Cancellation costs(*)	0.4
Guarantee Obligations	(1.7		)
Estimated net cancellation cost	$	4.8

(*) The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site.

The Guarantee Obligations continue to exist in the event of cancellation. In addition, under Georgia law, prudently incurred costs related to certificated projects cancelled by the Georgia PSC are allowed recovery, including carrying costs, in future retail rates. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery.

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

Other Matters

As of September 30, 2017, 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. On September 28, 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. 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 (E) under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the applicable unit be placed in service prior to 2021. The net present value of Georgia Power's PTCs is estimated at approximately $400 million per unit.

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 while construction proceeds. 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 and the related approvals by the NRC, may arise while construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

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While construction continues, the risk remains that challenges with management of contractors, subcontractors, and vendors, labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost.

The ultimate outcome of these matters 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.

Retail Base Rate Cases

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.

In 2013, the Florida PSC approved a settlement agreement that authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction could not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. For 2014 and 2015, Gulf Power recognized reductions in depreciation of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016. Through June 2017, Gulf Power recognized the remaining allowable reductions in depreciation totaling $34.0 million.

On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and three intervenors with respect to Gulf Power's request to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%), is deemed to have an equity ratio of 52.5% for all retail regulatory purposes, and implemented new dismantlement accruals effective July 1, 2017. Gulf Power will also begin amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and will implement new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.

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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. Gulf Power has four regulatory clauses which are approved by the Florida PSC. The balance of each regulatory clause recovery on the balance sheet follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2017		December 31, 2016
		(in millions)
Fuel Cost Recovery	Under recovered regulatory clause revenues	$	13	$	—
Fuel Cost Recovery	Other regulatory liabilities, current	—		15
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	1		—
Environmental Cost Recovery	Other regulatory liabilities, current	1		—
Environmental Cost Recovery	Under recovered regulatory clause revenues	—		13
Energy Conservation Cost Recovery	Under recovered regulatory clause revenues	1		4

As discussed previously, the 2017 Rate Case Settlement Agreement resolved the remaining issues related to Gulf Power's inclusion of certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 in the environmental cost recovery clause and no adjustment to the environmental cost recovery clause rate approved by the Florida PSC in November 2016 was made.

On October 25, 2017, 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 2018. The net effect of the approved changes is a $63 million increase in annual revenues effective in January 2018, the majority of which will be offset by related expense increases.

Mississippi Power

Performance Evaluation Plan

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's base rates.

On March 15, 2017, Mississippi Power submitted its annual PEP lookback filing for 2016, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time.

Energy Efficiency

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Energy Efficiency" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's energy efficiency programs.

On July 6, 2017, the Mississippi PSC issued an order approving Mississippi Power's Energy Efficiency Cost Rider compliance filing, which increased annual retail revenues by approximately $2 million effective with the first billing cycle for August 2017.

Environmental Compliance Overview Plan

On May 4, 2017, the Mississippi PSC approved Mississippi Power's ECO Plan filing for 2017, which requested the maximum 2% annual increase in revenues, approximately $18 million, primarily related to the Plant Daniel Units 1

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and 2 scrubbers placed in service in 2015. The rates became effective with the first billing cycle for June 2017. Approximately $26 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2018 filing.

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 Form 10-K for additional information regarding Mississippi Power's retail fuel cost recovery.

At September 30, 2017, the amount of over-recovered retail fuel costs included on Mississippi Power's condensed balance sheet was $2 million compared to $37 million at December 31, 2016.

Ad Valorem Tax Adjustment

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's ad valorem tax adjustments.

On July 6, 2017, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2017, which included an annual rate increase of 0.85%, or $8 million in annual retail revenues, primarily due to increased assessments.

Southern Company Gas

Riders

Nicor Gas has established a variable tax cost adjustment rider, which was approved by the Illinois Commission effective July 16, 2017. This rider provides for recovery of the invested capital tax imposed on Nicor Gas through an annual true-up and reconciliation mechanism based on amounts approved in prior rate cases. Accordingly, this rider will not have a significant effect on Southern Company Gas' net income.

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

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

Settled Base Rate Cases

On February 21, 2017, the Georgia PSC approved the Georgia Rate Adjustment Mechanism (GRAM) and a $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, based on the previously approved ROE of 10.75% and does not collect revenue through special riders and surcharges. Various infrastructure programs previously authorized by the Georgia PSC under Atlanta Gas Light's STRIDE program, which include the Integrated Vintage Plastic Replacement Program and Integrated System Reinforcement Program, will continue under GRAM and the recovery of and return on the infrastructure program investments will be included in annual base rate adjustments. The Georgia PSC will review Atlanta Gas Light's performance annually under GRAM.

Pursuant to the GRAM approval, Atlanta Gas Light and the staff of the Georgia PSC agreed to a variation to the Integrated Customer Growth Program that was formerly part of Atlanta Gas Light's STRIDE program. As a result, a

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new tariff was created, effective October 10, 2017, to provide $15 million annually for Atlanta Gas Light to commit to strategic economic development projects.

Beginning with the next rate adjustment in June 2018, Atlanta Gas Light's recovery of the previously unrecovered Pipeline Replacement Program revenue through 2014, as well as the mitigation costs associated with the Pipeline Replacement Program that were not previously included in its rates, will also be included in GRAM. In connection with the GRAM approval, the last monthly Pipeline Replacement Program surcharge increase became effective March 1, 2017.

In September 2016, Elizabethtown Gas filed a general base rate case with the New Jersey BPU requesting a $19 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year ending March 31, 2017 and a ROE of 10.25%. On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on a ROE of 9.6%. Also included in the settlement was a new composite depreciation rate that is expected to result in a $3 million annual reduction of depreciation. See Note (I) under "Southern Company Gas" for information on the proposed sale of Elizabethtown Gas.

Pending Base Rate Cases

On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase in December 2017, after which rate adjustments will be effective.

On March 31, 2017, Virginia Natural Gas filed a general base rate case with the Virginia Commission requesting a $44 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year beginning September 1, 2017 and a ROE of 10.25%. The requested increase included $13 million related to the recovery of investments under the Steps to Advance Virginia's Energy (SAVE) program. On October 3, 2017, Virginia Natural Gas entered into a proposed stipulation with the Staff of the Virginia Commission, the Office of the Attorney General, Division of Consumer Counsel, and the Virginia Industrial Gas Users' Association resolving all related issues. The proposed stipulation includes a $34 million increase in annual base rate revenues, including $13 million related to the recovery of investments under the SAVE program. An authorized ROE range of 9.0% to 10.0% with a midpoint of 9.5% will be used to determine the revenue requirement in any filing, other than for a change in base rates. The Virginia Commission is expected to rule on the proposed stipulation in the fourth quarter 2017. Rate adjustments based on the proposed stipulation became effective September 1, 2017, subject to refund.

On October 23, 2017, Florida City Gas filed a general base rate case with the Florida PSC requesting a $19 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 11.25%. The requested increase includes $3 million related to the recovery of investments under the Safety, Access, and Facility Enhancement (SAFE) program. Additionally, Florida City Gas requested interim rates of $5 million to be effective in January 2018, subject to refund. The Florida PSC is expected to rule on the requested increase in mid-2018.

The ultimate outcome of these pending base rate cases 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 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.

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Nicor Gas

In 2014, the Illinois Commission approved Nicor Gas' nine-year regulatory infrastructure program, Investing in Illinois. Under this program, Nicor Gas placed into service $178 million of qualifying assets during the first nine months of 2017.

Atlanta Gas Light

Atlanta Gas Light's STRIDE program, which started in 2009, consists of three individual programs that update and expand gas distribution systems and LNG facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, Atlanta Gas Light invested $127 million during the first nine months of 2017. The recovery of and return on current and future capital investments under the STRIDE program are included in the annual base rate revenue adjustment under GRAM.

In August 2016, Atlanta Gas Light filed a petition with the Georgia PSC for approval of a four-year extension of its Integrated System Reinforcement Program (i-SRP) seeking approval to invest an additional $177 million to improve and upgrade its core gas distribution system in years 2017 through 2020. Subsequently, the proposed capital investments associated with the extension of i-SRP were included in the 2017 annual base rate revenue under GRAM approved by the Georgia PSC on February 21, 2017.

See "Base Rate Cases" herein for additional information.

Elizabethtown Gas

In 2013, the New Jersey BPU approved the extension of Elizabethtown Gas' Aging Infrastructure Replacement program, under which Elizabethtown Gas invested $16 million during the first nine months of 2017. Effective July 1, 2017, investments under this program are being recovered through base rate revenues.

Virginia Natural Gas

In March 2016, the Virginia Commission approved an extension to the SAVE program, under which Virginia Natural Gas invested $21 million during the first nine months of 2017.

Florida City Gas

The Florida PSC approved Florida City Gas' SAFE program in 2015. Under the program, Florida City Gas invested $9 million during the first nine months of 2017.

Integrated Coal Gasification Combined Cycle

See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.

Kemper IGCC Overview

The Kemper IGCC was designed to utilize IGCC technology with an expected output capacity of 582 MWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed approximately 61 miles of CO₂ pipeline infrastructure for the transport of captured CO₂ for use in enhanced oil recovery.

Kemper IGCC Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power

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Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014.

The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO₂, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has increased significantly since certification.

On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC (Kemper IGCC Settlement Docket). On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014.

Mississippi Power's Kemper IGCC 2010 project estimate totaled $2.97 billion, which included capped costs of $2.4 billion. At the time of project suspension in June 2017, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE for the Kemper IGCC (Additional DOE Grants).

Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap for the Kemper IGCC of $196 million ($121 million after tax) in the second quarter through May 31, 2017 and a total of $305 million ($188 million after tax) for year-to-date through May 31, 2017. In the aggregate, Mississippi Power incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. The May 31, 2017 cost estimate included approximately $175 million of estimated costs to be incurred beyond the then-estimated in-service date of June 30, 2017 that were expected to be subject to the $2.88 billion cost cap.

While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure

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costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred. In the aggregate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC totaling $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017.

As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC. The Kemper combined cycle balances as presented in the condensed balance sheet at September 30, 2017 include $1.1 billion in property, plant, and equipment, net of $80 million in accumulated depreciation; $15 million in materials and supplies; $10 million in other deferred charges and assets; and $113 million in regulatory assets, net of accumulated amortization of $63 million, of which $21 million is included in other regulatory assets, current and $92 million in other regulatory assets, deferred.

Rate Recovery of Kemper IGCC Costs

Given the variety of potential scenarios and the uncertainty of the outcome of future regulatory proceedings with the Mississippi PSC (and any subsequent related legal challenges), the ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, cannot now be determined but could result in further material charges that could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity.

Kemper IGCC Settlement Docket

On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.

On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.

Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the Mississippi Public Utilities Staff (MPUS)), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.

While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs

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associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.

As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.

Prudence

On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceedings and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years after the Kemper IGCC was to be placed in service. Compared to amounts presented in the 2010 CPCN proceedings, operations and maintenance expenses have increased an average of $105 million annually and maintenance capital has increased an average of $44 million annually for the first full five years of operations for the Kemper IGCC. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. On November 17, 2016, Mississippi Power submitted a supplemental filing to the October 3, 2016 compliance filing to present revised non-fuel operations and maintenance expense projections for the first year after the Kemper IGCC was to be placed in service. This supplemental filing included approximately $68 million in additional estimated operations and maintenance costs expected to be required to support the operations of the Kemper IGCC during that period.

Mississippi Power responded to numerous requests for information from interested parties in the discovery docket, which is now complete. Mississippi Power expects the Mississippi PSC to utilize this information in connection with the ultimate resolution of Kemper IGCC cost recovery.

Economic Viability Analysis

In the fourth quarter 2016, as a part of its Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected. As a result of the updated long-term natural gas forecast, as well as the revised operating expense projections reflected in the discovery docket filings discussed above, on February 21, 2017, Mississippi Power filed an updated project economic viability analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order confirming authorization of the Kemper IGCC. The project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast

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and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis.

Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.

2015 Rate Case

On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full a stipulation entered into between Mississippi Power and the MPUS regarding the Kemper IGCC assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by Cooperative Energy but reserved Mississippi Power's right to seek recovery in a future proceeding. See "Termination of Proposed Sale of Undivided Interest" herein for additional information.

In 2011, the Mississippi PSC authorized Mississippi Power to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date. In connection with the implementation of the In-Service Asset Order and wholesale rates, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of September 30, 2017, the balance associated with these regulatory assets was $113 million, of which $21 million is included in current assets. See "FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.

The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, for the May 31, 2016 and 2017 calculations. At September 30, 2017, Mississippi Power's related regulatory liability totaled approximately $10 million.

As required by the In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in the In-Service Asset Order in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable. At September 30, 2017, the related regulatory liability totaled $7 million.

2013 MPSC Rate Order

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (construction cost increase demonstrated to produce efficiencies that result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions), but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate

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order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC was placed in service, based on a mirror CWIP methodology (Mirror CWIP rate).

On February 12, 2015, the Mississippi Supreme Court reversed the 2013 MPSC Rate Order and, on July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million previously collected, along with associated carrying costs of $29 million.

Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continued to record AFUDC on the Kemper IGCC. Between the original May 2014 estimated in-service date and the June 2017 project suspension date, Mississippi Power recorded $494 million of AFUDC on the Kemper IGCC subject to the $2.88 billion cost cap and Cost Cap Exception amounts, of which $460 million related to the gasification portions of the Kemper IGCC.

Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.

Lignite Mine and CO₂ Pipeline Facilities

In conjunction with the Kemper IGCC, Mississippi Power owns the lignite mine and equipment and mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.

In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is responsible for the mining operations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. During the suspension period, these costs are approximately $2 million per month and are being recognized in income as incurred. See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.

In addition, Mississippi Power constructed the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery. Mississippi Power entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC (Treetop), pursuant to which Denbury would purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop would purchase 30% of the CO₂ captured from the Kemper IGCC. On June 3, 2016, Mississippi Power cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury's agreement to purchase 100% of the CO₂ captured from the Kemper IGCC and an initial contract term of 16 years. Denbury has the right to terminate the contract at any time because Mississippi Power did not place the Kemper IGCC in service by July 1, 2017.

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

Termination of Proposed Sale of Undivided Interest

In 2010 and as amended in 2012, Mississippi Power and Cooperative Energy (formerly known as SMEPA) entered into an agreement whereby Cooperative Energy agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, Cooperative Energy notified Mississippi Power of its termination of the agreement. Mississippi Power previously received a total of $275 million of deposits from Cooperative Energy that were required to be returned to Cooperative Energy with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to Cooperative Energy. Subsequently, Mississippi Power issued a promissory note in the aggregate principal amount of approximately $301 million to Southern Company, which was repaid in June 2017.

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(UNAUDITED)

Litigation

On April 26, 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 on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have 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 IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal.

On June 9, 2016, Treetop, Greenleaf CO₂ Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO₂ contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO₂ contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages.

Southern Company and Mississippi Power believe these legal challenges have no merit; however, an adverse outcome in these proceedings 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 these matters, and the ultimate outcome of these matters cannot be determined at this time.

Baseload Act

In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery or implement credits, refunds, or rebates to customers for costs incurred in connection with such cancelled generating plant.

Income Tax Matters

See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle – Bonus Depreciation," " – Investment Tax Credits," and " – Section 174 Research and Experimental Deduction" in Item 8 of the Form 10-K and Note (G) under "Section 174 Research and Experimental Deduction" for additional information on bonus depreciation, investment tax credits, and the Section 174 research and experimental deduction.

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(UNAUDITED)

Bonus Depreciation

All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. If the suspension of the Kemper IGCC start-up activities ultimately results in an abandonment for income tax purposes, the related deduction would be claimed in the year of the abandonment. See Note (G) for additional information. The ultimate outcome of this matter cannot be determined at this time.

Section 174 Research and Experimental Deduction

Southern Company, on behalf of Mississippi Power, has reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. See Note (G) for additional information.

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(UNAUDITED)

(C) FAIR VALUE MEASUREMENTS

As of September 30, 2017, 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, 2017:	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)	$	231	$	184	$	—	$	—	$	415
Interest rate derivatives	—		5		—		—		5
Foreign currency derivatives	—		103		—		—		103
Nuclear decommissioning trusts(c)	752		1,004		—		26		1,782
Cash equivalents	1,271		—		—		—		1,271
Other investments	9		—		1		—		10
Total	$	2,263	$	1,296	$	1	$	26	$	3,586
Liabilities:
Energy-related derivatives(a)(b)	$	265	$	146	$	—	$	—	$	411
Interest rate derivatives	—		24		—		—		24
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		20		—		20
Total	$	265	$	193	$	20	$	—	$	478
Alabama Power
Assets:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9
Nuclear decommissioning trusts:(d)
Domestic equity	422		81		—		—		503
Foreign equity	60		57		—		—		117
U.S. Treasury and government agency securities	—		27		—		—		27
Corporate bonds	19		150		—		—		169
Mortgage and asset backed securities	—		18		—		—		18
Private Equity	—		—		—		26		26
Other	—		8		—		—		8
Cash equivalents	808		—		—		—		808
Total	$	1,309	$	350	$	—	$	26	$	1,685
Liabilities:
Energy-related derivatives	$	—	$	7	$	—	$	—	$	7

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(UNAUDITED)

	Fair Value Measurements Using:
As of September 30, 2017:	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)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	18	$	—	$	—	$	18
Interest rate derivatives	—		1		—		—		1
Nuclear decommissioning trusts:(d) (e)
Domestic equity	235		1		—		—		236
Foreign equity	—		156		—		—		156
U.S. Treasury and government agency securities	—		225		—		—		225
Municipal bonds	—		64		—		—		64
Corporate bonds	—		160		—		—		160
Mortgage and asset backed securities	—		38		—		—		38
Other	16		19		—		—		35
Cash equivalents	112		—		—		—		112
Total	$	363	$	682	$	—	$	—	$	1,045
Liabilities:
Energy-related derivatives	$	—	$	11	$	—	$	—	$	11
Interest rate derivatives	—		3		—		—		3
Total	$	—	$	14	$	—	$	—	$	14
Gulf Power
Assets:
Cash equivalents	$	21	$	—	$	—	$	—	$	21
Liabilities:
Energy-related derivatives	$	—	$	22	$	—	$	—	$	22
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Interest rate derivatives	—		2		—		—		2
Cash equivalents	209		—		—		—		209
Total	$	209	$	5	$	—	$	—	$	214
Liabilities:
Energy-related derivatives	$	—	$	7	$	—	$	—	$	7

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(UNAUDITED)

	Fair Value Measurements Using:
As of September 30, 2017:	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 Power
Assets:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9
Foreign currency derivatives	—		103		—		—		103
Cash equivalents	90		—		—		—		90
Total	$	90	$	112	$	—	$	—	$	202
Liabilities:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		20		—		20
Total	$	—	$	27	$	20	$	—	$	47
Southern Company Gas
Assets:
Energy-related derivatives(a)(b)	$	231	$	145	$	—	$	—	$	376
Liabilities:
Energy-related derivatives(a)(b)	$	265	$	95	$	—	$	—	$	360

(a) Excludes $13 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value.

(b) Excludes cash collateral of $76 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, 2017, approximately $66 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 at Southern Company, including reinvested interest and dividends and excluding the funds' expenses, increased by $50 million and $168 million, respectively, for the three and nine months ended September 30, 2017, and by $49 million and $116 million, respectively, for the three and nine months ended September 30, 2016. Alabama Power recorded increases in fair value of $25 million and $87 million, respectively, for the three and nine months ended September 30, 2017 and $26 million and $66 million, respectively, for the three and nine months ended September 30, 2016 as a change in regulatory liabilities related to its AROs. Georgia Power recorded increases in fair value of $25 million and $81 million, respectively, for the three and nine months ended September 30, 2017 and $23 million and $50 million, respectively, for the three and nine months ended September 30, 2016 as a change in its regulatory asset related to its AROs.

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

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(UNAUDITED)

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 (H) for additional information on how these derivatives are used.

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning 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. 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 obligated to make generation-based payments to the seller over a period ranging from 10 to 30 years, beginning at the commercial operation date. 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, and is evaluated periodically. 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, 2017, the fair value measurements of private equity investments held in the nuclear decommissioning trust 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, 2017:	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company	$	26	$	24	Not Applicable	Not Applicable
Alabama Power	$	26	$	24	Not Applicable	Not Applicable

Private equity funds include a fund-of-funds that invests 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.

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(UNAUDITED)

As of September 30, 2017, 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	$	47,269	$	49,348
Alabama Power	$	7,404	$	8,031
Georgia Power	$	11,713	$	12,237
Gulf Power	$	1,292	$	1,352
Mississippi Power	$	2,123	$	2,117
Southern Power	$	5,810	$	5,916
Southern Company Gas	$	5,862	$	6,230

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.

(D) 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 the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:

	Three Months Ended September 30, 2017	Three Months Ended September 30, 2016	Nine Months Ended September 30, 2017	Nine Months Ended September 30, 2016
	(in millions)
As reported shares	1,003	968	998	940
Effect of options and performance share award units	7	7	7	5
Diluted shares	1,010	975	1,005	945

Stock options and performance share award units 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, 2017 and 2016.

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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(*)
	(in thousands)			(in millions)
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
Balance at December 31, 2015	915,073	(3,352	)	$	20,592		$	609		$	781		$	21,982
Consolidated net income attributable to Southern Company	—	—		2,251			—			—			2,251
Other comprehensive income (loss)	—	—		(95		)	—			—			(95		)
Stock issued	65,725	2,599		3,265			—			—			3,265
Stock-based compensation	—	—		94			—			—			94
Cash dividends on common stock	—	—		(1,553		)	—			—			(1,553		)
Contributions from noncontrolling interests	—	—		—			—			357			357
Distributions to noncontrolling interests	—	—		—			—			(21		)	(21		)
Purchase of membership interests from noncontrolling interests	—	—		—			—			(129		)	(129		)
Net income attributable to noncontrolling interests	—	—		—			—			36			36
Other	—	(46	)	(7		)	—			—			(7		)
Balance at September 30, 2016	980,798	(799	)	$	24,547		$	609		$	1,024		$	26,180

(*) Related to Southern Power Company and excludes redeemable noncontrolling interests. In April 2017, approximately $114 million was reclassified from redeemable noncontrolling interests to noncontrolling interests, included in stockholder's equity, due to the expiration of SunPower Corp's option to require Southern Power to purchase its membership interests in one of the solar partnerships. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

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(UNAUDITED)

(E) FINANCING

Going Concern

As of September 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $769 million primarily due to approximately $935 million that will be required through September 30, 2018 to fund maturities of long-term debt and $4 million that will be required to fund maturities of short-term debt. In addition, Mississippi Power has $40 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilities and $50 million of fixed rate pollution control revenue bonds that are required to be remarketed over the next 12 months. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans, as market conditions permit, as well as, under certain circumstances, commercial paper and/or equity contributions and/or loans from Southern Company to fund Mississippi Power's short-term capital needs. Specifically, Mississippi Power has been informed by Southern Company that in the event sufficient funds are not available from external sources, Southern Company intends to provide Mississippi Power with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (B) under "Integrated Coal Gasification Combined Cycle."

DOE Loan Guarantee Borrowings

See Note 6 to the financial statements of Southern Company and Georgia Power in Item 8 of the Form 10-K for additional information regarding Georgia Power's Loan Guarantee Agreement with the DOE and related multi-advance term loan facility (FFB Credit Facility) with the FFB.

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 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 such time as Georgia Power has (i) completed the cost-to-complete and cancellation cost assessments prepared as a result of the bankruptcy of the EPC Contractor (Cost Assessments) and made a determination to continue construction of Plant Vogtle Units 3 and 4, (ii) delivered to the DOE an updated project schedule, construction budget, and other information, (iii) entered into one or more agreements with a construction contractor or contractors that will be primarily responsible for construction of Plant Vogtle Units 3 and 4 and such agreements have been approved by the DOE (together with the Services Agreement and the IP Licenses, the Replacement EPC Arrangements), and (iv) entered into a further amendment to the Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements.

Upon satisfaction of the conditions described above, advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.

In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, accuracy of project-related representations and warranties, delivery of updated project-related information, absence of liens on Georgia Power's ownership interest in Plant Vogtle Units 3 and 4 other than permitted liens, evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs.

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(UNAUDITED)

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 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 Services Agreement or rejection of the 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) a failure by Georgia Power to complete the Cost Assessments or enter into Replacement EPC Arrangements by December 31, 2017; (iv) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (v) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit 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, under certain circumstances Georgia Power may be required to make additional prepayments in connection with its receipt of payments under the Guarantee Settlement Agreement or from the EPC Contractor under the Vogtle 3 and 4 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.

On September 28, 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. 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 (B) under "Regulatory Matters – Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

Bank Credit Arrangements

Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional electric operating companies' pollution control revenue bonds. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of September 30, 2017 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 June 2017, Georgia Power remarketed $318 million of variable rate pollution control bonds in index rate modes, reducing the liquidity support utilized under Georgia Power's bank credit arrangement. In addition, at September 30, 2017, the traditional electric operating companies had approximately $699 million (comprised of approximately $509 million at Georgia Power, $140 million at Gulf Power, and $50 million at Mississippi Power) of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2017, $40 million of these pollution control revenue bonds of Georgia Power which were in an index rate mode were remarketed to the public in a long-term fixed rate mode. 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.

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(UNAUDITED)

The following table outlines the committed credit arrangements by company as of September 30, 2017:

	Expires														Executable Term Loans				Expires Within One Year
Company	2017		2018		2019		2020		2022		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)
Southern Company(a)	$	—	$	—	$	—	$	—	$	2,000	$	2,000	$	2,000	$	—	$	—	$	—	$	—
Alabama Power	—		35		—		500		800		1,335		1,335		—		—		—		35
Georgia Power	—		—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	30		195		25		30		—		280		280		45		—		—		40
Mississippi Power	100		—		—		—		—		100		100		—		—		—		100
Southern Power Company(b)	—		—		—		—		750		750		728		—		—		—		—
Southern Company Gas(c)	—		—		—		—		1,900		1,900		1,861		—		—		—		—
Other	—		30		—		—		—		30		30		20		—		20		10
Southern Company Consolidated	$	130	$	260	$	25	$	530	$	7,200	$	8,145	$	8,066	$	65	$	—	$	20	$	185

(a) Represents the Southern Company parent entity.

(b) Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $111 million has been used for letters of credit and $9 million remains unused at September 30, 2017.

(c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.2 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.

As reflected in the table above, in May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018. Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022. Pursuant to the new multi-year credit arrangement, the allocations may be adjusted. In September 2017, Alabama Power amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020.

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.

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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 2017:

Company	Senior Note Issuances		Senior Note Maturities and Redemptions		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions and Maturities(a)
	(in millions)
Southern Company(b)	$	300	$	400	$	—	$	500		$	400
Alabama Power	550		200		36		—			—
Georgia Power	1,350		450		65		370			13
Gulf Power	300		85		—		6			—
Mississippi Power	—		—		—		40			893
Southern Power	—		—		—		43			4
Southern Company Gas(c)	450		—		—		200			22
Other	—		—		—		—			12
Elimination(d)	—		—		—		(40		)	(599		)
Southern Company Consolidated	$	2,950	$	1,135	$	101	$	1,119		$	745

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

(b) Represents the Southern Company parent entity.

(c) The senior notes were issued by Southern Company Gas Capital and guaranteed by the Southern Company Gas parent entity. Other long-term debt issued represents first mortgage bonds issued by Nicor Gas.

(d) Includes intercompany loans from Southern Company to Mississippi Power and reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements.

Southern Company

In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057 and $300 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due September 30, 2020, which bear interest at a floating rate based on three-month LIBOR. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.

Also in June 2017, Southern Company entered into two$100 million aggregate principal amount floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.

In August 2017, Southern Company borrowed $250 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds were used for working capital and other general corporate purposes.

Alabama Power

In March 2017, Alabama Power issued $550 million aggregate principal amount of Series 2017A 2.45% Senior Notes due March 30, 2022. The proceeds were used to repay Alabama Power's short-term indebtedness and for general corporate purposes, including Alabama Power's continuous construction program.

In September 2017, Alabama Power issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used in

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(UNAUDITED)

October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of Alabama Power's 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of Alabama Power's 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of Alabama Power's 5.83% Class A Preferred Stock and for other general corporate purposes, including Alabama Power's continuous construction program.

Georgia Power

In March 2017, Georgia Power issued $450 million aggregate principal amount of Series 2017A 2.00% Senior Notes due March 30, 2020 and $400 million aggregate principal amount of Series 2017B 3.25% Senior Notes due March 30, 2027. The proceeds were used to repay a portion of Georgia Power's short-term indebtedness and for general corporate purposes, including Georgia Power's continuous construction program.

In April 2017, Georgia Power purchased and held $27 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995. Subsequent to September 30, 2017, Georgia Power remarketed these bonds to the public.

In June 2017, Georgia Power entered into three floating rate bank loans in aggregate principal amounts of $50 million, $150 million, and $100 million, with maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, which bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds from these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes, including Georgia Power's continuous construction program.

In August 2017, Georgia Power repaid $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. Also in August 2017, Georgia Power amended its $100 million floating rate bank loan to extend the maturity date from June 28, 2018 to October 26, 2018.

Also in August 2017, Georgia Power issued $500 million aggregate principal amount of Series 2017C 2.00% Senior Notes due September 8, 2020. The proceeds were used to repay Georgia Power's $50 million floating rate bank loan due December 1, 2017 and outstanding commercial paper borrowings and for general corporate purposes.

Also in August 2017, Georgia Power purchased and held $38 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1997. Subsequent to September 30, 2017, Georgia Power remarketed these bonds to the public.

In September 2017, Georgia Power issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used in October 2017 to redeem all 1.8 million shares ($45 million aggregate liquidation amount) of Georgia Power's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of Georgia Power's 6.50% Series 2007A Preference Stock.

Gulf Power

In March 2017, Gulf Power extended the maturity of a $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017.

In May 2017, Gulf Power issued $300 million aggregate principal amount of Series 2017A 3.30% Senior Notes due May 30, 2027. The proceeds, together with other funds, were used to repay at maturity $85 million aggregate principal amount of Series 2007A 5.90% Senior Notes due June 15, 2017; to repay outstanding commercial paper borrowings; to repay a $100 million short-term floating rate bank loan, as discussed above; and to redeem, in June 2017, 550,000 shares ($55 million aggregate liquidation amount) of Gulf Power's 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Gulf Power's Series 2007A 6.45% Preference Stock,

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

and 500,000 shares ($50 million aggregate liquidation amount) of Gulf Power's Series 2013A 5.60% Preference Stock.

Mississippi Power

In March 2017, Mississippi Power issued a $9 million short-term bank note bearing interest at 5% per annum, which was repaid in April 2017.

In February 2017, Mississippi Power amended $551 million in promissory notes to Southern Company extending the maturity dates of the notes from December 1, 2017 to July 31, 2018. In the second quarter 2017, Mississippi Power borrowed an additional $40 million under a promissory note issued to Southern Company.

In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay a $10 million short-term bank loan.

In August 2017, Mississippi Power repaid a $12.5 million short-term bank note.

In September 2017, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. Mississippi Power borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures. See Note (G) under "Section 174 Research and Experimental Deduction" for additional information.

Southern Power

In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate bank loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes.

Southern Company Gas

In May 2017, Southern Company Gas Capital issued $450 million aggregate principal amount of Series 2017A 4.40% Senior Notes due May 30, 2047. The proceeds were used to repay Southern Company Gas' short-term indebtedness and for general corporate purposes.

In July 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage Bonds 3.62% Series due August 10, 2037. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. The remaining $200 million is expected to be issued in November 2017.

(F) RETIREMENT BENEFITS

Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at Southern Company Gas, as discussed below, and PowerSecure. The Southern Company qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No mandatory contributions to the Southern Company qualified pension plan are anticipated for the year ending December 31, 2017. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric

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(UNAUDITED)

operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.

In addition, Southern Company Gas has a qualified defined benefit, trusteed, pension plan covering certain eligible employees, which was closed in 2012 to new employees. This qualified pension plan is funded in accordance with requirements of ERISA. No mandatory contributions to the Southern Company Gas qualified pension plan are anticipated for the year ending December 31, 2017. Southern Company Gas also provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company Gas provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. Southern Company Gas also has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.

See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Company Gas in Item 8 of the Form 10-K for additional information.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Components of the net periodic benefit costs for the three and nine months ended September 30, 2017 and 2016 are presented in the following tables.

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended September 30, 2017
Service cost	$	73		$	15		$	19		$	3		$	4
Interest cost	114			25			34			5			5
Expected return on plan assets	(224		)	(49		)	(71		)	(10		)	(9		)
Amortization:
Prior service costs	3			1			—			—			—
Net (gain)/loss	41			10			15			2			1
Net periodic pension cost (income)	$	7		$	2		$	(3	)	$	—		$	1
Nine Months Ended September 30, 2017
Service cost	$	220		$	47		$	56		$	10		$	11
Interest cost	341			73			103			15			15
Expected return on plan assets	(673		)	(147		)	(212		)	(29		)	(29		)
Amortization:
Prior service costs	9			2			2			—			1
Net (gain)/loss	122			31			43			5			5
Net periodic pension cost (income)	$	19		$	6		$	(8	)	$	1		$	3
Three Months Ended September 30, 2016
Service cost	$	68		$	14		$	17		$	3		$	3
Interest cost	110			23			34			5			4
Expected return on plan assets	(203		)	(46		)	(64		)	(9		)	(9		)
Amortization:
Prior service costs	3			1			1			—			1
Net (gain)/loss	45			10			14			2			2
Net periodic pension cost	$	23		$	2		$	2		$	1		$	1
Nine Months Ended September 30, 2016
Service cost	$	192		$	43		$	52		$	9		$	9
Interest cost	311			71			102			14			14
Expected return on plan assets	(577		)	(138		)	(193		)	(26		)	(26		)
Amortization:
Prior service costs	10			2			4			1			1
Net (gain)/loss	120			30			41			5			5
Net periodic pension cost	$	56		$	8		$	6		$	3		$	3

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Pension Plans	Southern Company Gas
	(in millions)
Successor – Three Months Ended September 30, 2017
Service cost	$	6
Interest cost	10
Expected return on plan assets	(18		)
Amortization of net (gain)/loss	5
Net periodic pension cost	$	3
Successor – Nine Months Ended September 30, 2017
Service cost	$	17
Interest cost	30
Expected return on plan assets	(53		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	15
Net periodic pension cost	$	8
Successor – July 1, 2016 through September 30, 2016
Service cost	$	7
Interest cost	10
Expected return on plan assets	(17		)
Amortization of regulatory asset	6
Net periodic pension cost	$	6
Predecessor – January 1, 2016 through June 30, 2016
Service cost	$	13
Interest cost	21
Expected return on plan assets	(33		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	13
Net periodic pension cost	$	13

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(UNAUDITED)

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended September 30, 2017
Service cost	$	6		$	1		$	2		$	—		$	—
Interest cost	19			4			6			1			1
Expected return on plan assets	(16		)	(5		)	(6		)	—			—
Amortization:
Prior service costs	2			1			—			—			—
Net (gain)/loss	3			—			3			—			—
Net periodic postretirement benefit cost	$	14		$	1		$	5		$	1		$	1
Nine Months Ended September 30, 2017
Service cost	$	18		$	4		$	5		$	1		$	1
Interest cost	59			13			21			2			3
Expected return on plan assets	(49		)	(19		)	(18		)	(1		)	(1		)
Amortization:
Prior service costs	5			3			1			—			—
Net (gain)/loss	10			1			6			—			—
Net periodic postretirement benefit cost	$	43		$	2		$	15		$	2		$	3
Three Months Ended September 30, 2016
Service cost	$	6		$	1		$	2		$	—		$	—
Interest cost	20			5			7			1			—
Expected return on plan assets	(16		)	(6		)	(6		)	—			—
Amortization:
Prior service costs	1			1			—			—			—
Net (gain)/loss	5			—			3			—			1
Net periodic postretirement benefit cost	$	16		$	1		$	6		$	1		$	1
Nine Months Ended September 30, 2016
Service cost	$	17		$	4		$	5		$	1		$	1
Interest cost	55			14			22			2			2
Expected return on plan assets	(44		)	(19		)	(17		)	(1		)	(1		)
Amortization:
Prior service costs	4			3			1			—			—
Net (gain)/loss	12			1			7			—			1
Net periodic postretirement benefit cost	$	44		$	3		$	18		$	2		$	3

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(UNAUDITED)

Postretirement Benefits	Southern Company Gas
	(in millions)
Successor – Three Months Ended September 30, 2017
Service cost	$	1
Interest cost	3
Expected return on plan assets	(2		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	1
Net periodic postretirement benefit cost	$	2
Successor – Nine Months Ended September 30, 2017
Service cost	$	2
Interest cost	8
Expected return on plan assets	(5		)
Amortization:
Prior service costs	(2		)
Net (gain)/loss	3
Net periodic postretirement benefit cost	$	6
Successor – July 1, 2016 through September 30, 2016
Service cost	$	1
Interest cost	2
Expected return on plan assets	(2		)
Amortization of regulatory asset	1
Net periodic postretirement benefit cost	$	2
Predecessor – January 1, 2016 through June 30, 2016
Service cost	$	1
Interest cost	5
Expected return on plan assets	(3		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	2
Net periodic postretirement benefit cost	$	4

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(UNAUDITED)

(G) INCOME TAXES

See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for additional tax information.

Current and Deferred Income Taxes

Tax Credit Carryforwards

Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $1.9 billion as of September 30, 2017 compared to $1.8 billion as of December 31, 2016.

The federal ITC carryforwards begin expiring in 2032 but are expected to be fully utilized by 2022. The PTC carryforwards begin expiring in 2036 but are expected to be utilized by 2022. The expected utilization of tax credit carryforwards could be further delayed by numerous factors. These factors include the acquisition of additional renewable projects, increased generation at existing wind facilities, carrying back the federal net operating loss, and potential tax reform legislation, as well as additional deductions in the event of an asset abandonment. The ultimate outcome of these matters cannot be determined at this time.

Valuation Allowances

At September 30, 2017, valuation allowances were as follows:

	Mississippi Power		Southern Company Gas		Southern Company
	(in millions)
Federal	$	—	$	18	$	18
State (net of federal benefit)	46		1		64
Balance at September 30, 2017	$	46	$	19	$	82

Southern Company had valuation allowances, net of the federal benefit, of $82 million at September 30, 2017 compared to $21 million at December 31, 2016. The increase was primarily due to Mississippi Power's projected inability to utilize the State of Mississippi net operating loss.

Effective Tax Rate

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 42.6% for the nine months ended September 30, 2017 compared to 28.3% for the corresponding period in 2016. The effective tax rate increase was primarily due to the estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion. Other factors include a decrease in tax benefits from solar ITCs and an increase in state valuation allowances, partially offset by an increase in tax benefits from wind PTCs.

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.

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(UNAUDITED)

Mississippi Power

Mississippi Power's effective tax (benefit) rate was (30.3)% for the nine months ended September 30, 2017 compared to (282.8)% for the corresponding period in 2016. The effective tax rate increase was primarily due to the estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion and the related state valuation allowances.

Southern Power

Southern Power's effective tax (benefit) rate was (66.5)% for the nine months ended September 30, 2017 compared to (88.9)% for the corresponding period in 2016. The effective tax rate increase was primarily due to a decrease in tax benefits from solar ITCs, partially offset by additional wind PTCs and state apportionment rate changes.

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.

During the third quarter 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate solar facilities, including certain subsidiaries owned in partnership with various third parties. Southern Power's ownership interests in the various solar entities and facilities will not be affected by the reorganization. The reorganization is expected to result in estimated tax benefits totaling approximately $40 million that will be recorded in the fourth quarter 2017 related to certain changes in state apportionment rates and net operating loss carryforward utilization. The ultimate outcome of this matter cannot be determined at this time.

Southern Company Gas

Southern Company Gas' effective tax rate was 43.4% for the successor nine months ended September 30, 2017 compared to 60.3% for the successor period of July 1, 2016 through September 30, 2016 and 37.6% for the predecessor period of January 1, 2016 through June 30, 2016. The effective tax rate for the successor year-to-date 2017 was impacted by State of Illinois tax legislation enacted during July 2017, the allocation of new tax apportionment factors in several states for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings, and higher pre-tax earnings. The effective tax rates for the periods in 2016 were impacted by the non-deductibility of certain Merger-related expenses. The effective tax rate for the successor period of July 1, 2016 through September 30, 2016 was also impacted by nondeductible expenses associated with certain compensation costs.

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.

Changes during the nine months ended September 30, 2017 for unrecognized tax benefits were as follows:

	Mississippi Power			Southern Power			Southern Company
	(in millions)
Unrecognized tax benefits as of December 31, 2016	$	465		$	17		$	484
Tax positions from current periods	2			—			9
Tax positions from prior periods	(175		)	(17		)	(186		)
Reductions due to settlements	(290		)	—			(290		)
Balance as of September 30, 2017	$	2		$	—		$	17

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

The tax positions from current and prior periods primarily relate to state tax benefits, deductions for R&E expenditures, and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper IGCC, as well as federal income tax benefits from deferred ITCs. See "Section 174 Research and Experimental Deduction" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.

The impact on the effective tax rate, if recognized, is as follows:

	As of September 30, 2017				As of December 31, 2016
	Mississippi Power		Southern Company		Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	2	$	17	$	20
Tax positions not impacting the effective tax rate	—		—		464
Balance of unrecognized tax benefits	$	2	$	17	$	484

The tax positions impacting the effective tax rate primarily relate to state tax benefits and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for additional information.

Accrued interest for all tax positions was immaterial for all periods presented.

All of the registrants classify interest on tax uncertainties as interest expense. None of the registrants accrued any penalties on uncertain tax positions.

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 federal income tax returns through 2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. However, the pre-Merger Southern Company Gas 2014, 2015, and June 30, 2016 federal tax returns are currently under audit. 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 2011.

Section 174 Research and Experimental Deduction

Southern Company has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the JCT approval, Southern Company recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount not allowed under IRC Section 174 would be claimed as a deduction under IRC Section 165 in the year an abandonment is determined. The ultimate outcome of this matter cannot be determined at this time.

(H) 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

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(UNAUDITED)

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 (C) 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.

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 extended the moratorium on Gulf Power's fuel-hedging program until January 1, 2021 in connection with the 2017 Rate Case Settlement Agreement. 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 the statements of income.

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 as the hedged transactions are reflected in earnings.

• 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

256

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(UNAUDITED)

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, 2017, 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(*)	463	2021	2024
Alabama Power	66	2020	—
Georgia Power	159	2021	—
Gulf Power	28	2020	—
Mississippi Power	44	2021	—
Southern Power	13	2018	—
Southern Company Gas(*)	153	2020	2024

(*) 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 3.3 billion mmBtu and short natural gas positions of 3.1 billion mmBtu as of September 30, 2017, 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 34 million mmBtu for Southern Company, 11 million mmbtu for Georgia Power and Southern Power, 5 million mmbtu for Alabama Power, 3 million mmBtu for Gulf Power, and 4 million mmBtu for Mississippi 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, 2018 are $5 million for Southern Power and immaterial for all other 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 effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. 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, providing an offset, with any difference representing ineffectiveness. 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.

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(UNAUDITED)

At September 30, 2017, 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, 2017
	(in millions)					(in millions)
Cash Flow Hedges of Existing Debt
Mississippi Power	$	900	1-month LIBOR	0.79%	March 2018	$	2
Fair Value Hedges of Existing Debt
Southern Company(*)	300		2.75%	3-month LIBOR + 0.92%	June 2020	—
Southern Company(*)	1,500		2.35%	1-month LIBOR + 0.87%	July 2021	(19		)
Georgia Power	250		5.40%	3-month LIBOR + 4.02%	June 2018	—
Georgia Power	500		1.95%	3-month LIBOR + 0.76%	December 2018	(2		)
Georgia Power	200		4.25%	3-month LIBOR + 2.46%	December 2019	—
Southern Company Consolidated	$	3,650				$	(19	)

(*) 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, 2018 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 effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time that the hedged transactions affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

258

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At September 30, 2017, 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, 2017
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	42
Southern Power	564		3.78%	500		1.85%	June 2026	38
Total	$	1,241		€	1,100			$	80

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, 2018 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.

259

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, 2017						As of December 31, 2016
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	$	21		$	25		$	73		$	27
Other deferred charges and assets/Other deferred credits and liabilities	13			23			25			33
Total derivatives designated as hedging instruments for regulatory purposes	$	34		$	48		$	98		$	60
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	8		$	6		$	23		$	7
Interest rate derivatives:
Other current assets/Other current liabilities	5			1			12			1
Other deferred charges and assets/Other deferred credits and liabilities	—			23			1			28
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			25
Other deferred charges and assets/Other deferred credits and liabilities	103			—			—			33
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	116		$	53		$	36		$	94
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	271		$	254		$	489		$	483
Other deferred charges and assets/Other deferred credits and liabilities	115			103			66			81
Interest rate derivatives:
Other current assets/Other current liabilities	—			—			1			—
Total derivatives not designated as hedging instruments	$	386		$	357		$	556		$	564
Gross amounts recognized	$	536		$	458		$	690		$	718
Gross amounts offset(*)	$	(275	)	$	(351	)	$	(462	)	$	(524	)
Net amounts recognized in the Balance Sheets	$	261		$	107		$	228		$	194

260

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	As of September 30, 2017						As of December 31, 2016
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	$	6		$	4		$	13		$	5
Other deferred charges and assets/Other deferred credits and liabilities	3			3			7			4
Total derivatives designated as hedging instruments for regulatory purposes	$	9		$	7		$	20		$	9
Gross amounts recognized	$	9		$	7		$	20		$	9
Gross amounts offset	$	(5	)	$	(5	)	$	(8	)	$	(8	)
Net amounts recognized in the Balance Sheets	$	4		$	2		$	12		$	1
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	10		$	3		$	30		$	1
Other deferred charges and assets/Other deferred credits and liabilities	8			8			14			7
Total derivatives designated as hedging instruments for regulatory purposes	$	18		$	11		$	44		$	8
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	1		$	1		$	2		$	—
Other deferred charges and assets/Other deferred credits and liabilities	—			2			—			3
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	1		$	3		$	2		$	3
Gross amounts recognized	$	19		$	14		$	46		$	11
Gross amounts offset	$	(10	)	$	(10	)	$	(8	)	$	(8	)
Net amounts recognized in the Balance Sheets	$	9		$	4		$	38		$	3
Gulf Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	—		$	13		$	4		$	12
Other deferred charges and assets/Other deferred credits and liabilities	—			9			1			17
Total derivatives designated as hedging instruments for regulatory purposes	$	—		$	22		$	5		$	29
Gross amounts recognized	$	—		$	22		$	5		$	29
Gross amounts offset	$	—		$	—		$	(4	)	$	(4	)
Net amounts recognized in the Balance Sheets	$	—		$	22		$	1		$	25

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	As of September 30, 2017						As of December 31, 2016
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	4		$	2		$	6
Other deferred charges and assets/Other deferred credits and liabilities	2			3			2			5
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	7		$	4		$	11
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	2		$	—		$	2		$	—
Other deferred charges and assets/Other deferred credits and liabilities	—			—			1			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	2		$	—		$	3		$	—
Gross amounts recognized	$	5		$	7		$	7		$	11
Gross amounts offset	$	(3	)	$	(3	)	$	(3	)	$	(3	)
Net amounts recognized in the Balance Sheets	$	2		$	4		$	4		$	8
Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	8		$	4		$	18		$	4
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			25
Other deferred charges and assets/Other deferred credits and liabilities	103			—			—			33
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	111		$	27		$	18		$	62
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	—		$	3		$	1
Interest rate derivatives:
Other current assets/Other current liabilities	—			—			1			—
Total derivatives not designated as hedging instruments	$	1		$	—		$	4		$	1
Gross amounts recognized	$	112		$	27		$	22		$	63
Gross amounts offset	$	(1	)	$	(1	)	$	(5	)	$	(5	)
Net amounts recognized in the Balance Sheets	$	111		$	26		$	17		$	58

262

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	As of September 30, 2017						As of December 31, 2016
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	$	4		$	1		$	24		$	3
Other deferred charges and assets/Other deferred credits and liabilities	—			—			1			—
Total derivatives designated as hedging instruments for regulatory purposes	$	4		$	1		$	25		$	3
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	$	—		$	2		$	4		$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	270		$	254		$	486		$	482
Other deferred charges and assets/Other deferred credits and liabilities	115			103			66			81
Total derivatives not designated as hedging instruments	$	385		$	357		$	552		$	563
Gross amounts of recognized	$	389		$	360		$	581		$	569
Gross amounts offset(*)	$	(251	)	$	(327	)	$	(435	)	$	(497	)
Net amounts recognized in the Balance Sheets	$	138		$	33		$	146		$	72

(*) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $76 million and $62 million as of September 30, 2017 and December 31, 2016, respectively.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At September 30, 2017 and December 31, 2016, 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, 2017
Derivative Category and Balance Sheet Location	Southern Company(b)			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas(c)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(18	)	$	(1	)	$	—		$	(13	)	$	(3	)	$	(1	)
Other regulatory assets, deferred	(12		)	(1		)	(1		)	(9		)	(1		)	—
Other regulatory liabilities, current(a)	14			3			7			—			—			4
Other regulatory liabilities, deferred(b)	2			1			1			—			—			—
Total energy-related derivative gains (losses)	$	(14	)	$	2		$	7		$	(22	)	$	(4	)	$	3

(a) Georgia Power includes other regulatory liabilities, current in other current liabilities.

(b) Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.

(c) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $1 million at September 30, 2017.

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2016
Derivative Category and Balance Sheet Location	Southern Company(c)			Alabama Power			Georgia Power		Gulf Power			Mississippi Power			Southern Company Gas(c)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(16	)	$	(1	)	$	—	$	(9	)	$	(5	)	$	(1	)
Other regulatory assets, deferred	(19		)	—			—		(16		)	(3		)	—
Other regulatory liabilities, current(a)	56			8			29		1			1			17
Other regulatory liabilities, deferred(b)	12			4			7		—			—			1
Total energy-related derivative gains (losses)	$	33		$	11		$	36	$	(24	)	$	(7	)	$	17

(a) Georgia Power includes other regulatory liabilities, current in other current liabilities.

(b) Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.

(c) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $8 million at December 31, 2016.

264

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the three months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments were as follows:

Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)						Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
							Statements of Income Location	Amount
	2017			2016				2017			2016
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	(6	)	$	—		Depreciation and amortization	$	(6	)	$	1
Interest rate derivatives	(1		)	(6		)	Interest expense, net of amounts capitalized	(5		)	(6		)
Foreign currency derivatives	46			37			Interest expense, net of amounts capitalized	(5		)	(6		)
							Other income (expense), net(*)	43			7
Total	$	39		$	31			$	27		$	(4	)
Alabama Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(2	)	$	(2	)
Georgia Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Mississippi Power
Interest rate derivatives	$	(1	)	$	(1	)	Interest expense, net of amounts capitalized	$	—		$	—
Southern Power
Energy-related derivatives	$	(6	)	$	—		Depreciation and amortization	$	(6	)	$	1
Foreign currency derivatives	46			37			Interest expense, net of amounts capitalized	(5		)	(6		)
							Other income (expense), net(*)	43			7
Total	$	40		$	37			$	32		$	2
Southern Company Gas
Interest rate derivatives	$	—		$	(5	)	Interest expense, net of amounts capitalized	$	—		$	—

(*) 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.

265

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the nine months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments were as follows:

Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)						Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
							Statements of Income Location	Amount
	2017			2016				2017			2016
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	(26	)	$	(1	)	Depreciation and amortization	$	(12	)	$	1
Interest rate derivatives	(2		)	(189		)	Interest expense, net of amounts capitalized	(15		)	(13		)
Foreign currency derivatives	114			(1		)	Interest expense, net of amounts capitalized	(17		)	(7		)
							Other income (expense), net(*)	139			(13		)
Total	$	86		$	(191	)		$	95		$	(32	)
Alabama Power
Interest rate derivatives	$	—		$	(3	)	Interest expense, net of amounts capitalized	$	(5	)	$	(5	)
Georgia Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(3	)	$	(3	)
Gulf Power
Energy-related derivatives	$	(1	)	$	—		Depreciation and amortization	$	—		$	—
Interest rate derivatives	(1		)	(7		)	Interest expense, net of amounts capitalized	—			—
Total	$	(2	)	$	(7	)		$	—		$	—
Mississippi Power
Interest rate derivatives	$	—		$	(1	)	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Southern Power
Energy-related derivatives	$	(21	)	$	(1	)	Depreciation and amortization	$	(12	)	$	1
Interest rate derivatives	—			—			Interest expense, net of amounts capitalized	—			(1		)
Foreign currency derivatives	114			(1		)	Interest expense, net of amounts capitalized	(17		)	(7		)
							Other income (expense), net(*)	139			(13		)
Total	$	93		$	(2	)		$	110		$	(20	)

(*) 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 Southern Company Gas, the pre-tax effect of energy related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings for the successor nine months ended September 30, 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016 were as follows:

	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)				Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Derivatives in Cash Flow Hedging Relationships	Nine Months Ended September 30, 2017			Statements of Income Location	Nine Months Ended September 30, 2017
	(in millions)				(in millions)
Energy-related derivatives	$	(4	)	Cost of natural gas	$	—

266

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)							Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
	Successor			Predecessor				Successor		Predecessor
Derivatives in Cash Flow Hedging Relationships	July 1, 2016 through September 30, 2016			January 1, 2016 through June 30, 2016			Statements of Income Location	July 1, 2016 through September 30, 2016		January 1, 2016 through June 30, 2016
	(in millions)			(in millions)				(in millions)		(in millions)
Energy-related derivatives	$	—		$	—		Cost of natural gas	$	—	$	(1	)
Interest rate derivatives	(5		)	(64		)	Interest expense, net of amounts capitalized	—		—
Total	$	(5	)	$	(64	)		$	—	$	(1	)

For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments were immaterial for the other registrants.

For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments on the statements of income 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	2017			2016		2017			2016
		(in millions)					(in millions)
Southern Company
Energy Related derivatives:	Natural gas revenues(*)	$	(17	)	$	—	$	48		$	—
	Cost of natural gas	2			6		(2		)	6
Total derivatives in non-designated hedging relationships		$	(15	)	$	6	$	46		$	6

(*) Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $15 million for the nine months ended September 30, 2017 and immaterial amounts for all other periods presented.

		Gain (Loss)
		Successor			Successor		Successor			Successor		Predecessor
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	Three Months Ended September 30, 2017			Three Months Ended September 30, 2016		Nine Months Ended September 30, 2017			July 1, 2016 through September 30, 2016		January 1, 2016 through June 30, 2016
		(in millions)			(in millions)		(in millions)			(in millions)
Southern Company Gas
Energy Related derivatives:	Natural gas revenues(*)	$	(17	)	$	—	$	48		$	—	$	(1	)
	Cost of natural gas	2			6		(2		)	6		(62		)
Total derivatives in non-designated hedging relationships		$	(15	)	$	6	$	46		$	6	$	(63	)

(*) Excludes gains recorded in cost of natural gas associated with weather derivatives of $15 million for the successor nine months ended September 30, 2017 and immaterial amounts for all other periods presented.

267

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the three and nine months ended September 30, 2017 and 2016, 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.

For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:

Derivatives in Fair Value Hedging Relationships
		Gain (Loss)
		Three Months Ended September 30,						Nine Months Ended September 30,
Derivative Category	Statements of Income Location	2017			2016			2017			2016
		(in millions)						(in millions)
Southern Company
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	(5	)	$	(9	)	$	(6	)	$	15
Georgia Power
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	—		$	(5	)	$	(1	)	$	10

For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt.

There was no material ineffectiveness recorded in earnings for any registrant for any period presented.

Contingent Features

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At September 30, 2017, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

At September 30, 2017, the fair value of derivative liabilities with contingent features was immaterial for all registrants. 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, 2017, 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, 2017, cash collateral held on deposit in broker margin accounts was $76 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

268

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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.

269

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(I) ACQUISITIONS AND DISPOSITIONS

Southern Company

Merger with Southern Company Gas

Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. On July 1, 2016, Southern Company completed the Merger for a total purchase price of approximately $8.0 billion and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company.

The Merger was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation:

Southern Company Gas Purchase Price
	(in millions)
Current assets	$	1,557
Property, plant, and equipment	10,108
Goodwill	5,967
Intangible assets	400
Regulatory assets	1,118
Other assets	229
Current liabilities	(2,201		)
Other liabilities	(4,742		)
Long-term debt	(4,261		)
Noncontrolling interest	(174		)
Total purchase price	$	8,001

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $6.0 billion is recognized as goodwill, which is primarily attributable to positioning the Southern Company system to provide natural gas infrastructure to meet customers' growing energy needs and to compete for growth across the energy value chain. Southern Company anticipates that much of the value assigned to goodwill will not be deductible for tax purposes.

The valuation of identifiable intangible assets included customer relationships, trade names, and storage and transportation contracts with estimated lives of one to 28 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).

The results of operations for Southern Company Gas have been included in Southern Company's consolidated financial statements from the date of acquisition and consist of operating revenues of $565 million and $2.8 billion and net income of $15 million and $303 million for the three and nine months ended September 30, 2017, respectively, and operating revenues and net income of $543 million and $4 million, respectively, for the three months ended September 30, 2016.

The following summarized unaudited pro forma consolidated statement of earnings information assumes that the acquisition of Southern Company Gas was completed on January 1, 2015. The summarized unaudited pro forma consolidated statement of earnings information includes adjustments for (i) intercompany sales, (ii) amortization of intangible assets, (iii) adjustments to interest expense to reflect current interest rates on Southern Company Gas debt and additional interest expense associated with borrowings by Southern Company to fund the Merger, and (iv) the elimination of nonrecurring expenses associated with the Merger.

270

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	For the Nine Months Ended September 30,
	2016
Operating revenues (in millions)	$	16,609
Net income attributable to Southern Company (in millions)	$	2,394
Basic Earnings Per Share (EPS)	$	2.52
Diluted EPS	$	2.51

These unaudited pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2015 or the results that would be attained in the future.

Acquisition of PowerSecure

On May 9, 2016, Southern Company acquired all of the outstanding stock of PowerSecure, a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, for $18.75 per common share in cash, resulting in an aggregate purchase price of $429 million. As a result, PowerSecure became a wholly-owned subsidiary of Southern Company.

The acquisition of PowerSecure was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation:

PowerSecure Purchase Price
	(in millions)
Current assets	$	172
Property, plant, and equipment	46
Intangible assets	106
Goodwill	284
Other assets	4
Current liabilities	(121		)
Long-term debt, including current portion	(48		)
Deferred credits and other liabilities	(14		)
Total purchase price	$	429

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $284 million was recognized as goodwill, which is primarily attributable to expected business expansion opportunities for PowerSecure. Southern Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes.

The valuation of identifiable intangible assets included customer relationships, trade names, patents, backlog, and software with estimated lives of one to 26 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).

The results of operations for PowerSecure have been included in Southern Company's consolidated financial statements from the date of acquisition and are immaterial to the consolidated financial results of Southern Company. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were immaterial to Southern Company's consolidated financial results for all periods presented.

271

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Southern Power

See Note 2 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, 2017

During the nine months ended September 30, 2017, in accordance with Southern Power's overall growth strategy, one of Southern Power's wholly-owned subsidiaries acquired the project discussed below. 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
Bethel	Wind	Invenergy, January 6, 2017	276	Castro County, TX	100	%	January 2017	12 years

The aggregate amounts of revenue and net income recognized by Southern Power related to the Bethel facility included in Southern Power's condensed consolidated statements of income for year-to-date 2017 were immaterial. The Bethel facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service; therefore, supplemental pro forma information as though the acquisition occurred as of the beginning of 2017 and for the comparable 2016 period is not meaningful and has been omitted.

In connection with Southern Power's 2016 acquisitions, allocations of the purchase price to individual assets were finalized during the nine months ended September 30, 2017 with no changes to amounts originally reported for Boulder 1, Grant Plains, Grant Wind, Henrietta, Mankato, Passadumkeag, Salt Fork, Tyler Bluff, and Wake Wind.

Subsequent to September 30, 2017, Southern Power purchased all of the redeemable noncontrolling interests, representing10%of the membership interests, in Southern Turner Renewable Energy, LLC and repaid$14 millionof notes payable to Turner Renewable Energy, LLC.

Construction Projects Completed and in Progress

During the nine months ended September 30, 2017, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through September 30, 2017, total costs of construction incurred for these projects were $494 million, of which $122 million remained in CWIP. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $360 million and $415 million for the Mankato and Cactus Flats facilities. The ultimate outcome of these matters cannot be determined at this time.

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Projects Completed During the Nine Months Ended September 30, 2017
East Pecos	Solar	120	Pecos County, TX	March 2017	15 years
Lamesa	Solar	102	Dawson County, TX	April 2017	15 years
Projects Under Construction as of September 30, 2017
Cactus Flats(*)	Wind	148	Concho County, TX	Third quarter 2018	12-15 years
Mankato	Natural Gas	345	Mankato, MN	Second quarter 2019	20 years

(*) On July 31, 2017, Southern Power acquired a 100% ownership interest in the Cactus Flats facility, which is in the early stages of construction, from RES America Developments, Inc.

272

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Development Projects

In December 2016, as part of Southern Power's renewable development strategy, one of Southern Power's wholly-owned subsidiaries entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects. Also in December 2016, Southern Power signed agreements and made payments to purchase wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. All of the wind turbine equipment was delivered by April 2017, which allows the projects to qualify for 100% PTCs for 10 years following their expected commercial operation dates between 2018 and 2020. The ultimate outcome of these matters cannot be determined at this time.

Southern Company Gas

On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements for the sale 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. The completion of each sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act; (ii) the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC; and (iii) other customary closing conditions. The sales are expected to be completed by the end of the third quarter 2018.

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

(J) JOINT OWNERSHIP AGREEMENTS

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.

273

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments as of September 30, 2017 and December 31, 2016 and related income from those investments for the successor three and nine month periods ended September 30, 2017, the successor three-month period ended September 30, 2016, and for the predecessor period January 1, 2016 through June 30, 2016 were as follows:

Balance Sheet Information	September 30, 2017		December 31, 2016
	(in millions)
SNG	$	1,385	$	1,394
Atlantic Coast Pipeline	61		33
PennEast Pipeline	49		22
Triton	43		44
Pivotal JAX LNG, LLC	40		16
Horizon Pipeline	30		30
Other	1		2
Total	$	1,609	$	1,541

	Successor		Successor		Successor		Predecessor
Income Statement Information	Three Months Ended September 30, 2017		Three Months Ended September 30, 2016		Nine Months Ended September 30, 2017		January 1, 2016 through June 30, 2016
	(in millions)		(in millions)		(in millions)		(in millions)
SNG	$	28	$	27	$	86	$	—
PennEast Pipeline	1		—		5		—
Atlantic Coast Pipeline	1		1		4		—
Triton	1		1		3		1
Horizon Pipeline	1		—		2		1
Total	$	32	$	29	$	100	$	2

Southern Natural Gas

In September 2016, Southern Company Gas, through a wholly-owned, indirect subsidiary, acquired a 50% equity interest in SNG, which is accounted for as an equity method investment. On March 31, 2017, Southern Company Gas made an additional $50 million contribution to maintain its 50% equity interest in SNG. See Note 11 to the financial statements of Southern Company Gas under "Investment in SNG" in Item 8 of the Form 10-K for additional information on this investment. Selected financial information of SNG for the three and nine months ended September 30, 2017 and for the period September 1, 2016 through September 30, 2016 is as follows:

Income Statement Information	Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017		September 1, 2016 through September 30, 2016
	(in millions)
Revenues	$	146	$	445	$	82
Operating income	$	71	$	218	$	60
Net income	$	57	$	172	$	55

274

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(K) 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 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 the seven natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations.

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 $105 million and $295 million for the three and nine months ended September 30, 2017, respectively, and $110 million and $313 million for the three and nine months ended September 30, 2016, 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.

275

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Financial data for business segments and products and services for the three and nine months ended September 30, 2017 and 2016 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, 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)(c)	—		276		—			276		303		(232		)	—			347
Total assets at September 30, 2017	$	73,056	$	14,648	$	(322	)	$	87,382	$	22,190	$	2,275		$	(1,532	)	$	110,315
Three Months Ended September 30, 2016:
Operating revenues	$	5,236	$	500	$	(117	)	$	5,619	$	543	$	139		$	(37	)	$	6,264
Segment net income (loss)(a)(b)	1,022		176		—			1,198		4		(62		)	(1		)	1,139
Nine Months Ended September 30, 2016:
Operating revenues	$	13,120	$	1,189	$	(330	)	$	13,979	$	543	$	311		$	(118	)	$	14,715
Segment net income (loss)(a)(b)	2,086		315		—			2,401		4		(146		)	(8		)	2,251
Total assets at December 31, 2016	$	72,141	$	15,169	$	(316	)	$	86,994	$	21,853	$	2,474		$	(1,624	)	$	109,697

(a) Attributable to Southern Company.

(b) Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $34 million ($21 million after tax) and $88 million ($54 million after tax) for the three months ended September 30, 2017 and 2016, respectively, and $3.2 billion ($2.2 billion after tax) and $222 million ($137 million after tax) for the nine months ended September 30, 2017 and 2016, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.

(c) Segment net income (loss) for the traditional electric operating companies also 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 (B) under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information.

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2017	$	4,615	$	718	$	190	$	5,523
Three Months Ended September 30, 2016	4,808		613		198		5,619
Nine Months Ended September 30, 2017	$	11,786	$	1,867	$	586	$	14,239
Nine Months Ended September 30, 2016	11,932		1,455		592		13,979

276

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	Southern Company Gas' Revenues
Period	Gas Distribution Operations		Gas Marketing Services		Other			Total
	(in millions)
Three Months Ended September 30, 2017	$	430	$	143	$	(8	)	$	565
Nine Months Ended September 30, 2017	$	2,119	$	597	$	125		$	2,841
Three and Nine Months Ended September 30, 2016	$	420	$	126	$	(3	)	$	543

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. Gas marketing services includes natural gas marketing to end-use customers primarily in Georgia and Illinois. Additionally, gas marketing services provides home equipment protection products and services. 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.

After the Merger, Southern Company Gas changed its segment performance measure to net income. In order to properly assess net income by segment, Southern Company Gas executed various intercompany note agreements to revise interest charges to its segments. Since such agreements did not exist in the predecessor period, Southern Company Gas is unable to provide the comparable net income.

Business segment financial data for the successor three months ended September 30, 2017 and 2016, the successor nine months ended September 30, 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016 was as follows:

	Gas Distribution Operations		Gas Marketing Services		Wholesale Gas Services(*)			Gas Midstream Operations		Total		All Other			Eliminations			Consolidated
	(in millions)
Successor – Three Months Ended September 30, 2017:
Operating revenues	$	472	$	143	$	(24	)	$	16	$	607	$	2		$	(44	)	$	565
Segment net income	52		1		(23		)	14		44		(29		)	—			15
Successor – Nine Months Ended September 30, 2017:
Operating revenues	$	2,255	$	597	$	95		$	53	$	3,000	$	7		$	(166	)	$	2,841
Segment net income	223		36		28			38		325		(22		)	—			303
Successor – Total assets at September 30, 2017	$	18,711	$	2,089	$	893		$	2,359	$	24,052	$	11,400		$	(13,262	)	$	22,190

277

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	Gas Distribution Operations		Gas Marketing Services			Wholesale Gas Services(*)			Gas Midstream Operations			Total		All Other			Eliminations			Consolidated
	(in millions)
Successor – Three Months Ended September 30, 2016:
Operating revenues	$	455	$	126		$	(8	)	$	13		$	586	$	2		$	(45	)	$	543
Segment net income (loss)	27		(4		)	(11		)	14			26		(22		)	—			4
Predecessor – January 1, 2016 through June 30, 2016:
Operating revenues	$	1,575	$	435		$	(32	)	$	25		$	2,003	$	4		$	(102	)	$	1,905
Segment EBIT	353		109			(68		)	(6		)	388		(60		)	—			328
Successor – Total assets at December 31, 2016	$	19,453	$	2,084		$	1,127		$	2,211		$	24,875	$	11,145		$	(14,167	)	$	21,853

(*) 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)
Successor – Three Months Ended September 30, 2017	$	1,411	$	103	$	1,514	$	1,538	$	(24	)
Successor – Nine Months Ended September 30, 2017	4,781		362		5,143		5,048		95
Successor – Three Months Ended September 30, 2016	1,688		77		1,765		1,773		(8		)
Predecessor – January 1, 2016 through June 30, 2016	$	2,500	$	143	$	2,643	$	2,675	$	(32	)

278

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.

The bankruptcy filing of the EPC Contractor is expected to have a material impact on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 and could have a material impact on the financial statements of Southern Company and Georgia Power, and any inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4, and therefore on the financial statements of Southern Company and Georgia Power.

See "Construction Risk" in Item 1A – Risk Factors of Southern Company and Georgia Power in the Form 10-K for a discussion of risks relating to major construction projects, including Plant Vogtle Units 3 and 4 and see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information.

On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the EPC Contractor (Interim Assessment Agreement), which the bankruptcy court approved on March 30, 2017.

The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided. The Interim Assessment Agreement, as amended, expired on July 27, 2017.

Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through September 30, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which $340 million had been paid or accrued as of September 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $176 million.

The Vogtle 3 and 4 Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed.

Under the terms of the Vogtle 3 and 4 Agreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the Vogtle 3 and 4 Agreement was 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest).

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On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, which will reduce CWIP, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million. Georgia Power is considering potential options with respect to its right to future payments under the Guarantee Settlement Agreement and its claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to DOE consents and related approvals under the Loan Guarantee Agreement and related agreements.

On August 10, 2017, Toshiba released its financial results for the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $4.5 billion as of June 30, 2017. Toshiba previously announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's and Georgia Power's financial statements.

Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into a services agreement (Services Agreement), which was 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. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement (Bechtel Agreement) with Bechtel Power Corporation (Bechtel), whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4. Facility design and engineering remains the responsibility of the EPC Contractor under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a 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

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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 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, 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 connection with the recommendation to continue with construction of Plant Vogtle Units 3 and 4 (described below), the Vogtle Owners agreed on a term sheet to amend the existing joint ownership agreements to provide for additional Vogtle Owner approval requirements. Under the 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 adverse events occur, including (i) the bankruptcy of Toshiba or a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) 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 because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth Vogtle Construction Monitoring (VCM) report by more than $1 billion or extension of the project schedule contained in the seventeenth VCM report by more than one year. In addition, under the term sheet, 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 Services Agreement or agreements with the primary construction contractor or Southern Nuclear.

The term sheet also confirms 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.

In the seventeenth VCM report, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4. Georgia Power's recommendation to go forward with completion of Vogtle Units 3 and 4 is based on the following assumptions about the regulatory treatment of this recommendation, if the recommendation to go forward is adopted by the Georgia PSC: (i) that pursuant to Georgia law, the Georgia PSC in the seventeenth VCM proceeding approves the new cost and schedule forecast and finds that it is a reasonable basis for going forward, and that if the Georgia PSC disapproves all or part of the proposed cost and schedule revisions, Georgia Power may cancel Plant Vogtle Units 3 and 4 and recover its actual investment in Plant Vogtle Units 3 and 4; (ii) that the Vogtle Cost Settlement Agreement remains in full force and effect, including Georgia Power retaining the burden of proving all capital costs above $5.680 billion were prudent; (iii) that while the Georgia PSC will make no prudence finding in the seventeenth VCM proceeding, nor will the certified amount be amended consistent with the Vogtle Cost Settlement Agreement, the Georgia PSC recognizes that the certified amount is not a cap, and all costs that are approved and presumed or shown to be prudently incurred will be recoverable by Georgia Power; (iv) that Georgia Power is not a guarantor of the Toshiba Guarantee, and the failure of Toshiba to pay the Toshiba Guarantee, the failure of the U.S. Congress to extend the PTCs for Plant Vogtle Units 3 and 4, or the failure of the DOE to extend the Loan Guarantee Agreement with Georgia Power to reflect the increased capital amounts, will not reduce the amount of investment Georgia Power is otherwise allowed to collect; and (v) that as conditions change and assumptions are either proven or disproven, Georgia Power and the Georgia PSC may reconsider the decision to go forward. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.

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Georgia Power's approximate proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 is as follows:

	(in billions)
Estimated cost to complete	$	4.2
CWIP as of September 30, 2017	4.6
Guarantee Obligations	(1.7		)
Estimated capital costs	$	7.1
Vogtle Cost Settlement Agreement Revised Forecast	(5.7		)
Estimated net additional capital costs	$	1.4

Georgia Power's estimated financing costs during the construction period total approximately $3.4 billion, of which approximately $1.5 billion had been incurred through September 30, 2017.

Georgia Power's cancellation cost estimate results indicate that its proportionate share of the estimated costs to cancel both units is approximately $350 million. As a result, as of September 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:

	Cancellation Cost Estimate
	(in billions)
CWIP as of September 30, 2017	$	4.6
Financing costs collected, net of tax	1.5
Cancellation costs(*)	0.4
Guarantee Obligations	(1.7		)
Estimated net cancellation cost	$	4.8

(*) The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site.

The Guarantee Obligations continue to exist in the event of cancellation. In addition, under Georgia law, prudently incurred costs related to certificated projects cancelled by the Georgia PSC are allowed recovery, including carrying costs, in future retail rates. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery.

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

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.

(3) Articles of Incorporation and By-Laws
Alabama Power
(b)1	-	Articles of Amendment to the Articles of Incorporation of Alabama Power dated September 7, 2017. (Designated in Form 8-K dated September 5, 2017, File No. 1-3164, as Exhibit 4.5.)

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	(4) Instruments Describing Rights of Security Holders, Including Indentures
	Georgia Power
	(c)1	-	Fifty-Eighth Supplemental Indenture to Senior Note Indenture, dated as of August 8, 2017, providing for the issuance of the Series 2017C 2.00% Senior Notes due September 8, 2020. (Designated in Form 8-K dated August 3, 2017, File No. 1-6468, as Exhibit 4.2.)
	(c)2	-	Subordinated Note Indenture, dated as of September 1, 2017, between Georgia Power and Wells Fargo Bank, National Association, as Trustee, and First Supplemental Indenture thereto dated as of September 21, 2017. (Designated in Form 8-K dated September 18, 2017, File No. 1-6468, as Exhibit 4.3 and in Form 8-K dated September 18, 2017, File No. 1-6468, as Exhibit 4.4.)
	(c)3	-	Amendment No. 3, dated July 27, 2017 to Loan Guarantee Agreement dated February 20, 2014, between Georgia Power and the DOE. (Designated in Form 8-K dated July 27, 2017, File No. 1-6468, as Exhibit 4.1.)
	(10) Material Contracts
	Mississippi Power
	(e)1	-	Promissory Note dated September 15, 2017, between Mississippi Power and Southern Company in the aggregate principal amount of up to $150,000,000. (Designated in Form 8-K dated September 15, 2017, File No. 001-11229, as Exhibit 10.1.)
	Southern Company Gas
	(g)1	-	Asset Purchase Agreement, dated as of October 15, 2017, by and between Pivotal Utility Holdings, Inc., as Seller, and South Jersey Industries, Inc., as Buyer. (Designated in Form  8-K dated October 15, 2017, File No. 1-14174, as Exhibit 10.1.)
	(24) Power of Attorney and Resolutions
	Southern Company
	(a)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2016, File No. 1-3526 as Exhibit 24(a).)
	Alabama Power
	(b)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2016, 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, 2016, File No. 1-6468 as Exhibit 24(c).)
*	(c)2	-	Power of Attorney for Xia Liu.
	Gulf Power
	(d)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2016, File No. 001-31737 as Exhibit 24(d).)
*	(d)2	-	Power of Attorney for Robin B. Boren.
	Mississippi Power
	(e)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2016, File No. 001-11229 as Exhibit 24(e).)

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	Southern Power
	(f)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2016, File No. 001-37803 as Exhibit 24(f).)
	Southern Company Gas
	(g)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2016, File No. 1-14174 as Exhibit 24(g).)
	(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.

284

	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.
	(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.
	(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

285

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	Art P. Beattie
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: October 31, 2017

286

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: October 31, 2017

287

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: October 31, 2017

288

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: October 31, 2017

289

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: October 31, 2017

290

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	Joseph A. Miller
	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: October 31, 2017

291

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	Andrew W. Evans
	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: October 31, 2017

292

EX-24.C2

Exhibit 24(c)2

Xia Liu Executive Vice President Chief Financial Officer & Treasurer BIN 10240 241 Ralph McGill Boulevard NE Atlanta, GA 30308-3374 404 506 5000

October 23, 2017

Mr. Art P. Beattie The Southern Company 30 Ivan Allen Jr. Blvd., NW Atlanta, GA 30308 Ms. Melissa K. Caen Southern Company Services, Inc. 30 Ivan Allen Jr. Blvd., NW Atlanta, GA 30308

Dear Mr. Beattie and Ms. Caen:

As an officer of Georgia Power Company (the “Company”), I hereby make, constitute, and appoint each of you my true and lawful Attorney in my name, place and stead, to sign and cause to be filed with the Securities and Exchange Commission (1) the Company’s Quarterly Reports on Form 10-Q during 2017, and (2) any necessary or appropriate amendment or amendments to any such reports and to the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, each such report or amendments to such reports to be accompanied in each case by any necessary or appropriate exhibits or schedules thereto.

Yours very truly,

/s/Xia Liu

Executive Vice President,

Chief Financial Officer and

Treasurer

EX-24.D2

Exhibit 24(d)2

One Energy Place Pensacola, FL 32520 850 444 6111tel

October 16, 2017

Mr. Art P. Beattie The Southern Company 30 Ivan Allen Jr. Blvd., NW Atlanta, GA 30308 Ms. Melissa K. Caen Southern Company Services, Inc. 30 Ivan Allen Jr. Blvd., NW Atlanta, GA 30308

Dear Mr. Beattie and Ms. Caen:

As an officer of Gulf Power Company (the “Company”), I hereby make, constitute, and appoint each of you my true and lawful Attorney in my name, place and stead, to sign and cause to be filed with the Securities and Exchange Commission (1) the Company’s Quarterly Reports on Form 10-Q during 2017, and (2) any necessary or appropriate amendment or amendments to any such reports and to the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, each such report or amendments to such reports to be accompanied in each case by any necessary or appropriate exhibits or schedules thereto.

Yours very truly,

/s/Robin B. Boren

Vice President,

Chief Financial Officer

and Treasurer

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:  October 31, 2017

/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, Art P. Beattie, 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:  October 31, 2017

/s/Art P. Beattie

Art P. Beattie

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:  October 31, 2017

/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:  October 31, 2017

/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:  October 31, 2017

/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:  October 31, 2017

/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:  October 31, 2017

/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:  October 31, 2017

/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:  October 31, 2017

/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:  October 31, 2017

/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, Joseph A. Miller, 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:   October 31, 2017

/s/Joseph A. Miller

Joseph A. Miller

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:  October 31, 2017

/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, Andrew W. Evans, 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:  October 31, 2017

/s/Andrew W. Evans

Andrew W. Evans

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:  October 31, 2017

/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, 2017, 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, 2017, 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, 2017, 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/Art P. Beattie

Art P. Beattie

Executive Vice President and

Chief Financial Officer

October 31, 2017

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, 2017, 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, 2017, 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, 2017, 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

October 31, 2017

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, 2017, 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, 2017, 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, 2017, 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

October 31, 2017

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, 2017, 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, 2017, 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, 2017, 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

October 31, 2017

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, 2017, 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, 2017, 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, 2017, 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

October 31, 2017

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, 2017, 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, 2017, 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, 2017, fairly presents, in all material respects, the financial condition and results of operations of Southern Power Company.

/s/Joseph A. Miller

Joseph A. Miller

Chairman, President and Chief Executive Officer

/s/William C. Grantham

William C. Grantham

Senior Vice President, Treasurer and

Chief Financial Officer

October 31, 2017

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, 2017, 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 year ended September 30, 2017, 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 year ended September 30, 2017, fairly presents, in all material respects, the financial condition and results of operations of Southern Company Gas.

/s/Andrew W. Evans

Andrew W. Evans

Chairman, President, and Chief Executive Officer

/s/Elizabeth W. Reese

Elizabeth W. Reese

Executive Vice President,

Chief Financial Officer, and Treasurer

October 31, 2017

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2017 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, 2017
Amendment Flag	false
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding (in shares)	1,003,627,691
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 Common Stock, Shares Outstanding (in shares)	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 Common Stock, Shares Outstanding (in shares)	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 Common Stock, Shares Outstanding (in shares)	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 Common Stock, Shares Outstanding (in shares)	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 Common Stock, Shares Outstanding (in shares)	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 Common Stock, Shares Outstanding (in shares)	100

XML

Condensed Consolidated Statements of Income (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Operating Revenues:
Retail electric revenues	$ 4,615	$ 4,808		$ 11,786	$ 11,932
Wholesale electric revenues	718	613		1,867	1,455
Other electric revenues	168	181		510	529
Natural gas revenues	532	518		2,746	518
Other revenues	168	144		494	281
Total operating revenues	6,201	6,264		17,403	14,715
Operating Expenses:
Fuel	1,285	1,400		3,372	3,334
Purchased power	256	227		646	581
Cost of natural gas	134	133		1,085	133
Cost of other sales	90	84		293	161
Other operations and maintenance	1,287	1,411		3,918	3,616
Depreciation and amortization	767	695		2,236	1,805
Taxes other than income taxes	303	309		941	821
Estimated loss on Kemper IGCC	34	88		3,155	222
Total operating expenses	4,156	4,347		15,646	10,673
Operating Income	2,045	1,917		1,757	4,042
Other Income and (Expense):
Allowance for equity funds used during construction	18	52		133	150
Earnings from equity method investments	32	29		100	28
Interest expense, net of amounts capitalized	(407)	(374)		(1,248)	(913)
Other income (expense), net	11	(8)		2	(66)
Total other income and (expense)	(346)	(301)		(1,013)	(801)
Earnings Before Income Taxes	1,699	1,616		744	3,241
Income taxes	590	439		317	917
Consolidated Net Income	1,109	1,177		427	2,324
Less:
Dividends on preferred and preference stock of subsidiaries	10	11		32	34
Net income attributable to noncontrolling interests	30	27		48	39
Net Income	$ 1,069	$ 1,139		$ 347	$ 2,251
Earnings per share —
Basic (in dollars per share)	$ 1.07	$ 1.18		$ 0.35	$ 2.40
Diluted (in dollars per share)	$ 1.06	$ 1.17		$ 0.35	$ 2.38
Average number of shares of common stock outstanding (in millions)
Basic (in shares)	1,003	968		998	940
Diluted (in shares)	1,010	975		1,005	945
Cash dividends paid per share of common stock (in dollars per share)	$ 0.58	$ 0.56		$ 1.7200	$ 1.6625
ALABAMA POWER CO
Operating Revenues:
Retail electric revenues	$ 1,595	$ 1,629		$ 4,155	$ 4,139
Wholesale revenues, non-affiliates	77	82		210	211
Wholesale revenues, affiliates	18	18		83	49
Other revenues	50	56		158	162
Total operating revenues	1,740	1,785		4,606	4,561
Operating Expenses:
Fuel	343	410		944	973
Purchased power, non-affiliates	57	63		132	139
Purchased power, affiliates	55	41		117	129
Other operations and maintenance	391	348		1,134	1,097
Depreciation and amortization	185	177		549	524
Taxes other than income taxes	93	96		284	286
Total operating expenses	1,124	1,135		3,160	3,148
Operating Income	616	650		1,446	1,413
Other Income and (Expense):
Allowance for equity funds used during construction	11	7		27	23
Interest expense, net of amounts capitalized	(76)	(77)		(229)	(224)
Other income (expense), net	(5)	(5)		(8)	(16)
Total other income and (expense)	(70)	(75)		(210)	(217)
Earnings Before Income Taxes	546	575		1,236	1,196
Income taxes	216	219		493	462
Consolidated Net Income	330	356		743	734
Less:
Dividends on preferred and preference stock of subsidiaries	5	4		14	13
Net Income	325	352		729	721
GEORGIA POWER CO
Operating Revenues:
Retail electric revenues	2,402	2,540		5,995	6,164
Wholesale revenues, non-affiliates	45	49		124	131
Wholesale revenues, affiliates	6	9		23	24
Other revenues	93	100		284	302
Total operating revenues	2,546	2,698		6,426	6,621
Operating Expenses:
Fuel	482	575		1,297	1,390
Purchased power, non-affiliates	119	102		310	277
Purchased power, affiliates	161	142		470	392
Other operations and maintenance	413	496		1,194	1,393
Depreciation and amortization	225	215		669	639
Taxes other than income taxes	112	114		311	311
Total operating expenses	1,512	1,644		4,251	4,402
Operating Income	1,034	1,054		2,175	2,219
Other Income and (Expense):
Allowance for equity funds used during construction				29	36
Interest expense, net of amounts capitalized	(105)	(98)		(310)	(290)
Other income (expense), net	5	11		41	35
Total other income and (expense)	(100)	(87)		(269)	(255)
Earnings Before Income Taxes	934	967		1,906	1,964
Income taxes	350	363		705	734
Consolidated Net Income	584	604		1,201	1,230
Less:
Dividends on preferred and preference stock of subsidiaries	4	4		13	13
Net Income	580	600		1,188	1,217
GULF POWER CO
Operating Revenues:
Retail electric revenues	375	377		972	978
Wholesale revenues, non-affiliates	14	17		44	48
Wholesale revenues, affiliates	28	23		75	59
Other revenues	20	19		53	51
Total operating revenues	437	436		1,144	1,136
Operating Expenses:
Fuel	127	141		323	342
Purchased power, non-affiliates	37	33		104	95
Purchased power, affiliates	2	3		13	9
Other operations and maintenance	81	86		252	239
Depreciation and amortization	42	49		95	129
Taxes other than income taxes	33	34		88	93
Loss on Plant Scherer Unit 3	0	0		33	0
Total operating expenses	322	346		908	907
Operating Income	115	90		236	229
Other Income and (Expense):
Interest expense, net of amounts capitalized	(13)	(11)		(37)	(36)
Other income (expense), net	1	(2)		0	(4)
Total other income and (expense)	(12)	(13)		(37)	(40)
Earnings Before Income Taxes	103	77		199	189
Income taxes	40	30		78	74
Consolidated Net Income	63	47		121	115
Less:
Dividends on preferred and preference stock of subsidiaries	0	2		4	7
Net Income	63	45		117	108
MISSISSIPPI POWER CO
Operating Revenues:
Retail electric revenues	243	263		665	652
Wholesale revenues, non-affiliates	72	78		196	198
Wholesale revenues, affiliates	21	7		40	23
Other revenues	5	4		14	12
Total operating revenues	341	352		915	885
Operating Expenses:
Fuel	120	112		301	268
Purchased power, non-affiliates	4	3		7	4
Purchased power, affiliates	2	5		13	14
Other operations and maintenance	66	74		206	211
Depreciation and amortization	39	30		120	114
Taxes other than income taxes	25	31		77	81
Estimated loss on Kemper IGCC	34	88		3,155	222
Total operating expenses	290	343		3,879	914
Operating Income	51	9		(2,964)	(29)
Other Income and (Expense):
Allowance for equity funds used during construction	1	31		72	90
Interest expense, net of amounts capitalized	13	(15)		(23)	(46)
Other income (expense), net	(1)	(1)		(3)	(4)
Total other income and (expense)	13	15		46	40
Earnings Before Income Taxes	64	24		(2,918)	11
Income taxes	24	(2)		(885)	(29)
Consolidated Net Income	40	26		(2,033)	40
Less:
Dividends on preferred and preference stock of subsidiaries	0	0		1	1
Net Income	40	26		(2,034)	39
SOUTHERN POWER CO
Operating Revenues:
Wholesale revenues, non-affiliates	510	387		1,293	866
Wholesale revenues, affiliates	105	110		295	313
Other revenues	3	3		9	10
Total operating revenues	618	500		1,597	1,189
Operating Expenses:
Fuel	189	154		460	341
Purchased power, non-affiliates	36	25		90	60
Purchased power, affiliates	7	8		23	16
Other operations and maintenance	83	81		272	246
Depreciation and amortization	131	93		379	247
Taxes other than income taxes	13	5		37	17
Total operating expenses	459	366		1,261	927
Operating Income	159	134		336	262
Other Income and (Expense):
Interest expense, net of amounts capitalized	(47)	(35)		(144)	(78)
Other income (expense), net	3	2		3	3
Total other income and (expense)	(44)	(33)		(141)	(75)
Earnings Before Income Taxes	115	101		195	187
Income taxes	(39)	(102)		(129)	(167)
Consolidated Net Income	154	203		324	354
Less:
Net income attributable to noncontrolling interests	30	27		48	39
Net Income	124	176		276	$ 315
SOUTHERN Co GAS
Operating Revenues:
Natural gas revenues	532	518		2,746
Other revenues	33	25		95
Total operating revenues	565	543		2,841
Operating Expenses:
Cost of natural gas	134	133		1,085
Cost of other sales	7	2		20
Other operations and maintenance	205	216		671
Depreciation and amortization	125	116		370
Merger-related expenses	0	35		0
Taxes other than income taxes	26	29		140
Total operating expenses	497	531		2,286
Operating Income	68	12		555
Other Income and (Expense):
Earnings from equity method investments	32	29		100
Interest expense, net of amounts capitalized	(51)	(39)		(145)
Other income (expense), net	18	9		26
Total other income and (expense)	(1)	(1)		(19)
Earnings Before Income Taxes	67	11		536
Income taxes	52	7		233
Consolidated Net Income	15	4		303
Less:
Net income attributable to noncontrolling interests	0	0		0
Net Income	$ 15	$ 4		$ 303
Predecessor | SOUTHERN Co GAS
Operating Revenues:
Natural gas revenues			$ 1,841
Other revenues			64
Total operating revenues			1,905
Operating Expenses:
Cost of natural gas			755
Cost of other sales			14
Other operations and maintenance			454
Depreciation and amortization			206
Merger-related expenses			56
Taxes other than income taxes			99
Total operating expenses			1,584
Operating Income			321
Other Income and (Expense):
Earnings from equity method investments			2
Interest expense, net of amounts capitalized			(96)
Other income (expense), net			5
Total other income and (expense)			(89)
Earnings Before Income Taxes			232
Income taxes			87
Consolidated Net Income			145
Less:
Net income attributable to noncontrolling interests			14
Net Income			$ 131

XML

Condensed Consolidated Statements of Income (Unaudited) - Parenthetical - SOUTHERN Co GAS - USD ($) $ in Millions	3 Months Ended		6 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2017
Excise taxes collected	$ 9	$ 9		$ 75
Predecessor
Excise taxes collected			$ 57

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Net Income	$ 1,109	$ 1,177		$ 427	$ 2,324
Qualifying hedges:
Changes in fair value, net of tax	25	19		54	(118)
Reclassification adjustment for amounts included in net income, net of tax	(17)	2		(59)	20
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	1	1		3	3
Total other comprehensive income (loss)	9	22		(2)	(95)
Comprehensive Income	1,118	1,199		425	2,229
Less:
Dividends on preferred and preference stock of subsidiaries	10	11		32	34
Comprehensive income attributable to noncontrolling interests	30	27		48	39
Comprehensive Income (Loss) Attributable to Parent	1,078	1,161		345	2,156
ALABAMA POWER CO
Net Income	330	356		743	734
Qualifying hedges:
Changes in fair value, net of tax	0	0		0	(2)
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	1
Comprehensive Income	331	357		746	735
Less:
Dividends on preferred and preference stock of subsidiaries	5	4		14	13
GEORGIA POWER CO
Net Income	584	604		1,201	1,230
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	1	1		2	2
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	1	1		2	2
Comprehensive Income	585	605		1,203	1,232
Less:
Dividends on preferred and preference stock of subsidiaries	4	4		13	13
GULF POWER CO
Net Income	63	47		121	115
Qualifying hedges:
Changes in fair value, net of tax	0	0		(1)	(4)
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	0	0		(1)	(4)
Comprehensive Income	63	47		120	111
Less:
Dividends on preferred and preference stock of subsidiaries	0	2		4	7
MISSISSIPPI POWER CO
Net Income	40	26		(2,033)	40
Qualifying hedges:
Changes in fair value, net of tax	(1)	0		0	(1)
Reclassification adjustment for amounts included in net income, net of tax	0	0		1	1
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	(1)	0		1	0
Comprehensive Income	39	26		(2,032)	40
Less:
Dividends on preferred and preference stock of subsidiaries	0	0		1	1
SOUTHERN POWER CO
Net Income	154	203		324	354
Qualifying hedges:
Changes in fair value, net of tax	25	23		58	(1)
Reclassification adjustment for amounts included in net income, net of tax	(20)	(1)		(68)	13
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	5	22		(10)	12
Comprehensive Income	159	225		314	366
Less:
Comprehensive income attributable to noncontrolling interests	30	27		48	39
Comprehensive Income (Loss) Attributable to Parent	129	198		266	$ 327
SOUTHERN Co GAS
Net Income	15	4		303
Qualifying hedges:
Changes in fair value, net of tax	0	(3)		(3)
Reclassification adjustment for amounts included in net income, net of tax	0	0		0
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	0	0		0
Total other comprehensive income (loss)	0	(3)		(3)
Comprehensive Income	15	1		300
Less:
Comprehensive income attributable to noncontrolling interests	0	0		0
Comprehensive Income (Loss) Attributable to Parent	$ 15	$ 1		$ 300
Predecessor | SOUTHERN Co GAS
Net Income			$ 145
Qualifying hedges:
Changes in fair value, net of tax			(41)
Reclassification adjustment for amounts included in net income, net of tax			1
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax			5
Total other comprehensive income (loss)			(35)
Comprehensive Income			110
Less:
Comprehensive income attributable to noncontrolling interests			14
Comprehensive Income (Loss) Attributable to Parent			$ 96

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Changes in fair value, tax	$ 15	$ 12		$ 32	$ (74)
Reclassification adjustment for qualified hedges, tax	(10)	2		(36)	13
Reclassification adjustment for pension and other post retirement benefit plans, tax	1	1		2	2
ALABAMA POWER CO
Changes in fair value, tax	0	0		0	(1)
Reclassification adjustment for qualified hedges, tax	1	1		2	2
GEORGIA POWER CO
Reclassification adjustment for qualified hedges, tax	0	0		1	1
GULF POWER CO
Changes in fair value, tax	0	0		(1)	(3)
MISSISSIPPI POWER CO
Changes in fair value, tax	0	0		0	0
Reclassification adjustment for qualified hedges, tax	0	0		0	0
SOUTHERN POWER CO
Changes in fair value, tax	15	14		35	(1)
Reclassification adjustment for qualified hedges, tax	(12)	(1)		(42)	$ 7
SOUTHERN Co GAS
Changes in fair value, tax	0	(2)		(2)
Reclassification adjustment for qualified hedges, tax	0	0		0
Reclassification adjustment for pension and other post retirement benefit plans, tax	$ 0	$ 0		$ (1)
Predecessor | SOUTHERN Co GAS
Changes in fair value, tax			$ (23)
Reclassification adjustment for qualified hedges, tax			0
Reclassification adjustment for pension and other post retirement benefit plans, tax			$ 4

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($)	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Operating Activities:
Net Income	$ 427,000,000	$ 2,324,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	2,564,000,000	2,109,000,000
Deferred income taxes	15,000,000	(22,000,000)
Allowance for equity funds used during construction	(133,000,000)	(150,000,000)
Pension, postretirement, and other employee benefits	(64,000,000)	(158,000,000)
Settlement of asset retirement obligations	(137,000,000)	(117,000,000)
Hedge settlements	0	(236,000,000)
Estimated loss on Kemper IGCC	3,148,000,000	222,000,000
Other, net	(8,000,000)	(1,000,000)
Changes in certain current assets and liabilities —
-Receivables	426,000,000	(458,000,000)
-Fossil fuel stock	59,000,000	204,000,000
-Natural gas for sale, net of temporary LIFO liquidation	0	(222,000,000)
-Other current assets	(164,000,000)	(112,000,000)
-Accounts payable	(467,000,000)	(9,000,000)
-Accrued taxes	157,000,000	1,062,000,000
-Accrued compensation	(230,000,000)	(122,000,000)
-Retail fuel cost over recovery	(211,000,000)	(106,000,000)
-Other current liabilities	(129,000,000)	88,000,000
Net cash provided from operating activities	5,253,000,000	4,296,000,000
Investing Activities:
Business acquisitions, net of cash acquired	(1,032,000,000)	(9,513,000,000)
Property additions	(5,242,000,000)	(5,252,000,000)
Investment in restricted cash	(16,000,000)	(750,000,000)
Distribution of restricted cash	33,000,000	746,000,000
Nuclear decommissioning trust fund purchases	(585,000,000)	(838,000,000)
Nuclear decommissioning trust fund sales	580,000,000	832,000,000
Cost of removal, net of salvage	(208,000,000)	(155,000,000)
Change in construction payables, net	120,000,000	(259,000,000)
Investment in unconsolidated subsidiaries	(134,000,000)	(1,421,000,000)
Payments pursuant to LTSAs	(189,000,000)	(125,000,000)
Other investing activities	(14,000,000)	95,000,000
Net cash used for investing activities	(6,687,000,000)	(16,640,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	(515,000,000)	655,000,000
Proceeds —
Long-term debt	4,068,000,000	14,091,000,000
Common stock	613,000,000	3,265,000,000
Preferred stock	250,000,000	0
Short-term borrowings	1,263,000,000	0
Redemptions and repurchases —
Long-term debt	(1,981,000,000)	(2,405,000,000)
Preferred and preference stock	(150,000,000)	0
Short-term borrowings	(409,000,000)	(475,000,000)
Distributions to noncontrolling interests	(89,000,000)	(22,000,000)
Capital contributions from noncontrolling interests	79,000,000	367,000,000
Purchase of membership interests from noncontrolling interests	0	(129,000,000)
Payment of common stock dividends	(1,716,000,000)	(1,553,000,000)
Other financing activities	(113,000,000)	(185,000,000)
Net cash provided from financing activities	1,300,000,000	13,609,000,000
Net Change in Cash and Cash Equivalents	(134,000,000)	1,265,000,000
Cash and Cash Equivalents at Beginning of Period	1,975,000,000	1,404,000,000
Cash and Cash Equivalents at End of Period	1,841,000,000	2,669,000,000
Cash paid (received) during the period for —
Interest	1,286,000,000	766,000,000
Income taxes, net	(187,000,000)	(151,000,000)
Noncash Investing and Financing Items [Abstract]
Noncash transactions — Accrued property additions at end of period	805,000,000	578,000,000
ALABAMA POWER CO
Operating Activities:
Net Income	743,000,000	734,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	666,000,000	634,000,000
Deferred income taxes	260,000,000	267,000,000
Allowance for equity funds used during construction	(27,000,000)	(23,000,000)
Pension, postretirement, and other employee benefits	(4,000,000)	(14,000,000)
Other, net	43,000,000	(12,000,000)
Changes in certain current assets and liabilities —
-Receivables	(163,000,000)	(4,000,000)
-Fossil fuel stock	34,000,000	18,000,000
-Other current assets	(58,000,000)	(46,000,000)
-Accounts payable	(125,000,000)	(113,000,000)
-Accrued taxes	159,000,000	207,000,000
-Accrued compensation	(48,000,000)	(22,000,000)
-Retail fuel cost over recovery	(76,000,000)	(104,000,000)
-Other current liabilities	7,000,000	19,000,000
Net cash provided from operating activities	1,411,000,000	1,541,000,000
Investing Activities:
Property additions	(1,211,000,000)	(947,000,000)
Nuclear decommissioning trust fund purchases	(174,000,000)	(275,000,000)
Nuclear decommissioning trust fund sales	174,000,000	275,000,000
Cost of removal, net of salvage	(82,000,000)	(70,000,000)
Change in construction payables, net	105,000,000	(37,000,000)
Other investing activities	(29,000,000)	(28,000,000)
Net cash used for investing activities	(1,217,000,000)	(1,082,000,000)
Proceeds —
Senior notes	550,000,000	400,000,000
Capital contributions from parent company	337,000,000	253,000,000
Preferred stock	250,000,000	0
Other long-term debt	0	45,000,000
Redemptions and repurchases —
Pollution control revenue bonds	(36,000,000)	0
Senior notes	(200,000,000)	(200,000,000)
Payment of common stock dividends	(536,000,000)	(574,000,000)
Other financing activities	(26,000,000)	(21,000,000)
Net cash provided from financing activities	339,000,000	(97,000,000)
Net Change in Cash and Cash Equivalents	533,000,000	362,000,000
Cash and Cash Equivalents at Beginning of Period	420,000,000	194,000,000
Cash and Cash Equivalents at End of Period	953,000,000	556,000,000
Cash paid (received) during the period for —
Interest	217,000,000	215,000,000
Income taxes, net	146,000,000	(70,000,000)
Noncash Investing and Financing Items [Abstract]
Noncash transactions — Accrued property additions at end of period	189,000,000	84,000,000
GEORGIA POWER CO
Operating Activities:
Net Income	1,201,000,000	1,230,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	821,000,000	794,000,000
Deferred income taxes	328,000,000	346,000,000
Allowance for equity funds used during construction	(29,000,000)	(36,000,000)
Deferred expenses	(30,000,000)	(40,000,000)
Pension, postretirement, and other employee benefits	(42,000,000)	(14,000,000)
Settlement of asset retirement obligations	(95,000,000)	(93,000,000)
Other, net	(21,000,000)	7,000,000
Changes in certain current assets and liabilities —
-Receivables	(254,000,000)	(162,000,000)
-Fossil fuel stock	(2,000,000)	128,000,000
-Other current assets	(29,000,000)	62,000,000
-Accounts payable	(161,000,000)	39,000,000
-Accrued taxes	(52,000,000)	(22,000,000)
-Accrued compensation	(60,000,000)	(26,000,000)
-Retail fuel cost over recovery	(84,000,000)	9,000,000
-Other current liabilities	(11,000,000)	44,000,000
Net cash provided from operating activities	1,480,000,000	2,266,000,000
Investing Activities:
Property additions	(1,907,000,000)	(1,566,000,000)
Nuclear decommissioning trust fund purchases	(411,000,000)	(563,000,000)
Nuclear decommissioning trust fund sales	406,000,000	558,000,000
Cost of removal, net of salvage	(54,000,000)	(45,000,000)
Change in construction payables, net of joint owner portion	180,000,000	(139,000,000)
Payments pursuant to LTSAs	(59,000,000)	(27,000,000)
Sale of property	63,000,000	10,000,000
Other investing activities	(52,000,000)	14,000,000
Net cash used for investing activities	(1,834,000,000)	(1,758,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	(391,000,000)	(63,000,000)
Proceeds —
Senior notes	1,350,000,000	650,000,000
FFB loan	0	300,000,000
Capital contributions from parent company	412,000,000	294,000,000
Short-term borrowings	700,000,000	0
Other long-term debt	370,000,000	0
Redemptions and repurchases —
Pollution control revenue bonds	(65,000,000)	(4,000,000)
Senior notes	(450,000,000)	(700,000,000)
Short-term borrowings	(300,000,000)	0
Payment of common stock dividends	(961,000,000)	(979,000,000)
Other financing activities	(48,000,000)	(26,000,000)
Net cash provided from financing activities	617,000,000	(528,000,000)
Net Change in Cash and Cash Equivalents	263,000,000	(20,000,000)
Cash and Cash Equivalents at Beginning of Period	3,000,000	67,000,000
Cash and Cash Equivalents at End of Period	266,000,000	47,000,000
Cash paid (received) during the period for —
Interest	284,000,000	277,000,000
Income taxes, net	369,000,000	188,000,000
Noncash Investing and Financing Items [Abstract]
Noncash transactions — Accrued property additions at end of period	470,000,000	226,000,000
GULF POWER CO
Operating Activities:
Net Income	121,000,000	115,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	100,000,000	134,000,000
Deferred income taxes	57,000,000	15,000,000
Loss on Plant Scherer Unit 3	33,000,000	0
Other, net	(5,000,000)	(2,000,000)
Changes in certain current assets and liabilities —
-Receivables	(65,000,000)	(9,000,000)
-Fossil fuel stock	7,000,000	49,000,000
-Other current assets	11,000,000	3,000,000
-Accrued taxes	21,000,000	40,000,000
-Accrued compensation	(10,000,000)	(5,000,000)
-Over recovered regulatory clause revenues	(8,000,000)	26,000,000
-Other current liabilities	10,000,000	8,000,000
Net cash provided from operating activities	272,000,000	374,000,000
Investing Activities:
Property additions	(142,000,000)	(106,000,000)
Cost of removal, net of salvage	(16,000,000)	(8,000,000)
Change in construction payables, net	(9,000,000)	(7,000,000)
Other investing activities	(6,000,000)	(6,000,000)
Net cash used for investing activities	(173,000,000)	(127,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	(268,000,000)	(42,000,000)
Proceeds —
Senior notes	300,000,000	0
Capital contributions from parent company	7,000,000	10,000,000
Common stock	175,000,000	0
Redemptions and repurchases —
Preferred and preference stock	(150,000,000)	0
Senior notes	(85,000,000)	(125,000,000)
Payment of common stock dividends	(94,000,000)	(90,000,000)
Other financing activities	(3,000,000)	(5,000,000)
Net cash provided from financing activities	(118,000,000)	(252,000,000)
Net Change in Cash and Cash Equivalents	(19,000,000)	(5,000,000)
Cash and Cash Equivalents at Beginning of Period	56,000,000	74,000,000
Cash and Cash Equivalents at End of Period	37,000,000	69,000,000
Cash paid (received) during the period for —
Interest	24,000,000	29,000,000
Income taxes, net	19,000,000	14,000,000
Noncash Investing and Financing Items [Abstract]
Noncash transactions — Accrued property additions at end of period	25,000,000	13,000,000
MISSISSIPPI POWER CO
Operating Activities:
Net Income	(2,033,000,000)	40,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	144,000,000	115,000,000
Deferred income taxes	(1,159,000,000)	34,000,000
Allowance for equity funds used during construction	(72,000,000)	(90,000,000)
Estimated loss on Kemper IGCC	3,148,000,000	222,000,000
Other, net	(26,000,000)	(1,000,000)
Changes in certain current assets and liabilities —
-Receivables	438,000,000	3,000,000
-Fossil fuel stock	21,000,000	8,000,000
-Other current assets	(9,000,000)	34,000,000
-Accounts payable	(21,000,000)	5,000,000
-Accrued taxes	20,000,000	96,000,000
-Accrued compensation	(12,000,000)	(5,000,000)
-Over recovered regulatory clause revenues	(47,000,000)	(20,000,000)
-Customer liability associated with Kemper refunds	0	(73,000,000)
-Other current liabilities	(31,000,000)	5,000,000
Net cash provided from operating activities	361,000,000	373,000,000
Investing Activities:
Property additions	(411,000,000)	(592,000,000)
Change in construction payables, net	(47,000,000)	(25,000,000)
Government grant proceeds	0	137,000,000
Other investing activities	(25,000,000)	(29,000,000)
Net cash used for investing activities	(483,000,000)	(509,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	(23,000,000)	0
Proceeds —
Capital contributions from parent company	1,002,000,000	227,000,000
Short-term borrowings	113,000,000	0
Long-term debt to parent company	40,000,000	200,000,000
Other long-term debt	0	900,000,000
Redemptions and repurchases —
Short-term borrowings	(109,000,000)	(475,000,000)
Long-term debt to parent company	(591,000,000)	(225,000,000)
Other long-term debt	(300,000,000)	(425,000,000)
Other financing activities	(3,000,000)	(5,000,000)
Net cash provided from financing activities	129,000,000	197,000,000
Net Change in Cash and Cash Equivalents	7,000,000	61,000,000
Cash and Cash Equivalents at Beginning of Period	224,000,000	98,000,000
Cash and Cash Equivalents at End of Period	231,000,000	159,000,000
Cash paid (received) during the period for —
Interest	45,000,000	36,000,000
Income taxes, net	(209,000,000)	(231,000,000)
Noncash Investing and Financing Items [Abstract]
Noncash transactions — Accrued property additions at end of period	32,000,000	80,000,000
SOUTHERN POWER CO
Operating Activities:
Net Income	324,000,000	354,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	404,000,000	262,000,000
Deferred income taxes	240,000,000	(668,000,000)
Amortization of investment tax credits	(42,000,000)	(25,000,000)
Collateral deposits	(1,000,000)	(80,000,000)
Income taxes receivable, non-current	(42,000,000)	0
Other, net	(2,000,000)	19,000,000
Changes in certain current assets and liabilities —
-Receivables	(77,000,000)	(82,000,000)
-Other current assets	38,000,000	(15,000,000)
-Accounts payable	(31,000,000)	7,000,000
-Accrued taxes	79,000,000	483,000,000
-Other current liabilities	5,000,000	14,000,000
Net cash provided from operating activities	895,000,000	269,000,000
Investing Activities:
Business acquisitions, net of cash acquired	(1,032,000,000)	(1,134,000,000)
Property additions	(218,000,000)	(1,702,000,000)
Investment in restricted cash	(16,000,000)	(750,000,000)
Distribution of restricted cash	33,000,000	746,000,000
Change in construction payables, net	(166,000,000)	(69,000,000)
Payments pursuant to LTSAs	(99,000,000)	(58,000,000)
Other investing activities	7,000,000	(41,000,000)
Net cash used for investing activities	(1,491,000,000)	(3,008,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	(89,000,000)	692,000,000
Proceeds —
Senior notes	0	1,531,000,000
Capital contributions from parent company	0	800,000,000
Other long-term debt	43,000,000	63,000,000
Redemptions and repurchases —
Other long-term debt	(4,000,000)	(84,000,000)
Distributions to noncontrolling interests	(89,000,000)	(22,000,000)
Capital contributions from noncontrolling interests	79,000,000	367,000,000
Purchase of membership interests from noncontrolling interests	0	(129,000,000)
Payment of common stock dividends	(238,000,000)	(204,000,000)
Other financing activities	(27,000,000)	(14,000,000)
Net cash provided from financing activities	(325,000,000)	3,000,000,000
Net Change in Cash and Cash Equivalents	(921,000,000)	261,000,000
Cash and Cash Equivalents at Beginning of Period	1,099,000,000	830,000,000
Cash and Cash Equivalents at End of Period	178,000,000	1,091,000,000
Cash paid (received) during the period for —
Interest	144,000,000	49,000,000
Income taxes, net	(343,000,000)	71,000,000
Noncash Investing and Financing Items [Abstract]
Noncash transactions — Accrued property additions at end of period	16,000,000	210,000,000
SOUTHERN Co GAS
Operating Activities:
Net Income	303,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	370,000,000
Deferred income taxes	265,000,000
Pension, postretirement, and other employee benefits	(4,000,000)
Stock based compensation expense	25,000,000
Hedge settlements	0
Mark-to-market adjustments	(32,000,000)
Other, net	(67,000,000)
Changes in certain current assets and liabilities —
-Receivables	534,000,000
-Natural gas for sale, net of temporary LIFO liquidation	0
-Prepaid income taxes	(7,000,000)
-Other current assets	(42,000,000)
-Accounts payable	(169,000,000)
-Accrued taxes	(24,000,000)
-Accrued compensation	(11,000,000)
-Other current liabilities	8,000,000
Net cash provided from operating activities	1,149,000,000
Investing Activities:
Property additions	(1,093,000,000)
Cost of removal, net of salvage	(45,000,000)
Change in construction payables, net	49,000,000
Investment in unconsolidated subsidiaries	(128,000,000)
Returned investment in unconsolidated subsidiaries	22,000,000
Other investing activities	3,000,000
Net cash used for investing activities	(1,192,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	(323,000,000)
First mortgage bonds	0
Proceeds —
First mortgage bonds	200,000,000
Senior notes	450,000,000
Capital contributions from parent company	79,000,000
Redemptions and repurchases —
Long-term debt	(22,000,000)
Senior notes	0
Distributions to noncontrolling interests	0
Payment of common stock dividends	(332,000,000)
Other financing activities	(7,000,000)
Net cash provided from financing activities	45,000,000
Net Change in Cash and Cash Equivalents	2,000,000
Cash and Cash Equivalents at Beginning of Period	19,000,000
Cash and Cash Equivalents at End of Period	21,000,000	48,000,000
Cash paid (received) during the period for —
Interest	146,000,000
Income taxes, net	17,000,000
Noncash Investing and Financing Items [Abstract]
Noncash transactions — Accrued property additions at end of period	$ 112,000,000
Predecessor | SOUTHERN Co GAS
Redemptions and repurchases —
Cash and Cash Equivalents at Beginning of Period		$ 19,000,000

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended	6 Months Ended	9 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Net cash paid for capitalized interest			$ 72	$ 94
ALABAMA POWER CO
Net cash paid for capitalized interest			10	8
GEORGIA POWER CO
Net cash paid for capitalized interest			17	15
GULF POWER CO
Net cash paid for capitalized interest			0	0
MISSISSIPPI POWER CO
Interest paid			73	72
Net cash paid for capitalized interest			28	36
SOUTHERN POWER CO
Net cash paid for capitalized interest			7	$ 32
SOUTHERN Co GAS
Net cash paid for capitalized interest	$ 2		$ 9
Predecessor | SOUTHERN Co GAS
Net cash paid for capitalized interest		$ 3

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Current Assets:
Cash and cash equivalents	$ 1,841	$ 1,975
Receivables —
Customer accounts receivable	1,744	1,583
Energy marketing receivables	427	623
Unbilled revenues	595	706
Under recovered fuel clause revenues	62	0
Income taxes receivable, current	138	544
Other accounts and notes receivable	578	377
Accumulated provision for uncollectible accounts	(43)	(43)
Materials and supplies	1,499	1,462
Fossil fuel for generation	571	689
Natural gas for sale	631	631
Prepaid expenses	365	364
Other regulatory assets, current	585	581
Other current assets	209	230
Total current assets	9,202	9,722
Property, Plant, and Equipment:
In service	102,014	98,416
Less: Accumulated depreciation	31,164	29,852
Plant in service, net of depreciation	70,850	68,564
Nuclear fuel, at amortized cost	865	905
Construction work in progress	8,026	8,977
Total property, plant, and equipment	79,741	78,446
Other Property and Investments:
Goodwill	6,267	6,251
Equity investments in unconsolidated subsidiaries	1,637	1,549
Other intangible assets, net of amortization	902	970
Nuclear decommissioning trusts, at fair value	1,783	1,606
Leveraged leases	788	774
Miscellaneous property and investments	236	270
Total other property and investments	11,613	11,420
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,318	1,629
Unamortized loss on reacquired debt	210	223
Other regulatory assets, deferred	6,718	6,851
Other deferred charges and assets	1,513	1,406
Total deferred charges and other assets	9,759	10,109
Total Assets	110,315	109,697
Current Liabilities:
Securities due within one year	3,505	2,587
Notes payable	2,579	2,241
Energy marketing trade payables	451	597
Accounts payable —
Accounts payable	2,353	2,228
Customer deposits	550	558
Accrued taxes —
Accrued income taxes	176	193
Unrecognized tax benefits	17	385
Other accrued taxes	690	667
Accrued interest	443	518
Accrued compensation	703	915
Asset retirement obligations, current	245	378
Acquisitions payable	0	489
Other regulatory liabilities, current	139	236
Other current liabilities	752	925
Total current liabilities	12,603	12,917
Long-term Debt	44,042	42,629
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	14,321	14,092
Accumulated deferred ITCs	2,290	2,228
Employee benefit obligations	2,139	2,299
Asset retirement obligations, deferred	4,356	4,136
Other cost of removal obligations	2,708	2,748
Other regulatory liabilities, deferred	449	476
Other deferred credits and liabilities	1,048	1,278
Total deferred credits and other liabilities	27,311	27,257
Total Liabilities	83,956	82,803
Redeemable Preferred Stock of Subsidiaries	361	118
Redeemable Noncontrolling Interests	59	164
Common Stockholders' Equity:
Par value	5,018	4,952
Paid-in capital	10,300	9,661
Treasury, at cost	(35)	(31)
Retained earnings (accumulated deficit)	8,981	10,356
Accumulated other comprehensive income (loss)	(182)	(180)
Total Common Stockholders' Equity	24,082	24,758
Preferred and Preference Stock of Subsidiaries	462	609
Noncontrolling Interests	1,395	1,245
Total Stockholders' Equity	25,939	26,612
Total Liabilities and Stockholders' Equity	110,315	109,697
ALABAMA POWER CO
Current Assets:
Cash and cash equivalents	953	420
Receivables —
Customer accounts receivable	428	348
Unbilled revenues	149	146
Other accounts and notes receivable	47	27
Affiliated	45	40
Accumulated provision for uncollectible accounts	(8)	(10)
Materials and supplies	455	435
Fossil fuel for generation	171	205
Prepaid expenses	58	34
Other regulatory assets, current	122	149
Other current assets	5	11
Total current assets	2,425	1,805
Property, Plant, and Equipment:
In service	26,619	26,031
Less: Accumulated depreciation	9,463	9,112
Plant in service, net of depreciation	17,156	16,919
Nuclear fuel, at amortized cost	314	336
Construction work in progress	928	491
Total property, plant, and equipment	18,398	17,746
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	65	66
Nuclear decommissioning trusts, at fair value	869	792
Miscellaneous property and investments	121	112
Total other property and investments	1,055	970
Deferred Charges and Other Assets:
Deferred charges related to income taxes	525	525
Deferred under recovered regulatory clause revenues	17	150
Other regulatory assets, deferred	1,191	1,157
Other deferred charges and assets	178	163
Total deferred charges and other assets	1,911	1,995
Total Assets	23,789	22,516
Current Liabilities:
Securities due within one year	325	561
Accounts payable —
Affiliated	275	297
Other	376	433
Customer deposits	92	88
Accrued taxes —
Accrued income taxes	115	45
Other accrued taxes	128	42
Accrued interest	75	78
Accrued compensation	151	193
Other regulatory liabilities, current	4	85
Other current liabilities	50	76
Total current liabilities	1,591	1,898
Long-term Debt	7,083	6,535
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,919	4,654
Deferred credits related to income taxes	60	65
Accumulated deferred ITCs	118	110
Employee benefit obligations	289	300
Asset retirement obligations, deferred	1,564	1,503
Other cost of removal obligations	630	684
Other regulatory liabilities, deferred	93	100
Other deferred credits and liabilities	51	63
Total deferred credits and other liabilities	7,724	7,479
Total Liabilities	16,398	15,912
Redeemable Preferred Stock	329	85
Preference Stock	196	196
Common Stockholders' Equity:
Par value	1,222	1,222
Paid-in capital	2,961	2,613
Retained earnings (accumulated deficit)	2,711	2,518
Accumulated other comprehensive income (loss)	(28)	(30)
Total Common Stockholders' Equity	6,866	6,323
Total Liabilities and Stockholders' Equity	23,789	22,516
GEORGIA POWER CO
Current Assets:
Cash and cash equivalents	266	3
Receivables —
Customer accounts receivable	670	523
Unbilled revenues	276	224
Under recovered fuel clause revenues	62	0
Joint owner accounts receivable	222	57
Other accounts and notes receivable	82	81
Affiliated	21	18
Accumulated provision for uncollectible accounts	(3)	(3)
Materials and supplies	480	479
Fossil fuel for generation	300	298
Prepaid expenses	82	105
Other regulatory assets, current	200	193
Other current assets	27	38
Total current assets	2,685	2,016
Property, Plant, and Equipment:
In service	34,589	33,841
Less: Accumulated depreciation	11,655	11,317
Plant in service, net of depreciation	22,934	22,524
Nuclear fuel, at amortized cost	551	569
Construction work in progress	5,751	4,939
Total property, plant, and equipment	29,236	28,032
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	53	60
Nuclear decommissioning trusts, at fair value	914	814
Miscellaneous property and investments	51	46
Total other property and investments	1,018	920
Deferred Charges and Other Assets:
Deferred charges related to income taxes	669	676
Other regulatory assets, deferred	2,890	2,774
Other deferred charges and assets	608	417
Total deferred charges and other assets	4,167	3,867
Total Assets	37,106	34,835
Current Liabilities:
Securities due within one year	261	460
Notes payable	400	391
Accounts payable —
Affiliated	396	438
Other	1,012	589
Customer deposits	270	265
Accrued taxes —
Accrued income taxes	353	407
Accrued interest	121	106
Accrued compensation	164	224
Asset retirement obligations, current	214	299
Other current liabilities	192	297
Total current liabilities	3,383	3,476
Long-term Debt	11,610	10,225
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	6,328	6,000
Accumulated deferred ITCs	248	256
Employee benefit obligations	665	703
Asset retirement obligations, deferred	2,367	2,233
Other deferred credits and liabilities	232	320
Total deferred credits and other liabilities	9,840	9,512
Total Liabilities	24,833	23,213
Redeemable Preferred Stock	45	45
Preference Stock	221	221
Common Stockholders' Equity:
Par value	398	398
Paid-in capital	7,308	6,885
Retained earnings (accumulated deficit)	4,311	4,086
Accumulated other comprehensive income (loss)	(10)	(13)
Total Common Stockholders' Equity	12,007	11,356
Total Liabilities and Stockholders' Equity	37,106	34,835
GULF POWER CO
Current Assets:
Cash and cash equivalents	37	56
Receivables —
Customer accounts receivable	96	72
Unbilled revenues	68	55
Under recovered fuel clause revenues	15	17
Income taxes receivable, current	15	0
Other accounts and notes receivable	12	6
Affiliated	13	17
Accumulated provision for uncollectible accounts	(1)	(1)
Materials and supplies	58	55
Fossil fuel for generation	64	71
Other regulatory assets, current	55	44
Other current assets	15	30
Total current assets	447	422
Property, Plant, and Equipment:
In service	5,181	5,140
Less: Accumulated depreciation	1,457	1,382
Plant in service, net of depreciation	3,724	3,758
Construction work in progress	75	51
Total property, plant, and equipment	3,799	3,809
Deferred Charges and Other Assets:
Deferred charges related to income taxes	56	58
Other regulatory assets, deferred	499	512
Other deferred charges and assets	22	21
Total deferred charges and other assets	577	591
Total Assets	4,823	4,822
Current Liabilities:
Securities due within one year	7	87
Notes payable	0	268
Accounts payable —
Affiliated	46	59
Other	55	54
Customer deposits	35	35
Accrued taxes —
Other accrued taxes	41	20
Accrued interest	20	8
Accrued compensation	30	40
Deferred capacity expense, current	22	22
Other regulatory liabilities, current	1	16
Other current liabilities	37	40
Total current liabilities	294	649
Long-term Debt	1,285	987
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,003	948
Employee benefit obligations	90	96
Deferred capacity expense	103	119
Asset retirement obligations, deferred	125	120
Other cost of removal obligations	218	249
Other regulatory liabilities, deferred	45	47
Other deferred credits and liabilities	71	71
Total deferred credits and other liabilities	1,655	1,650
Total Liabilities	3,234	3,286
Preference Stock	0	147
Common Stockholders' Equity:
Par value	678	503
Paid-in capital	600	589
Retained earnings (accumulated deficit)	312	296
Accumulated other comprehensive income (loss)	(1)	1
Total Common Stockholders' Equity	1,589	1,389
Total Liabilities and Stockholders' Equity	4,823	4,822
MISSISSIPPI POWER CO
Current Assets:
Cash and cash equivalents	231	224
Receivables —
Customer accounts receivable	38	29
Unbilled revenues	41	42
Income taxes receivable, current	102	544
Other accounts and notes receivable	15	14
Affiliated	15	15
Materials and supplies	45	76
Fossil fuel for generation	20	100
Other regulatory assets, current	113	115
Other current assets	8	8
Total current assets	628	1,167
Property, Plant, and Equipment:
In service	4,836	4,865
Less: Accumulated depreciation	1,312	1,289
Plant in service, net of depreciation	3,524	3,576
Construction work in progress	75	2,545
Total property, plant, and equipment	3,599	6,121
Other Property and Investments:
Total other property and investments	28	12
Deferred Charges and Other Assets:
Deferred charges related to income taxes	62	361
Other regulatory assets, deferred	436	518
Accumulated deferred income taxes	279	0
Other deferred charges and assets	23	56
Total deferred charges and other assets	800	935
Total Assets	5,055	8,235
Current Liabilities:
Securities due within one year - parent	0	551
Securities due within one year	1,028	78
Notes payable	4	23
Accounts payable —
Affiliated	56	62
Other	82	135
Customer deposits	16	16
Accrued taxes —
Unrecognized tax benefits	2	383
Other accrued taxes	78	99
Accrued interest	16	46
Accrued compensation	29	42
Asset retirement obligations, current	15	32
Over recovered fuel clause liabilities	4	51
Other current liabilities	67	20
Total current liabilities	1,397	1,538
Long-term Debt	1,167	2,424
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	0	756
Employee benefit obligations	109	115
Asset retirement obligations, deferred	150	146
Other cost of removal obligations	175	170
Other regulatory liabilities, deferred	87	84
Other deferred credits and liabilities	23	26
Total deferred credits and other liabilities	544	1,297
Total Liabilities	3,108	5,259
Redeemable Preferred Stock	33	33
Common Stockholders' Equity:
Par value	38	38
Paid-in capital	4,529	3,525
Retained earnings (accumulated deficit)	(2,650)	(616)
Accumulated other comprehensive income (loss)	(3)	(4)
Total Common Stockholders' Equity	1,914	2,943
Total Liabilities and Stockholders' Equity	5,055	8,235
SOUTHERN POWER CO
Current Assets:
Cash and cash equivalents	178	1,099
Receivables —
Customer accounts receivable	148	102
Other accounts and notes receivable	61	34
Affiliated	74	57
Materials and supplies	351	337
Fossil fuel for generation	15	15
Prepaid income taxes	51	74
Other current assets	26	39
Total current assets	904	1,757
Property, Plant, and Equipment:
In service	13,734	12,728
Less: Accumulated depreciation	1,823	1,484
Plant in service, net of depreciation	11,911	11,244
Construction work in progress	425	398
Total property, plant, and equipment	12,336	11,642
Other Property and Investments:
Goodwill	2	2
Intangible assets, net (including goodwill)	417	436
Total other property and investments	417	436
Deferred Charges and Other Assets:
Prepaid LTSAs	77	101
Accumulated deferred income taxes	400	594
Income taxes receivable, non-current	53	11
Other deferred charges and assets — affiliated	6	13
Other deferred charges and assets	455	615
Total deferred charges and other assets	991	1,334
Total Assets	14,648	15,169
Current Liabilities:
Securities due within one year	864	560
Notes payable	120	209
Accounts payable —
Affiliated	93	88
Other	84	278
Accrued taxes —
Accrued income taxes	101	148
Other accrued taxes	30	7
Accrued interest	36	36
Acquisitions payable	0	461
Contingent consideration	15	46
Other current liabilities	58	70
Total current liabilities	1,401	1,903
Long-term Debt	4,946	5,068
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	191	152
Accumulated deferred ITCs	1,900	1,839
Asset retirement obligations, deferred	76	64
Other deferred credits and liabilities	232	304
Total deferred credits and other liabilities	2,399	2,359
Total Liabilities	8,746	9,330
Redeemable Noncontrolling Interests	59	164
Common Stockholders' Equity:
Par value	0	0
Paid-in capital	3,661	3,671
Retained earnings (accumulated deficit)	762	724
Accumulated other comprehensive income (loss)	25	35
Total Common Stockholders' Equity	4,448	4,430
Noncontrolling interests	1,395	1,245
Total Stockholders' Equity	5,843	5,675
Total Liabilities and Stockholders' Equity	14,648	15,169
SOUTHERN Co GAS
Current Assets:
Cash and cash equivalents	21	19
Receivables —
Customer accounts receivable	221	364
Energy marketing receivables	427	623
Unbilled revenues	61	239
Other accounts and notes receivable	61	76
Accumulated provision for uncollectible accounts	(26)	(27)
Materials and supplies	24	26
Natural gas for sale	631	631
Prepaid expenses	103	80
Assets from risk management activities, net of collateral	103	128
Other regulatory assets, current	96	81
Other current assets	25	10
Total current assets	1,747	2,250
Property, Plant, and Equipment:
In service	15,383	14,508
Less: Accumulated depreciation	4,567	4,439
Plant in service, net of depreciation	10,816	10,069
Construction work in progress	596	496
Total property, plant, and equipment	11,412	10,565
Other Property and Investments:
Goodwill	5,967	5,967
Equity investments in unconsolidated subsidiaries	1,609	1,541
Other intangible assets, net of amortization	300	366
Miscellaneous property and investments	21	21
Total other property and investments	7,897	7,895
Deferred Charges and Other Assets:
Other regulatory assets, deferred	944	973
Other deferred charges and assets	190	170
Total deferred charges and other assets	1,134	1,143
Total Assets	22,190	21,853
Current Liabilities:
Securities due within one year	0	22
Notes payable	934	1,257
Energy marketing trade payables	451	597
Accounts payable —
Accounts payable	368	348
Customer deposits	137	153
Accrued taxes —
Accrued income taxes	0	26
Other accrued taxes	70	68
Accrued interest	66	48
Accrued compensation	46	58
Liabilities from risk management activities, net of collateral	28	62
Other regulatory liabilities, current	126	102
Accrued environmental remediation, current	54	69
Other current liabilities	112	108
Total current liabilities	2,392	2,918
Long-term Debt	5,862	5,259
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	2,214	1,975
Employee benefit obligations	431	441
Accrued environmental remediation	345	357
Other cost of removal obligations	1,656	1,616
Other regulatory liabilities, deferred	35	51
Other deferred credits and liabilities	88	127
Total deferred credits and other liabilities	4,769	4,567
Total Liabilities	13,023	12,744
Common Stockholders' Equity:
Par value	0	0
Paid-in capital	9,185	9,095
Retained earnings (accumulated deficit)	(41)	(12)
Accumulated other comprehensive income (loss)	23	26
Total Stockholders' Equity	9,167	9,109
Total Liabilities and Stockholders' Equity	$ 22,190	$ 21,853

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Other intangible assets, accumulated amortization	$ 156	$ 62
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	991,000,000
Treasury shares at cost (in shares)	900,000	800,000
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	5,642,717
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, accumulated amortization	$ 41	$ 22
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, accumulated amortization	$ 100	$ 34
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, 2017

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, 2016 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, 2017 and 2016. 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.

Southern Company's financial statements reflect its investments in its subsidiaries, including Southern Company Gas as a result of the Merger, on a consolidated basis. Southern Company Gas' results of operations and cash flows for the three and nine months ended September 30, 2017 and the three months ended September 30, 2016, as well as its financial condition as of September 30, 2017 and December 31, 2016, are reflected within Southern Company's consolidated amounts in these accompanying notes herein. The equity method is used for entities in which Southern Company has significant influence but does not control, including Southern Company Gas' investment in SNG, and for variable interest entities where Southern Company has an equity investment but is not the primary beneficiary. See Note (I) under "Southern Company– Merger with Southern Company Gas" for additional information regarding the Merger.

Pursuant to the Merger, Southern Company pushed down the application of the acquisition method of accounting to the consolidated financial statements of Southern Company Gas such that the assets and liabilities are recorded at their respective fair values, and goodwill has been established for the excess of the purchase price over the fair value of net identifiable assets. Accordingly, the consolidated financial statements of Southern Company Gas for periods before and after July 1, 2016 (acquisition date) reflect different bases of accounting, and the financial positions and results of operations of those periods are not comparable. Throughout Southern Company Gas' condensed consolidated financial statements and the accompanying notes herein, periods prior to July 1, 2016 are identified as "predecessor," while periods after the acquisition date are identified as "successor."

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 Issued 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.

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. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While the registrants expect most of their revenue to be included in the scope of ASC 606, they have not fully completed the evaluation of all revenue arrangements. The majority of Southern Company's, the traditional electric operating companies', and Southern Company Gas' revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined contractual term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements. The majority of Southern Power's revenues includes longer-term PPAs for generation capacity and energy. The registrants expect the adoption of ASC 606 will not result in a significant shift from the current timing of revenue recognition for such transactions.

The registrants' ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the registrants' financial statements.In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company, the traditional electric operating companies, and Southern Company Gas expect CIAC to be out of the scope of ASC 606.

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The registrants intend to use the modified retrospective method of adoption effective January 1, 2018. The registrants have also elected to utilize practical expedients which allow them to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in the registrants' financial statements, the registrants will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.

On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017. Southern Company and Southern Company Gas are evaluating the standard and expect to early adopt ASU 2017-04 effective January 1, 2018.

On March 10, 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 income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's, the traditional electric operating companies', and Southern Company Gas' operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Southern Company's, the traditional electric operating companies', or Southern Company Gas' financial statements.

On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. 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 and interim periods within those fiscal years, with early adoption permitted. The registrants are evaluating the standard and expect to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on the registrants' financial statements.

Affiliate Transactions

Prior to the completion of Southern Company Gas' acquisition of its 50% equity interest in SNG, SCS (as agent for Alabama Power, Georgia Power, and Southern Power) and Southern Company Gas had entered into long-term interstate natural gas transportation agreements with SNG. The interstate transportation service provided to Alabama Power, Georgia Power, Southern Power, and Southern Company Gas by SNG pursuant to these agreements is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the nine months ended September 30, 2017, transportation costs under these agreements for Alabama Power, Georgia Power, Southern Power, and Southern Company Gas were approximately $8 million, $77 million, $19 million, and $24 million, respectively. For the period subsequent to Southern Company Gas' investment in SNG through September 30, 2016, transportation costs under these agreements for Alabama Power, Georgia Power, Southern Power, and Southern Company Gas were approximately $1 million, $8 million, $2 million, and $4 million, respectively.

SCS, as agent for Georgia Power and Southern Power, has agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. For the nine months ended September 30, 2017, natural gas purchases made by Georgia Power and Southern Power from Southern Company Gas' subsidiaries were approximately $18 million and $94 million, respectively. For the period subsequent to Southern Company's acquisition of Southern Company Gas through September 30, 2016, natural gas purchases made by Georgia Power and Southern Power from Southern Company Gas' subsidiaries were approximately $7 million and $2 million, respectively.

Goodwill and Other Intangible Assets

At September 30, 2017 and December 31, 2016, goodwill was as follows:

	Goodwill
	At September 30, 2017		At December 31, 2016
	(in millions)
Southern Company	$	6,267	$	6,251
Southern Power	$	2	$	2
Southern Company Gas
Gas distribution operations	$	4,702	$	4,702
Gas marketing services	1,265		1,265
Southern Company Gas total	$	5,967	$	5,967

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, 2017							At December 31, 2016
	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	$	288	$	(70	)	$	218	$	268	$	(32	)	$	236
Trade names	159		(15		)	144		158		(5		)	153
Storage and transportation contracts	64		(27		)	37		64		(2		)	62
PPA fair value adjustments	456		(41		)	415		456		(22		)	434
Other	16		(3		)	13		11		(1		)	10
Total other intangible assets subject to amortization	$	983	$	(156	)	$	827	$	957	$	(62	)	$	895
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	$	75	$	—		$	75	$	75	$	—		$	75
Total other intangible assets	$	1,058	$	(156	)	$	902	$	1,032	$	(62	)	$	970
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	456	$	(41	)	$	415	$	456	$	(22	)	$	434
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	221	$	(65	)	$	156	$	221	$	(30	)	$	191
Trade names	115		(8		)	107		115		(2		)	113
Wholesale gas services
Storage and transportation contracts	64		(27		)	37		64		(2		)	62
Total other intangible assets subject to amortization	$	400	$	(100	)	$	300	$	400	$	(34	)	$	366

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Nine Months Ended
	September 30, 2017
	(in millions)
Southern Company	$	29	$	94
Southern Power	$	6	$	19
Southern Company Gas	$	20	$	66

See Note 12 to the financial statements of Southern Company under "Southern Power" and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information regarding Southern Power's PPA fair value adjustments related to its business acquisitions. Also see Note (I) under "Southern Company– Acquisition of PowerSecure" and " –Merger with Southern Company Gas" for additional information.

Property Damage Reserve

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.

Gulf Power's cost of repairing damages from major storms and other uninsured property damages, including uninsured damages to transmission and distribution facilities, generation facilities, and other property is charged to Gulf Power's property damage reserve. In accordance with a settlement agreement approved by the Florida PSC on April 4, 2017 (2017 Rate Case Settlement Agreement), Gulf Power suspended further property damage reserve accruals effective April 2017. Gulf Power may make discretionary accruals and is required to resume accruals of $3.5 million annually if the reserve balance falls below zero. In addition, Gulf Power may initiate a storm surcharge to recover costs associated with any tropical systems named by the National Hurricane Center or other catastrophic storm events that reduce the property damage reserve in the aggregate by approximately $31 million (75% of the April 1, 2017 balance) or more. The storm surcharge would begin, on an interim basis, 60 days following the filing of a cost recovery petition, would be limited to $4.00/month for a 1,000 KWH residential customer unless Gulf Power incurs in excess of $100 million in qualified storm recovery costs in a calendar year, and would replenish the property damage reserve to approximately $40 million. As of September 30, 2017, Gulf Power's property damage reserve totaled approximately $39 million. See Note (B) under "Regulatory Matters–Gulf Power– Retail Base Rate Cases" for additional details regarding the 2017 Rate Case Settlement Agreement.

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, 2017. 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.

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Contingencies and Regulatory Matters

9 Months Ended

Sep. 30, 2017

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 regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, 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

On January 20, 2017, a purported 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 IGCC 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. On June 12, 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. On July 27, 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition on September 11, 2017.

On February 27, 2017, Jean Vineyard filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District 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 defendants caused Southern Company to make false or misleading statements regarding the Kemper IGCC cost and schedule. Further, the complaint alleges that the defendants were unjustly enriched and caused the waste of corporate assets. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On March 27, 2017, the court deferred this lawsuit until 30 days after certain further action in the purported securities class action complaint discussed above.

On May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia and, on May 31, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. Each 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 IGCC. Each complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper IGCC schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. Each 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. Each plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia and the court deferred the consolidated case until 30 days after certain further action in the purported securities class action complaint discussed above.

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.

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 November 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court for further proceedings. Georgia Power filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted on August 28, 2017. A decision from the Georgia Supreme Court is not expected until 2018. Georgia Power believes the plaintiffs' claims have no merit and intends to vigorously defend itself in this matter. The ultimate outcome of this matter cannot be determined at this time.

Southern Power

During 2015, Southern Power indirectly acquired a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas, which was under construction by Recurrent Energy, LLC and was subsequently placed in service in November 2016. Prior to placing the facility in service, certain solar panels were damaged during installation. While the facility currently is generating energy consistent with operational expectations and PPA obligations, Southern Power is pursuing remedies under its insurance policies and other contracts to repair or replace these solar panels. In connection therewith, Southern Power is withholding payments of approximately $26 million from the construction contractor, who has placed a lien on the Roserock facility for the same amount. The amounts withheld are included in other accounts and notes payable and other current liabilities on Southern Company's consolidated balance sheets and other accounts payable and other current liabilities on Southern Power's consolidated balance sheets. On May 18, 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, against X.L. America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from a hail storm and certain installation practices by the construction contractor, McCarthy Building Companies, Inc. (McCarthy). On May 19, 2017, Roserock filed a separate lawsuit against McCarthy in the state district court in Travis County, Texas alleging breach of contract and breach of warranty for the damages sustained at the Roserock facility, which has since been moved to the U.S. District Court for the Western District of Texas. On May 22, 2017, McCarthy filed a counter lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things, breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. 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 Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. were defendants in a putative class action initially filed in 2011 in the state court in Cook County, Illinois. The plaintiffs purported to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously alleged that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs sought, on behalf of the classes they purported to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On February 8, 2017, the judge denied the plaintiffs' motion for class certification and Southern Company Gas' motion for summary judgment. On March 7, 2017, the parties reached a settlement, which was finalized and effective on April 3, 2017. The settlement did not have a material impact on Southern Company's or Southern Company Gas' financial statements.

Environmental Matters

Environmental Remediation

The Southern Company system must comply with environmental laws and regulations that cover 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, New Jersey, Georgia, and Florida have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.

Georgia Power's environmental remediation liability was $26 million and $17 million as of September 30, 2017 and December 31, 2016, 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 $53 million and $44 million as of September 30, 2017 and December 31, 2016, 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. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.

Southern Company Gas' environmental remediation liability was $399 million and $426 million as of September 30, 2017 and December 31, 2016, respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities, with the exception of one site representing $5 million of the total accrued remediation costs.

The final outcome of these matters cannot be determined at this time. However, 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.

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 (LDNR). 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, 2017, the facility's property, plant, and equipment had a net book value of $111 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including the results of ongoing third-party technical engineering reviews, testing, and compliance with an order from the LDNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining a core sample to determine the composition of the sheath surrounding the edge of the salt dome. 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.

Nuclear Fuel Disposal Costs

See Note 3 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Fuel Disposal Costs" in Item 8 of the Form 10-K for additional information regarding legal remedies pursued by Alabama Power and Georgia Power against the U.S. government for its partial breach of contract relating to the disposal of spent nuclear fuel and high level radioactive waste generated at each company's nuclear plants.

On October 10, 2017, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government in the Court of Federal Claims for the costs of continuing to store spent nuclear fuel at Plant Farley, Plant Hatch, and Plant Vogtle Units 1 and 2 for the period from January 1, 2015 through December 31, 2017. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of September 30, 2017 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.

FERC Matters

Municipal and Rural Associations Tariff

See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding a settlement agreement entered into by Mississippi Power regarding the establishment of a regulatory asset for Kemper IGCC-related costs. See "Integrated Coal Gasification Combined Cycle" herein for information regarding the Kemper IGCC.

In March 2016, Mississippi Power reached a settlement agreement with its wholesale customers, which was subsequently approved by the FERC, for an increase in wholesale base revenues under the MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking through an order issued by the Mississippi PSC in December 2015 (In-Service Asset Rate Order). This regulatory treatment primarily includes (i) recovery of the Kemper IGCC assets currently operational and providing service to customers and other related costs, (ii) amortization of the Kemper IGCC-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper IGCC-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper IGCC CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC totaled approximately $22 million through the suspension of Kemper IGCC start-up activities.

See "Integrated Coal Gasification Combined Cycle" herein for additional information.

Fuel Cost Recovery

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At September 30, 2017, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $3 million compared to $13 million at December 31, 2016. Over-recovered wholesale MB fuel costs included in the balance sheets were immaterial at September 30, 2017 and December 31, 2016.

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 Note 3 to the financial statements of Southern Company and Mississippi Power under "FERC Matters – Market-Based Rate Authority" and Note 3 to the financial statements of Alabama Power, Georgia Power, Gulf Power, and Southern Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.

On May 17, 2017, the FERC accepted the traditional electric operating companies' and Southern Power's compliance filing accepting the terms of the FERC's February 2, 2017 order regarding an amendment by the traditional electric operating companies and Southern Power to their market-based rate tariff. While the FERC's order references the traditional electric operating companies' and Southern Power's market power proceeding related to their 2014 triennial updated market power analysis, that proceeding remains a separate, ongoing matter.

On October 25, 2017, the FERC issued an order in response to the traditional electric operating companies' and Southern Power's June 30, 2017 triennial updated market power analysis. The FERC directed the traditional electric operating companies and Southern Power to show cause within 60 days why market-based rate authority should not be revoked in certain areas adjacent to the area presently under mitigation in accordance with the February 2, 2017 order, or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power expect to make a filing within the specified 60 days responding to the FERC's order.

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

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, 2017		December 31, 2016
		(in millions)
Rate CNP Compliance	Deferred over recovered regulatory clause revenues	$	9	$	—
Rate CNP Compliance(*)	Deferred under recovered regulatory clause revenues	—		9
Rate CNP PPA	Deferred under recovered regulatory clause revenues	17		142
Retail Energy Cost Recovery(*)	Other regulatory liabilities, current	—		76
Natural Disaster Reserve	Other regulatory liabilities, deferred	51		69

(*) In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its under recovered balance for Rate CNP Compliance and $11 million of its under recovered balance for Retail Energy Cost Recovery to a deferred regulatory asset account.

Georgia Power

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.

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 the construction 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 "Regulatory Matters – Georgia Power – 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.

Integrated Resource Plan

See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Integrated Resource Plan" and "Retail Regulatory Matters – Integrated Resource Plan," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan.

On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at a future generation site in Stewart County, Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing of recovery for costs incurred of approximately $50 million will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.

As of September 30, 2017, Georgia Power's under recovered fuel balance totaled $100 million and is included in current assets and other deferred charges and assets on Southern Company's and Georgia Power's condensed balance sheets. As of December 31, 2016, Georgia Power's over recovered fuel balance totaled $84 million and is included in other current liabilities on Southern Company's and Georgia Power's condensed balance sheets.

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

Georgia Power is accruing$30 millionannually through December 31, 2019, as provided in the 2013 ARP, for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. During September 2017, Hurricane Irma caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of incremental restoration costs related to this hurricane is estimated to be approximately $150 million. As of September 30, 2017, Georgia Power had deferred approximately $145 million in a regulatory asset related to storm damage. As of September 30, 2017, the total balance in Georgia Power's regulatory asset related to storm damage was $360 million. Therate of storm damage cost recovery is expected to be adjusted as part of Georgia Power's next base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's or Georgia Power's financial statements.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.

Nuclear Construction

See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – 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, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, and the Contractor Settlement Agreement.

Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy

In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Vogtle 3 and 4 Agreement, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. Georgia Power's proportionate share of Plant Vogtle Units 3 and 4 is 45.7%.

The Vogtle 3 and 4 Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million (approximately $420 million based on Georgia Power's ownership interest). Under the Toshiba Guarantee, Toshiba guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed.

Under the terms of the Vogtle 3 and 4 Agreement, the EPC Contractor did not have the right to terminate the Vogtle 3 and 4 Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the Vogtle 3 and 4 Agreement was 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest).

On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. To provide for a continuation of work at Plant Vogtle Units 3 and 4, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the EPC Contractor (Interim Assessment Agreement), which the bankruptcy court approved on March 30, 2017.

The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement Georgia Power was obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided. The Interim Assessment Agreement, as amended, expired on July 27, 2017.

Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through September 30, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which $340 million had been paid or accrued as of September 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $176 million.

On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, which will reduce CWIP, beginning in October 2017 and continuing through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Vogtle Owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Vogtle Owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Vogtle Owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Vogtle Owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. On October 2, 2017, Georgia Power received the first installment of the Guarantee Obligations of $300 million from Toshiba, of which Georgia Power's proportionate share was $137 million. Georgia Power is considering potential options with respect to its right to future payments under the Guarantee Settlement Agreement and its claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to DOE consents and related approvals under the Loan Guarantee Agreement and related agreements.

On August 10, 2017, Toshiba released its financial results for the quarter ended June 30, 2017, which reflected a negative shareholders' equity balance of approximately $4.5 billion as of June 30, 2017. Toshiba previously announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's and Georgia Power's financial statements.

Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into a services agreement (Services Agreement), which was 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. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement. The Services Agreement, and the EPC Contractor's rejection of the Vogtle 3 and 4 Agreement, became effective upon approval by the DOE on July 27, 2017. The Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement (Bechtel Agreement) with Bechtel Power Corporation (Bechtel), whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4. Facility design and engineering remains the responsibility of the EPC Contractor under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a 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 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, 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 connection with the recommendation to continue with construction of Plant Vogtle Units 3 and 4 (described below), the Vogtle Owners agreed on a term sheet to amend the existing joint ownership agreements to provide for additional Vogtle Owner approval requirements. Under the 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 adverse events occur, including (i) the bankruptcy of Toshiba or a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) 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 because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report by more than $1 billion or extension of the project schedule contained in the seventeenth VCM report by more than one year. In addition, under the term sheet, 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 Services Agreement or agreements with the primary construction contractor or Southern Nuclear.

The term sheet also confirms 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.

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 nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. As of September 30, 2017, Georgia Power had recovered approximately $1.5 billion of financing costs. Georgia Power expects to file on November 1, 2017 to increase the NCCR tariff by approximately $90 million, effective January 1, 2018, pending Georgia PSC approval.

On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report will be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none of the amounts paid or to be paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified and approved capital costs will be deemed prudent provided they are incurred prior to December 31, 2019 and December 31, 2020 for Plant Vogtle Units 3 and 4, respectively; and (iv) (a) the in-service capital cost forecast will be adjusted to $5.680 billion (Revised Forecast), which includes a contingency of $240 million above Georgia Power's then current forecast of $5.440 billion, (b) capital costs incurred up to the Revised Forecast will be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, and (c) Georgia Power would have the burden to show that any capital costs above the Revised Forecast are reasonable and prudent. Under the terms of the Vogtle Cost Settlement Agreement, the certified in-service capital cost for purposes of calculating the NCCR tariff will remain at $4.418 billion. Construction capital costs above $4.418 billion will accrue AFUDC through the date each unit is placed in service. The ROE used to calculate the NCCR tariff was reduced from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016. For purposes of the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00% and the ROE on any amounts above $5.440 billion would be Georgia Power's average cost of long-term debt. If the Georgia PSC adjusts Georgia Power's ROE rate setting point in a rate case prior to Plant Vogtle Units 3 and 4 being placed into retail rate base, then the ROE for purposes of calculating both the NCCR tariff and AFUDC will likewise be 95 basis points lower than the revised ROE rate setting point. If Plant Vogtle Units 3 and 4 are not placed in service by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, or $8 million per month, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units are placed in service and (ii) the ROE used to calculate AFUDC will be Georgia Power's average cost of long-term debt.

The Georgia PSC has approved sixteen VCM reports covering the periods through December 31, 2016, including construction capital costs incurred, which through that date totaled $3.9 billion. Georgia Power filed its seventeenth VCM report, covering the period from January 1 through June 30, 2017, requesting approval of $542 million of construction capital costs incurred during that period, with the Georgia PSC on August 31, 2017.

In the seventeenth VCM report, Georgia Power recommended that construction of Plant Vogtle Units 3 and 4 be continued, with Southern Nuclear serving as project manager. Georgia Power believes that the most reasonable schedule for completing Plant Vogtle Units 3 and 4 is by November 2021 for Unit 3 and by November 2022 for Unit 4. Georgia Power's recommendation to go forward with completion of Vogtle Units 3 and 4 is based on the following assumptions about the regulatory treatment of this recommendation, if the recommendation to go forward is adopted by the Georgia PSC: (i) that pursuant to Georgia law, the Georgia PSC in the seventeenth VCM proceeding approves the new cost and schedule forecast and finds that it is a reasonable basis for going forward, and that if the Georgia PSC disapproves all or part of the proposed cost and schedule revisions, Georgia Power may cancel Plant Vogtle Units 3 and 4 and recover its actual investment in Plant Vogtle Units 3 and 4; (ii) that the Vogtle Cost Settlement Agreement remains in full force and effect, including Georgia Power retaining the burden of proving all capital costs above $5.680 billion were prudent; (iii) that while the Georgia PSC will make no prudence finding in the seventeenth VCM proceeding, nor will the certified amount be amended consistent with the Vogtle Cost Settlement Agreement, the Georgia PSC recognizes that the certified amount is not a cap, and all costs that are approved and presumed or shown to be prudently incurred will be recoverable by Georgia Power; (iv) that Georgia Power is not a guarantor of the Toshiba Guarantee, and the failure of Toshiba to pay the Toshiba Guarantee, the failure of the U.S. Congress to extend the PTCs for Plant Vogtle Units 3 and 4, or the failure of the DOE to extend the Loan Guarantee Agreement with Georgia Power to reflect the increased capital amounts, will not reduce the amount of investment Georgia Power is otherwise allowed to collect; and (v) that as conditions change and assumptions are either proven or disproven, Georgia Power and the Georgia PSC may reconsider the decision to go forward. The Georgia PSC is expected to make a decision on these matters by February 6, 2018.

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

Revised Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 is as follows:

	(in billions)
Estimated cost to complete	$	4.2
CWIP as of September 30, 2017	4.6
Guarantee Obligations	(1.7		)
Estimated capital costs	$	7.1
Vogtle Cost Settlement Agreement Revised Forecast	(5.7		)
Estimated net additional capital costs	$	1.4

Georgia Power's estimated financing costs during the construction period total approximately $3.4 billion, of which approximately $1.5 billion had been incurred through September 30, 2017.

Georgia Power's cancellation cost estimate results indicate that its proportionate share of the estimated costs to cancel both units is approximately $350 million. As a result, as of September 30, 2017, total estimated costs subject to evaluation by Georgia Power and the Georgia PSC in the event of a cancellation decision are as follows:

	Cancellation Cost Estimate
	(in billions)
CWIP as of September 30, 2017	$	4.6
Financing costs collected, net of tax	1.5
Cancellation costs(*)	0.4
Guarantee Obligations	(1.7		)
Estimated net cancellation cost	$	4.8

(*) The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site.

The Guarantee Obligations continue to exist in the event of cancellation. In addition, under Georgia law, prudently incurred costs related to certificated projects cancelled by the Georgia PSC are allowed recovery, including carrying costs, in future retail rates. Georgia Power will continue working with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4, including, but not limited to, the status of construction and rate recovery.

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

Other Matters

As of September 30, 2017, 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. On September 28, 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. 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 (E) under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

The IRS has allocated PTCs to Plant Vogtle Units 3 and 4 which require that the applicable unit be placed in service prior to 2021. The net present value of Georgia Power's PTCs is estimated at approximately $400 million per unit.

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 while construction proceeds. 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 and the related approvals by the NRC, may arise while construction proceeds, 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.

While construction continues, the risk remains that challenges with management of contractors, subcontractors, and vendors, labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost.

The ultimate outcome of these matters 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.

Retail Base Rate Cases

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.

In 2013, the Florida PSC approved a settlement agreement that authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction could not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. For 2014 and 2015, Gulf Power recognized reductions in depreciation of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016. Through June 2017, Gulf Power recognized the remaining allowable reductions in depreciation totaling $34.0 million.

On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and three intervenors with respect to Gulf Power's request to increase retail base rates. Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power increased rates effective with the first billing cycle in July 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consisted of a $62.0 million increase in annual base revenues less an annual equivalent credit of approximately $7.7 million for 2017 for certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause. In addition, Gulf Power continued its authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%), is deemed to have an equity ratio of 52.5% for all retail regulatory purposes, and implemented new dismantlement accruals effective July 1, 2017. Gulf Power will also begin amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018 and will implement new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.

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. Gulf Power has four regulatory clauses which are approved by the Florida PSC. The balance of each regulatory clause recovery on the balance sheet follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2017		December 31, 2016
		(in millions)
Fuel Cost Recovery	Under recovered regulatory clause revenues	$	13	$	—
Fuel Cost Recovery	Other regulatory liabilities, current	—		15
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	1		—
Environmental Cost Recovery	Other regulatory liabilities, current	1		—
Environmental Cost Recovery	Under recovered regulatory clause revenues	—		13
Energy Conservation Cost Recovery	Under recovered regulatory clause revenues	1		4

As discussed previously, the 2017 Rate Case Settlement Agreement resolved the remaining issues related to Gulf Power's inclusion of certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 in the environmental cost recovery clause and no adjustment to the environmental cost recovery clause rate approved by the Florida PSC in November 2016 was made.

On October 25, 2017, 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 2018. The net effect of the approved changes is a $63 million increase in annual revenues effective in January 2018, the majority of which will be offset by related expense increases.

Mississippi Power

Performance Evaluation Plan

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's base rates.

On March 15, 2017, Mississippi Power submitted its annual PEP lookback filing for 2016, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time.

Energy Efficiency

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Energy Efficiency" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's energy efficiency programs.

On July 6, 2017, the Mississippi PSC issued an order approving Mississippi Power's Energy Efficiency Cost Rider compliance filing, which increased annual retail revenues by approximately $2 million effective with the first billing cycle for August 2017.

Environmental Compliance Overview Plan

On May 4, 2017, the Mississippi PSC approved Mississippi Power's ECO Plan filing for 2017, which requested the maximum 2% annual increase in revenues, approximately $18 million, primarily related to the Plant Daniel Units 1 and 2 scrubbers placed in service in 2015. The rates became effective with the first billing cycle for June 2017. Approximately $26 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2018 filing.

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 Form 10-K for additional information regarding Mississippi Power's retail fuel cost recovery.

At September 30, 2017, the amount of over-recovered retail fuel costs included on Mississippi Power's condensed balance sheet was $2 million compared to $37 million at December 31, 2016.

Ad Valorem Tax Adjustment

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's ad valorem tax adjustments.

On July 6, 2017, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2017, which included an annual rate increase of 0.85%, or $8 million in annual retail revenues, primarily due to increased assessments.

Southern Company Gas

Riders

Nicor Gas has established a variable tax cost adjustment rider, which was approved by the Illinois Commission effective July 16, 2017. This rider provides for recovery of the invested capital tax imposed on Nicor Gas through an annual true-up and reconciliation mechanism based on amounts approved in prior rate cases. Accordingly, this rider will not have a significant effect on Southern Company Gas' net income.

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

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

Settled Base Rate Cases

On February 21, 2017, the Georgia PSC approved the Georgia Rate Adjustment Mechanism (GRAM) and a $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, based on the previously approved ROE of 10.75% and does not collect revenue through special riders and surcharges. Various infrastructure programs previously authorized by the Georgia PSC under Atlanta Gas Light's STRIDE program, which include the Integrated Vintage Plastic Replacement Program and Integrated System Reinforcement Program, will continue under GRAM and the recovery of and return on the infrastructure program investments will be included in annual base rate adjustments. The Georgia PSC will review Atlanta Gas Light's performance annually under GRAM.

Pursuant to the GRAM approval, Atlanta Gas Light and the staff of the Georgia PSC agreed to a variation to the Integrated Customer Growth Program that was formerly part of Atlanta Gas Light's STRIDE program. As a result, a new tariff was created, effective October 10, 2017, to provide $15 million annually for Atlanta Gas Light to commit to strategic economic development projects.

Beginning with the next rate adjustment in June 2018, Atlanta Gas Light's recovery of the previously unrecovered Pipeline Replacement Program revenue through 2014, as well as the mitigation costs associated with the Pipeline Replacement Program that were not previously included in its rates, will also be included in GRAM. In connection with the GRAM approval, the last monthly Pipeline Replacement Program surcharge increase became effective March 1, 2017.

In September 2016, Elizabethtown Gas filed a general base rate case with the New Jersey BPU requesting a $19 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year ending March 31, 2017 and a ROE of 10.25%. On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on a ROE of 9.6%. Also included in the settlement was a new composite depreciation rate that is expected to result in a $3 million annual reduction of depreciation. See Note (I) under "Southern Company Gas" for information on the proposed sale of Elizabethtown Gas.

Pending Base Rate Cases

On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase in December 2017, after which rate adjustments will be effective.

On March 31, 2017, Virginia Natural Gas filed a general base rate case with the Virginia Commission requesting a $44 million increase in annual base rate revenues. The requested increase was based on a projected 12-month test year beginning September 1, 2017 and a ROE of 10.25%. The requested increase included $13 million related to the recovery of investments under the Steps to Advance Virginia's Energy (SAVE) program. On October 3, 2017, Virginia Natural Gas entered into a proposed stipulation with the Staff of the Virginia Commission, the Office of the Attorney General, Division of Consumer Counsel, and the Virginia Industrial Gas Users' Association resolving all related issues. The proposed stipulation includes a $34 million increase in annual base rate revenues, including $13 million related to the recovery of investments under the SAVE program. An authorized ROE range of 9.0% to 10.0% with a midpoint of 9.5% will be used to determine the revenue requirement in any filing, other than for a change in base rates. The Virginia Commission is expected to rule on the proposed stipulation in the fourth quarter 2017. Rate adjustments based on the proposed stipulation became effective September 1, 2017, subject to refund.

On October 23, 2017, Florida City Gas filed a general base rate case with the Florida PSC requesting a $19 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 11.25%. The requested increase includes $3 million related to the recovery of investments under the Safety, Access, and Facility Enhancement (SAFE) program. Additionally, Florida City Gas requested interim rates of $5 million to be effective in January 2018, subject to refund. The Florida PSC is expected to rule on the requested increase in mid-2018.

The ultimate outcome of these pending base rate cases 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 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.

Nicor Gas

In 2014, the Illinois Commission approved Nicor Gas' nine-year regulatory infrastructure program, Investing in Illinois. Under this program, Nicor Gas placed into service $178 million of qualifying assets during the first nine months of 2017.

Atlanta Gas Light

Atlanta Gas Light's STRIDE program, which started in 2009, consists of three individual programs that update and expand gas distribution systems and LNG facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, Atlanta Gas Light invested $127 million during the first nine months of 2017. The recovery of and return on current and future capital investments under the STRIDE program are included in the annual base rate revenue adjustment under GRAM.

In August 2016, Atlanta Gas Light filed a petition with the Georgia PSC for approval of a four-year extension of its Integrated System Reinforcement Program (i-SRP) seeking approval to invest an additional $177 million to improve and upgrade its core gas distribution system in years 2017 through 2020. Subsequently, the proposed capital investments associated with the extension of i-SRP were included in the 2017 annual base rate revenue under GRAM approved by the Georgia PSC on February 21, 2017.

See "Base Rate Cases" herein for additional information.

Elizabethtown Gas

In 2013, the New Jersey BPU approved the extension of Elizabethtown Gas' Aging Infrastructure Replacement program, under which Elizabethtown Gas invested $16 million during the first nine months of 2017. Effective July 1, 2017, investments under this program are being recovered through base rate revenues.

Virginia Natural Gas

In March 2016, the Virginia Commission approved an extension to the SAVE program, under which Virginia Natural Gas invested $21 million during the first nine months of 2017.

Florida City Gas

The Florida PSC approved Florida City Gas' SAFE program in 2015. Under the program, Florida City Gas invested $9 million during the first nine months of 2017.

Integrated Coal Gasification Combined Cycle

See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.

Kemper IGCC Overview

The Kemper IGCC was designed to utilize IGCC technology with an expected output capacity of 582 MWs and to be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed approximately 61 miles of CO₂ pipeline infrastructure for the transport of captured CO₂ for use in enhanced oil recovery.

Kemper IGCC Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014.

The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. During testing, the plant produced and captured CO₂, and produced sulfuric acid and ammonia, each of acceptable quality under the related off-take agreements. However, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a sustained basis. In May 2017, after achieving these milestones, Mississippi Power determined that a critical system component, the syngas coolers, would need replacement sooner than originally planned, which would require significant lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of operating and maintaining the facility during the first five full years of operations has increased significantly since certification.

On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC (Kemper IGCC Settlement Docket). On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014.

Mississippi Power's Kemper IGCC 2010 project estimate totaled $2.97 billion, which included capped costs of $2.4 billion. At the time of project suspension in June 2017, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in additional grants from the DOE for the Kemper IGCC (Additional DOE Grants).

Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap for the Kemper IGCC of $196 million ($121 million after tax) in the second quarter through May 31, 2017 and a total of $305 million ($188 million after tax) for year-to-date through May 31, 2017. In the aggregate, Mississippi Power incurred charges of $3.07 billion ($1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through May 31, 2017. The May 31, 2017 cost estimate included approximately $175 million of estimated costs to be incurred beyond the then-estimated in-service date of June 30, 2017 that were expected to be subject to the $2.88 billion cost cap.

While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred. In the aggregate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC totaling $34 million ($21 million after tax) for the third quarter 2017 and $3.2 billion ($2.2 billion after tax) for the nine months ended September 30, 2017.

As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC. The Kemper combined cycle balances as presented in the condensed balance sheet at September 30, 2017 include $1.1 billion in property, plant, and equipment, net of $80 million in accumulated depreciation; $15 million in materials and supplies; $10 million in other deferred charges and assets; and $113 million in regulatory assets, net of accumulated amortization of $63 million, of which $21 million is included in other regulatory assets, current and $92 million in other regulatory assets, deferred.

Rate Recovery of Kemper IGCC Costs

Given the variety of potential scenarios and the uncertainty of the outcome of future regulatory proceedings with the Mississippi PSC (and any subsequent related legal challenges), the ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, cannot now be determined but could result in further material charges that could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity.

Kemper IGCC Settlement Docket

On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility.

On June 28, 2017, Mississippi Power notified the Mississippi PSC that it would begin a process to suspend operations and start-up activities on the gasifier portion of the Kemper IGCC, given the uncertainty as to the future of the gasifier portion of the Kemper IGCC. Mississippi Power expects to continue to operate the combined cycle portion of the Kemper IGCC as it has done since August 2014. At the time of project suspension, the total cost estimate for the Kemper IGCC was approximately $7.38 billion, including approximately $5.95 billion of costs subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.

Mississippi Power reached and filed a settlement agreement on August 21, 2017 with certain parties (not including the Mississippi Public Utilities Staff (MPUS)), which it believes met the conditions of the Kemper Settlement Order. The settlement agreement provides for an annual revenue requirement of $126 million for Kemper IGCC-related costs, which would (i) be effective January 1, 2018, (ii) represent no rate increase for customers, and (iii) include no recovery for the costs associated with the gasifier portion of the Kemper IGCC in 2018 or at any future date. In addition, under the settlement agreement, the CPCN for the Kemper IGCC would be modified to limit the Kemper County energy facility to natural gas combined cycle operation and Mississippi Power would, in the future, file a reserve margin plan with the Mississippi PSC. The Mississippi PSC issued a scheduling order, as amended on October 5, 2017, noting Mississippi Power and the MPUS had failed to reach a joint stipulation and ordering a full hearing. The Mississippi PSC is expected to rule on an order resolving this matter in January 2018.

While the ultimate disposition of the gasification portions of the Kemper IGCC remains subject to the Mississippi PSC's jurisdiction, including the potential resolution of the matters addressed in the Kemper IGCC Settlement Docket, given the Mississippi PSC's stated intent regarding no further rate increase for the Kemper County energy facility, cost recovery of the gasification portions is no longer probable; therefore, Mississippi Power recorded an additional charge to income in June 2017 of $2.8 billion ($2.0 billion after tax), which includes estimated costs associated with the gasification portions of the plant and lignite mine. In the third quarter 2017, Mississippi Power recorded an additional charge of $34 million ($21 million after tax) for ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the Mississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through September 30, 2017. Any extension of the suspension period beyond December 31, 2017 is currently estimated to result in additional suspension costs of approximately $5 million per month. In the event the gasification portions of the project are ultimately canceled, additional pre-tax costs, which include mine and Kemper IGCC plant closure costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred.

As of September 30, 2017, Mississippi Power has recorded a total of approximately $1.3 billion in costs associated with the combined cycle portion of the Kemper IGCC including transmission and related regulatory assets, of which $0.8 billion is included in retail and wholesale rates. The $0.5 billion not included in current rates includes costs in excess of the original 2010 estimate for the combined cycle portion of the facility, as well as the 15% that was previously contracted to Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.

Prudence

On August 17, 2016, the Mississippi PSC issued an order establishing a discovery docket to manage all filings related to the prudence of the Kemper IGCC. On October 3, 2016, Mississippi Power made a required compliance filing, which included a review and explanation of differences between the Kemper IGCC project estimate set forth in the 2010 CPCN proceedings and the most recent Kemper IGCC project estimate, as well as comparisons of current cost estimates and current expected plant operational parameters to the estimates presented in the 2010 CPCN proceedings for the first five years after the Kemper IGCC was to be placed in service. Compared to amounts presented in the 2010 CPCN proceedings, operations and maintenance expenses have increased an average of $105 million annually and maintenance capital has increased an average of $44 million annually for the first full five years of operations for the Kemper IGCC. Additionally, while the current estimated operational availability estimates reflect ultimate results similar to those presented in the 2010 CPCN proceedings, the ramp up period for the current estimates reflects a lower starting point and a slower escalation rate. On November 17, 2016, Mississippi Power submitted a supplemental filing to the October 3, 2016 compliance filing to present revised non-fuel operations and maintenance expense projections for the first year after the Kemper IGCC was to be placed in service. This supplemental filing included approximately $68 million in additional estimated operations and maintenance costs expected to be required to support the operations of the Kemper IGCC during that period.

Mississippi Power responded to numerous requests for information from interested parties in the discovery docket, which is now complete. Mississippi Power expects the Mississippi PSC to utilize this information in connection with the ultimate resolution of Kemper IGCC cost recovery.

Economic Viability Analysis

In the fourth quarter 2016, as a part of its Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected. As a result of the updated long-term natural gas forecast, as well as the revised operating expense projections reflected in the discovery docket filings discussed above, on February 21, 2017, Mississippi Power filed an updated project economic viability analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order confirming authorization of the Kemper IGCC. The project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis.

Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.

2015 Rate Case

On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full a stipulation entered into between Mississippi Power and the MPUS regarding the Kemper IGCC assets that were commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by Cooperative Energy but reserved Mississippi Power's right to seek recovery in a future proceeding. See "Termination of Proposed Sale of Undivided Interest" herein for additional information.

In 2011, the Mississippi PSC authorized Mississippi Power to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date. In connection with the implementation of the In-Service Asset Order and wholesale rates, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of September 30, 2017, the balance associated with these regulatory assets was $113 million, of which $21 million is included in current assets. See "FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.

The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, for the May 31, 2016 and 2017 calculations. At September 30, 2017, Mississippi Power's related regulatory liability totaled approximately $10 million.

As required by the In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the regulatory assets reviewed and determined prudent in the In-Service Asset Order in a manner that would not change customer rates or annual revenues. On June 28, 2017, the Mississippi PSC suspended this filing. On July 6, 2017, the Mississippi PSC issued an order requiring Mississippi Power to establish a regulatory liability account to maintain current rates related to the Kemper IGCC following the July 2017 completion of the amortization period for certain regulatory assets approved in the In-Service Asset Rate Order that would allow for subsequent refund if the Mississippi PSC deems the rates unjust and unreasonable. At September 30, 2017, the related regulatory liability totaled $7 million.

2013 MPSC Rate Order

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (construction cost increase demonstrated to produce efficiencies that result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions), but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC was placed in service, based on a mirror CWIP methodology (Mirror CWIP rate).

On February 12, 2015, the Mississippi Supreme Court reversed the 2013 MPSC Rate Order and, on July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million previously collected, along with associated carrying costs of $29 million.

Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continued to record AFUDC on the Kemper IGCC. Between the original May 2014 estimated in-service date and the June 2017 project suspension date, Mississippi Power recorded $494 million of AFUDC on the Kemper IGCC subject to the $2.88 billion cost cap and Cost Cap Exception amounts, of which $460 million related to the gasification portions of the Kemper IGCC.

Mississippi Power expects the Mississippi PSC to address this matter in connection with the Kemper IGCC Settlement Docket.

Lignite Mine and CO₂ Pipeline Facilities

In conjunction with the Kemper IGCC, Mississippi Power owns the lignite mine and equipment and mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013.

In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is responsible for the mining operations through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. During the suspension period, these costs are approximately $2 million per month and are being recognized in income as incurred. See Note 1 to the financial statements of Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.

In addition, Mississippi Power constructed the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery. Mississippi Power entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC (Treetop), pursuant to which Denbury would purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop would purchase 30% of the CO₂ captured from the Kemper IGCC. On June 3, 2016, Mississippi Power cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury's agreement to purchase 100% of the CO₂ captured from the Kemper IGCC and an initial contract term of 16 years. Denbury has the right to terminate the contract at any time because Mississippi Power did not place the Kemper IGCC in service by July 1, 2017.

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

Termination of Proposed Sale of Undivided Interest

In 2010 and as amended in 2012, Mississippi Power and Cooperative Energy (formerly known as SMEPA) entered into an agreement whereby Cooperative Energy agreed to purchase a 15% undivided interest in the Kemper IGCC. On May 20, 2015, Cooperative Energy notified Mississippi Power of its termination of the agreement. Mississippi Power previously received a total of $275 million of deposits from Cooperative Energy that were required to be returned to Cooperative Energy with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to Cooperative Energy. Subsequently, Mississippi Power issued a promissory note in the aggregate principal amount of approximately $301 million to Southern Company, which was repaid in June 2017.

Litigation

On April 26, 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 on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have 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 IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice of an appeal.

On June 9, 2016, Treetop, Greenleaf CO₂ Solutions, LLC (Greenleaf), Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO₂ contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS moved to compel arbitration pursuant to the terms of the CO₂ contract, which the court granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages.

Southern Company and Mississippi Power believe these legal challenges have no merit; however, an adverse outcome in these proceedings 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 these matters, and the ultimate outcome of these matters cannot be determined at this time.

Baseload Act

In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery or implement credits, refunds, or rebates to customers for costs incurred in connection with such cancelled generating plant.

Income Tax Matters

See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle – Bonus Depreciation," " – Investment Tax Credits," and " – Section 174 Research and Experimental Deduction" in Item 8 of the Form 10-K and Note (G) under "Section 174 Research and Experimental Deduction" for additional information on bonus depreciation, investment tax credits, and the Section 174 research and experimental deduction.

Bonus Depreciation

All projected tax benefits previously received for bonus depreciation related to the Kemper IGCC were repaid in connection with third quarter 2017 estimated tax payments. If the suspension of the Kemper IGCC start-up activities ultimately results in an abandonment for income tax purposes, the related deduction would be claimed in the year of the abandonment. See Note (G) for additional information. The ultimate outcome of this matter cannot be determined at this time.

Section 174 Research and Experimental Deduction

Southern Company, on behalf of Mississippi Power, has reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. See Note (G) for additional information.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

As of September 30, 2017, 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, 2017:	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)	$	231	$	184	$	—	$	—	$	415
Interest rate derivatives	—		5		—		—		5
Foreign currency derivatives	—		103		—		—		103
Nuclear decommissioning trusts(c)	752		1,004		—		26		1,782
Cash equivalents	1,271		—		—		—		1,271
Other investments	9		—		1		—		10
Total	$	2,263	$	1,296	$	1	$	26	$	3,586
Liabilities:
Energy-related derivatives(a)(b)	$	265	$	146	$	—	$	—	$	411
Interest rate derivatives	—		24		—		—		24
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		20		—		20
Total	$	265	$	193	$	20	$	—	$	478
Alabama Power
Assets:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9
Nuclear decommissioning trusts:(d)
Domestic equity	422		81		—		—		503
Foreign equity	60		57		—		—		117
U.S. Treasury and government agency securities	—		27		—		—		27
Corporate bonds	19		150		—		—		169
Mortgage and asset backed securities	—		18		—		—		18
Private Equity	—		—		—		26		26
Other	—		8		—		—		8
Cash equivalents	808		—		—		—		808
Total	$	1,309	$	350	$	—	$	26	$	1,685
Liabilities:
Energy-related derivatives	$	—	$	7	$	—	$	—	$	7

	Fair Value Measurements Using:
As of September 30, 2017:	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)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	18	$	—	$	—	$	18
Interest rate derivatives	—		1		—		—		1
Nuclear decommissioning trusts:(d) (e)
Domestic equity	235		1		—		—		236
Foreign equity	—		156		—		—		156
U.S. Treasury and government agency securities	—		225		—		—		225
Municipal bonds	—		64		—		—		64
Corporate bonds	—		160		—		—		160
Mortgage and asset backed securities	—		38		—		—		38
Other	16		19		—		—		35
Cash equivalents	112		—		—		—		112
Total	$	363	$	682	$	—	$	—	$	1,045
Liabilities:
Energy-related derivatives	$	—	$	11	$	—	$	—	$	11
Interest rate derivatives	—		3		—		—		3
Total	$	—	$	14	$	—	$	—	$	14
Gulf Power
Assets:
Cash equivalents	$	21	$	—	$	—	$	—	$	21
Liabilities:
Energy-related derivatives	$	—	$	22	$	—	$	—	$	22
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Interest rate derivatives	—		2		—		—		2
Cash equivalents	209		—		—		—		209
Total	$	209	$	5	$	—	$	—	$	214
Liabilities:
Energy-related derivatives	$	—	$	7	$	—	$	—	$	7

	Fair Value Measurements Using:
As of September 30, 2017:	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 Power
Assets:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9
Foreign currency derivatives	—		103		—		—		103
Cash equivalents	90		—		—		—		90
Total	$	90	$	112	$	—	$	—	$	202
Liabilities:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		20		—		20
Total	$	—	$	27	$	20	$	—	$	47
Southern Company Gas
Assets:
Energy-related derivatives(a)(b)	$	231	$	145	$	—	$	—	$	376
Liabilities:
Energy-related derivatives(a)(b)	$	265	$	95	$	—	$	—	$	360

(a) Excludes $13 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value.

(b) Excludes cash collateral of $76 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, 2017, approximately $66 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 at Southern Company, including reinvested interest and dividends and excluding the funds' expenses, increased by $50 million and $168 million, respectively, for the three and nine months ended September 30, 2017, and by $49 million and $116 million, respectively, for the three and nine months ended September 30, 2016. Alabama Power recorded increases in fair value of $25 million and $87 million, respectively, for the three and nine months ended September 30, 2017 and $26 million and $66 million, respectively, for the three and nine months ended September 30, 2016 as a change in regulatory liabilities related to its AROs. Georgia Power recorded increases in fair value of $25 million and $81 million, respectively, for the three and nine months ended September 30, 2017 and $23 million and $50 million, respectively, for the three and nine months ended September 30, 2016 as a change in its regulatory asset related to its AROs.

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 (H) for additional information on how these derivatives are used.

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning 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. 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 obligated to make generation-based payments to the seller over a period ranging from 10 to 30 years, beginning at the commercial operation date. 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, and is evaluated periodically. 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, 2017, the fair value measurements of private equity investments held in the nuclear decommissioning trust 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, 2017:	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company	$	26	$	24	Not Applicable	Not Applicable
Alabama Power	$	26	$	24	Not Applicable	Not Applicable

Private equity funds include a fund-of-funds that invests 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, 2017, 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	$	47,269	$	49,348
Alabama Power	$	7,404	$	8,031
Georgia Power	$	11,713	$	12,237
Gulf Power	$	1,292	$	1,352
Mississippi Power	$	2,123	$	2,117
Southern Power	$	5,810	$	5,916
Southern Company Gas	$	5,862	$	6,230

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, 2017

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 the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:

	Three Months Ended September 30, 2017	Three Months Ended September 30, 2016	Nine Months Ended September 30, 2017	Nine Months Ended September 30, 2016
	(in millions)
As reported shares	1,003	968	998	940
Effect of options and performance share award units	7	7	7	5
Diluted shares	1,010	975	1,005	945

Stock options and performance share award units 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, 2017 and 2016.

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(*)
	(in thousands)			(in millions)
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
Balance at December 31, 2015	915,073	(3,352	)	$	20,592		$	609		$	781		$	21,982
Consolidated net income attributable to Southern Company	—	—		2,251			—			—			2,251
Other comprehensive income (loss)	—	—		(95		)	—			—			(95		)
Stock issued	65,725	2,599		3,265			—			—			3,265
Stock-based compensation	—	—		94			—			—			94
Cash dividends on common stock	—	—		(1,553		)	—			—			(1,553		)
Contributions from noncontrolling interests	—	—		—			—			357			357
Distributions to noncontrolling interests	—	—		—			—			(21		)	(21		)
Purchase of membership interests from noncontrolling interests	—	—		—			—			(129		)	(129		)
Net income attributable to noncontrolling interests	—	—		—			—			36			36
Other	—	(46	)	(7		)	—			—			(7		)
Balance at September 30, 2016	980,798	(799	)	$	24,547		$	609		$	1,024		$	26,180

(*) Related to Southern Power Company and excludes redeemable noncontrolling interests. In April 2017, approximately $114 million was reclassified from redeemable noncontrolling interests to noncontrolling interests, included in stockholder's equity, due to the expiration of SunPower Corp's option to require Southern Power to purchase its membership interests in one of the solar partnerships. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

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Financing

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

FINANCING

FINANCING

Going Concern

As of September 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $769 million primarily due to approximately $935 million that will be required through September 30, 2018 to fund maturities of long-term debt and $4 million that will be required to fund maturities of short-term debt. In addition, Mississippi Power has $40 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilities and $50 million of fixed rate pollution control revenue bonds that are required to be remarketed over the next 12 months. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans, as market conditions permit, as well as, under certain circumstances, commercial paper and/or equity contributions and/or loans from Southern Company to fund Mississippi Power's short-term capital needs. Specifically, Mississippi Power has been informed by Southern Company that in the event sufficient funds are not available from external sources, Southern Company intends to provide Mississippi Power with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (B) under "Integrated Coal Gasification Combined Cycle."

DOE Loan Guarantee Borrowings

See Note 6 to the financial statements of Southern Company and Georgia Power in Item 8 of the Form 10-K for additional information regarding Georgia Power's Loan Guarantee Agreement with the DOE and related multi-advance term loan facility (FFB Credit Facility) with the FFB.

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 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 such time as Georgia Power has (i) completed the cost-to-complete and cancellation cost assessments prepared as a result of the bankruptcy of the EPC Contractor (Cost Assessments) and made a determination to continue construction of Plant Vogtle Units 3 and 4, (ii) delivered to the DOE an updated project schedule, construction budget, and other information, (iii) entered into one or more agreements with a construction contractor or contractors that will be primarily responsible for construction of Plant Vogtle Units 3 and 4 and such agreements have been approved by the DOE (together with the Services Agreement and the IP Licenses, the Replacement EPC Arrangements), and (iv) entered into a further amendment to the Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements.

Upon satisfaction of the conditions described above, advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.

In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, accuracy of project-related representations and warranties, delivery of updated project-related information, absence of liens on Georgia Power's ownership interest in Plant Vogtle Units 3 and 4 other than permitted liens, evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs.

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 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 Services Agreement or rejection of the 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) a failure by Georgia Power to complete the Cost Assessments or enter into Replacement EPC Arrangements by December 31, 2017; (iv) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (v) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit 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, under certain circumstances Georgia Power may be required to make additional prepayments in connection with its receipt of payments under the Guarantee Settlement Agreement or from the EPC Contractor under the Vogtle 3 and 4 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.

On September 28, 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. 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 (B) under "Regulatory Matters – Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

Bank Credit Arrangements

Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional electric operating companies' pollution control revenue bonds. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of September 30, 2017 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 June 2017, Georgia Power remarketed $318 million of variable rate pollution control bonds in index rate modes, reducing the liquidity support utilized under Georgia Power's bank credit arrangement. In addition, at September 30, 2017, the traditional electric operating companies had approximately $699 million (comprised of approximately $509 million at Georgia Power, $140 million at Gulf Power, and $50 million at Mississippi Power) of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to September 30, 2017, $40 million of these pollution control revenue bonds of Georgia Power which were in an index rate mode were remarketed to the public in a long-term fixed rate mode. 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, 2017:

	Expires														Executable Term Loans				Expires Within One Year
Company	2017		2018		2019		2020		2022		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)
Southern Company(a)	$	—	$	—	$	—	$	—	$	2,000	$	2,000	$	2,000	$	—	$	—	$	—	$	—
Alabama Power	—		35		—		500		800		1,335		1,335		—		—		—		35
Georgia Power	—		—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	30		195		25		30		—		280		280		45		—		—		40
Mississippi Power	100		—		—		—		—		100		100		—		—		—		100
Southern Power Company(b)	—		—		—		—		750		750		728		—		—		—		—
Southern Company Gas(c)	—		—		—		—		1,900		1,900		1,861		—		—		—		—
Other	—		30		—		—		—		30		30		20		—		20		10
Southern Company Consolidated	$	130	$	260	$	25	$	530	$	7,200	$	8,145	$	8,066	$	65	$	—	$	20	$	185

(a) Represents the Southern Company parent entity.

(b) Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $111 million has been used for letters of credit and $9 million remains unused at September 30, 2017.

(c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.2 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.

As reflected in the table above, in May 2017, Southern Company, Alabama Power, Georgia Power, and Southern Power Company each amended certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2020 to 2022. Southern Company and Southern Power Company increased their borrowing ability under these arrangements to $2.0 billion from $1.25 billion and to $750 million from $600 million, respectively. Southern Company also terminated its $1.0 billion facility maturing in 2018. Also in May 2017, Southern Company Gas Capital and Nicor Gas terminated their existing credit arrangements for $1.3 billion and $700 million, respectively, which were to mature in 2017 and 2018, and entered into a new multi-year credit arrangement currently allocated for $1.2 billion and $700 million, respectively, with a maturity date of 2022. Pursuant to the new multi-year credit arrangement, the allocations may be adjusted. In September 2017, Alabama Power amended its $500 million multi-year credit arrangement, which, among other things, extended the maturity date from 2018 to 2020.

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.

Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2017:

Company	Senior Note Issuances		Senior Note Maturities and Redemptions		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions and Maturities(a)
	(in millions)
Southern Company(b)	$	300	$	400	$	—	$	500		$	400
Alabama Power	550		200		36		—			—
Georgia Power	1,350		450		65		370			13
Gulf Power	300		85		—		6			—
Mississippi Power	—		—		—		40			893
Southern Power	—		—		—		43			4
Southern Company Gas(c)	450		—		—		200			22
Other	—		—		—		—			12
Elimination(d)	—		—		—		(40		)	(599		)
Southern Company Consolidated	$	2,950	$	1,135	$	101	$	1,119		$	745

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

(b) Represents the Southern Company parent entity.

(c) The senior notes were issued by Southern Company Gas Capital and guaranteed by the Southern Company Gas parent entity. Other long-term debt issued represents first mortgage bonds issued by Nicor Gas.

(d) Includes intercompany loans from Southern Company to Mississippi Power and reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements.

Southern Company

In June 2017, Southern Company issued $500 million aggregate principal amount of Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057 and $300 million aggregate principal amount of Series 2017A Floating Rate Senior Notes due September 30, 2020, which bear interest at a floating rate based on three-month LIBOR. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.

Also in June 2017, Southern Company entered into two$100 million aggregate principal amount floating rate bank term loan agreements, which mature on June 21, 2018 and June 29, 2018 and bear interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.

In August 2017, Southern Company borrowed $250 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds were used for working capital and other general corporate purposes.

Alabama Power

In March 2017, Alabama Power issued $550 million aggregate principal amount of Series 2017A 2.45% Senior Notes due March 30, 2022. The proceeds were used to repay Alabama Power's short-term indebtedness and for general corporate purposes, including Alabama Power's continuous construction program.

In September 2017, Alabama Power issued 10 million shares ($250 million aggregate stated capital) of 5.00% Class A Preferred Stock, Cumulative, Par Value $1 Per Share (Stated Capital $25 Per Share). The proceeds were used in October 2017 to redeem all 2 million shares ($50 million aggregate stated capital) of Alabama Power's 6.50% Series Preference Stock, 6 million shares ($150 million aggregate stated capital) of Alabama Power's 6.45% Series Preference Stock, and 1.52 million shares ($38 million aggregate stated capital) of Alabama Power's 5.83% Class A Preferred Stock and for other general corporate purposes, including Alabama Power's continuous construction program.

Georgia Power

In March 2017, Georgia Power issued $450 million aggregate principal amount of Series 2017A 2.00% Senior Notes due March 30, 2020 and $400 million aggregate principal amount of Series 2017B 3.25% Senior Notes due March 30, 2027. The proceeds were used to repay a portion of Georgia Power's short-term indebtedness and for general corporate purposes, including Georgia Power's continuous construction program.

In April 2017, Georgia Power purchased and held $27 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995. Subsequent to September 30, 2017, Georgia Power remarketed these bonds to the public.

In June 2017, Georgia Power entered into three floating rate bank loans in aggregate principal amounts of $50 million, $150 million, and $100 million, with maturity dates of December 1, 2017, May 31, 2018, and June 28, 2018, respectively, which bear interest based on one-month LIBOR. Also in June 2017, Georgia Power borrowed $500 million pursuant to an uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Georgia Power and the bank from time to time and is payable on no less than 30 days' demand by the bank. The proceeds from these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes, including Georgia Power's continuous construction program.

In August 2017, Georgia Power repaid $250 million of the $500 million aggregate principal amount outstanding pursuant to its uncommitted bank credit arrangement. Also in August 2017, Georgia Power amended its $100 million floating rate bank loan to extend the maturity date from June 28, 2018 to October 26, 2018.

Also in August 2017, Georgia Power issued $500 million aggregate principal amount of Series 2017C 2.00% Senior Notes due September 8, 2020. The proceeds were used to repay Georgia Power's $50 million floating rate bank loan due December 1, 2017 and outstanding commercial paper borrowings and for general corporate purposes.

Also in August 2017, Georgia Power purchased and held $38 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1997. Subsequent to September 30, 2017, Georgia Power remarketed these bonds to the public.

In September 2017, Georgia Power issued $270 million aggregate principal amount of Series 2017A 5.00% Junior Subordinated Notes due October 1, 2077. The proceeds were used in October 2017 to redeem all 1.8 million shares ($45 million aggregate liquidation amount) of Georgia Power's 6.125% Series Class A Preferred Stock and 2.25 million shares ($225 million aggregate liquidation amount) of Georgia Power's 6.50% Series 2007A Preference Stock.

Gulf Power

In March 2017, Gulf Power extended the maturity of a $100 million short-term floating rate bank loan bearing interest based on one-month LIBOR from April 2017 to October 2017 and subsequently repaid the loan in May 2017.

In May 2017, Gulf Power issued $300 million aggregate principal amount of Series 2017A 3.30% Senior Notes due May 30, 2027. The proceeds, together with other funds, were used to repay at maturity $85 million aggregate principal amount of Series 2007A 5.90% Senior Notes due June 15, 2017; to repay outstanding commercial paper borrowings; to repay a $100 million short-term floating rate bank loan, as discussed above; and to redeem, in June 2017, 550,000 shares ($55 million aggregate liquidation amount) of Gulf Power's 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Gulf Power's Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Gulf Power's Series 2013A 5.60% Preference Stock.

Mississippi Power

In March 2017, Mississippi Power issued a $9 million short-term bank note bearing interest at 5% per annum, which was repaid in April 2017.

In February 2017, Mississippi Power amended $551 million in promissory notes to Southern Company extending the maturity dates of the notes from December 1, 2017 to July 31, 2018. In the second quarter 2017, Mississippi Power borrowed an additional $40 million under a promissory note issued to Southern Company.

In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay a $10 million short-term bank loan.

In August 2017, Mississippi Power repaid a $12.5 million short-term bank note.

In September 2017, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million bearing interest based on one-month LIBOR. Mississippi Power borrowed $109 million under this promissory note primarily to satisfy its federal income tax obligations for the quarter ending September 30, 2017 and subsequently repaid the promissory note upon receipt of its income tax refund from the U.S. federal government related to the settlement concerning deductible R&E expenditures. See Note (G) under "Section 174 Research and Experimental Deduction" for additional information.

Southern Power

In September 2017, Southern Power amended its $60 million aggregate principal amount floating rate bank loan to, among other things, increase the aggregate principal amount to $100 million and extend the maturity date from September 2017 to October 2018. The additional $40 million of proceeds were used to repay existing indebtedness and for other general corporate purposes.

Southern Company Gas

In May 2017, Southern Company Gas Capital issued $450 million aggregate principal amount of Series 2017A 4.40% Senior Notes due May 30, 2047. The proceeds were used to repay Southern Company Gas' short-term indebtedness and for general corporate purposes.

In July 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of first mortgage bonds in a private placement. On August 10, 2017, Nicor Gas issued $100 million aggregate principal amount of First Mortgage Bonds 3.03% Series due August 10, 2027 and $100 million aggregate principal amount of First Mortgage Bonds 3.62% Series due August 10, 2037. The proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs. The remaining $200 million is expected to be issued in November 2017.

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Retirement Benefits

9 Months Ended

Sep. 30, 2017

Retirement Benefits [Abstract]

RETIREMENT BENEFITS

RETIREMENT BENEFITS

Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at Southern Company Gas, as discussed below, and PowerSecure. The Southern Company qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No mandatory contributions to the Southern Company qualified pension plan are anticipated for the year ending December 31, 2017. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, 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.

In addition, Southern Company Gas has a qualified defined benefit, trusteed, pension plan covering certain eligible employees, which was closed in 2012 to new employees. This qualified pension plan is funded in accordance with requirements of ERISA. No mandatory contributions to the Southern Company Gas qualified pension plan are anticipated for the year ending December 31, 2017. Southern Company Gas also provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company Gas provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. Southern Company Gas also has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.

See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Company Gas 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, 2017 and 2016 are presented in the following tables.

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended September 30, 2017
Service cost	$	73		$	15		$	19		$	3		$	4
Interest cost	114			25			34			5			5
Expected return on plan assets	(224		)	(49		)	(71		)	(10		)	(9		)
Amortization:
Prior service costs	3			1			—			—			—
Net (gain)/loss	41			10			15			2			1
Net periodic pension cost (income)	$	7		$	2		$	(3	)	$	—		$	1
Nine Months Ended September 30, 2017
Service cost	$	220		$	47		$	56		$	10		$	11
Interest cost	341			73			103			15			15
Expected return on plan assets	(673		)	(147		)	(212		)	(29		)	(29		)
Amortization:
Prior service costs	9			2			2			—			1
Net (gain)/loss	122			31			43			5			5
Net periodic pension cost (income)	$	19		$	6		$	(8	)	$	1		$	3
Three Months Ended September 30, 2016
Service cost	$	68		$	14		$	17		$	3		$	3
Interest cost	110			23			34			5			4
Expected return on plan assets	(203		)	(46		)	(64		)	(9		)	(9		)
Amortization:
Prior service costs	3			1			1			—			1
Net (gain)/loss	45			10			14			2			2
Net periodic pension cost	$	23		$	2		$	2		$	1		$	1
Nine Months Ended September 30, 2016
Service cost	$	192		$	43		$	52		$	9		$	9
Interest cost	311			71			102			14			14
Expected return on plan assets	(577		)	(138		)	(193		)	(26		)	(26		)
Amortization:
Prior service costs	10			2			4			1			1
Net (gain)/loss	120			30			41			5			5
Net periodic pension cost	$	56		$	8		$	6		$	3		$	3

Pension Plans	Southern Company Gas
	(in millions)
Successor – Three Months Ended September 30, 2017
Service cost	$	6
Interest cost	10
Expected return on plan assets	(18		)
Amortization of net (gain)/loss	5
Net periodic pension cost	$	3
Successor – Nine Months Ended September 30, 2017
Service cost	$	17
Interest cost	30
Expected return on plan assets	(53		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	15
Net periodic pension cost	$	8
Successor – July 1, 2016 through September 30, 2016
Service cost	$	7
Interest cost	10
Expected return on plan assets	(17		)
Amortization of regulatory asset	6
Net periodic pension cost	$	6
Predecessor – January 1, 2016 through June 30, 2016
Service cost	$	13
Interest cost	21
Expected return on plan assets	(33		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	13
Net periodic pension cost	$	13

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended September 30, 2017
Service cost	$	6		$	1		$	2		$	—		$	—
Interest cost	19			4			6			1			1
Expected return on plan assets	(16		)	(5		)	(6		)	—			—
Amortization:
Prior service costs	2			1			—			—			—
Net (gain)/loss	3			—			3			—			—
Net periodic postretirement benefit cost	$	14		$	1		$	5		$	1		$	1
Nine Months Ended September 30, 2017
Service cost	$	18		$	4		$	5		$	1		$	1
Interest cost	59			13			21			2			3
Expected return on plan assets	(49		)	(19		)	(18		)	(1		)	(1		)
Amortization:
Prior service costs	5			3			1			—			—
Net (gain)/loss	10			1			6			—			—
Net periodic postretirement benefit cost	$	43		$	2		$	15		$	2		$	3
Three Months Ended September 30, 2016
Service cost	$	6		$	1		$	2		$	—		$	—
Interest cost	20			5			7			1			—
Expected return on plan assets	(16		)	(6		)	(6		)	—			—
Amortization:
Prior service costs	1			1			—			—			—
Net (gain)/loss	5			—			3			—			1
Net periodic postretirement benefit cost	$	16		$	1		$	6		$	1		$	1
Nine Months Ended September 30, 2016
Service cost	$	17		$	4		$	5		$	1		$	1
Interest cost	55			14			22			2			2
Expected return on plan assets	(44		)	(19		)	(17		)	(1		)	(1		)
Amortization:
Prior service costs	4			3			1			—			—
Net (gain)/loss	12			1			7			—			1
Net periodic postretirement benefit cost	$	44		$	3		$	18		$	2		$	3

Postretirement Benefits	Southern Company Gas
	(in millions)
Successor – Three Months Ended September 30, 2017
Service cost	$	1
Interest cost	3
Expected return on plan assets	(2		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	1
Net periodic postretirement benefit cost	$	2
Successor – Nine Months Ended September 30, 2017
Service cost	$	2
Interest cost	8
Expected return on plan assets	(5		)
Amortization:
Prior service costs	(2		)
Net (gain)/loss	3
Net periodic postretirement benefit cost	$	6
Successor – July 1, 2016 through September 30, 2016
Service cost	$	1
Interest cost	2
Expected return on plan assets	(2		)
Amortization of regulatory asset	1
Net periodic postretirement benefit cost	$	2
Predecessor – January 1, 2016 through June 30, 2016
Service cost	$	1
Interest cost	5
Expected return on plan assets	(3		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	2
Net periodic postretirement benefit cost	$	4

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Income Taxes

9 Months Ended

Sep. 30, 2017

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.

Current and Deferred Income Taxes

Tax Credit Carryforwards

Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $1.9 billion as of September 30, 2017 compared to $1.8 billion as of December 31, 2016.

The federal ITC carryforwards begin expiring in 2032 but are expected to be fully utilized by 2022. The PTC carryforwards begin expiring in 2036 but are expected to be utilized by 2022. The expected utilization of tax credit carryforwards could be further delayed by numerous factors. These factors include the acquisition of additional renewable projects, increased generation at existing wind facilities, carrying back the federal net operating loss, and potential tax reform legislation, as well as additional deductions in the event of an asset abandonment. The ultimate outcome of these matters cannot be determined at this time.

Valuation Allowances

At September 30, 2017, valuation allowances were as follows:

	Mississippi Power		Southern Company Gas		Southern Company
	(in millions)
Federal	$	—	$	18	$	18
State (net of federal benefit)	46		1		64
Balance at September 30, 2017	$	46	$	19	$	82

Southern Company had valuation allowances, net of the federal benefit, of $82 million at September 30, 2017 compared to $21 million at December 31, 2016. The increase was primarily due to Mississippi Power's projected inability to utilize the State of Mississippi net operating loss.

Effective Tax Rate

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 42.6% for the nine months ended September 30, 2017 compared to 28.3% for the corresponding period in 2016. The effective tax rate increase was primarily due to the estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion. Other factors include a decrease in tax benefits from solar ITCs and an increase in state valuation allowances, partially offset by an increase in tax benefits from wind PTCs.

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.

Mississippi Power

Mississippi Power's effective tax (benefit) rate was (30.3)% for the nine months ended September 30, 2017 compared to (282.8)% for the corresponding period in 2016. The effective tax rate increase was primarily due to the estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion and the related state valuation allowances.

Southern Power

Southern Power's effective tax (benefit) rate was (66.5)% for the nine months ended September 30, 2017 compared to (88.9)% for the corresponding period in 2016. The effective tax rate increase was primarily due to a decrease in tax benefits from solar ITCs, partially offset by additional wind PTCs and state apportionment rate changes.

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.

During the third quarter 2017, Southern Power began a legal entity reorganization of various direct and indirect subsidiaries that own and operate solar facilities, including certain subsidiaries owned in partnership with various third parties. Southern Power's ownership interests in the various solar entities and facilities will not be affected by the reorganization. The reorganization is expected to result in estimated tax benefits totaling approximately $40 million that will be recorded in the fourth quarter 2017 related to certain changes in state apportionment rates and net operating loss carryforward utilization. The ultimate outcome of this matter cannot be determined at this time.

Southern Company Gas

Southern Company Gas' effective tax rate was 43.4% for the successor nine months ended September 30, 2017 compared to 60.3% for the successor period of July 1, 2016 through September 30, 2016 and 37.6% for the predecessor period of January 1, 2016 through June 30, 2016. The effective tax rate for the successor year-to-date 2017 was impacted by State of Illinois tax legislation enacted during July 2017, the allocation of new tax apportionment factors in several states for the inclusion of Southern Company Gas into the consolidated Southern Company state tax filings, and higher pre-tax earnings. The effective tax rates for the periods in 2016 were impacted by the non-deductibility of certain Merger-related expenses. The effective tax rate for the successor period of July 1, 2016 through September 30, 2016 was also impacted by nondeductible expenses associated with certain compensation costs.

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.

Changes during the nine months ended September 30, 2017 for unrecognized tax benefits were as follows:

	Mississippi Power			Southern Power			Southern Company
	(in millions)
Unrecognized tax benefits as of December 31, 2016	$	465		$	17		$	484
Tax positions from current periods	2			—			9
Tax positions from prior periods	(175		)	(17		)	(186		)
Reductions due to settlements	(290		)	—			(290		)
Balance as of September 30, 2017	$	2		$	—		$	17

The tax positions from current and prior periods primarily relate to state tax benefits, deductions for R&E expenditures, and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper IGCC, as well as federal income tax benefits from deferred ITCs. See "Section 174 Research and Experimental Deduction" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.

The impact on the effective tax rate, if recognized, is as follows:

	As of September 30, 2017				As of December 31, 2016
	Mississippi Power		Southern Company		Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	2	$	17	$	20
Tax positions not impacting the effective tax rate	—		—		464
Balance of unrecognized tax benefits	$	2	$	17	$	484

The tax positions impacting the effective tax rate primarily relate to state tax benefits and charitable contribution carryforwards that were impacted as a result of the settlement of R&E expenditures associated with the Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for additional information.

Accrued interest for all tax positions was immaterial for all periods presented.

All of the registrants classify interest on tax uncertainties as interest expense. None of the registrants accrued any penalties on uncertain tax positions.

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 federal income tax returns through 2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. However, the pre-Merger Southern Company Gas 2014, 2015, and June 30, 2016 federal tax returns are currently under audit. 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 2011.

Section 174 Research and Experimental Deduction

Southern Company has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and filed amended federal income tax returns for 2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. As a result of the JCT approval, Southern Company recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated accrued interest. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount not allowed under IRC Section 174 would be claimed as a deduction under IRC Section 165 in the year an abandonment is determined. The ultimate outcome of this matter cannot be determined at this time.

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Derivatives

9 Months Ended

Sep. 30, 2017

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 (C) 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.

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 extended the moratorium on Gulf Power's fuel-hedging program until January 1, 2021 in connection with the 2017 Rate Case Settlement Agreement. 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 the statements of income.

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 as the hedged transactions are reflected in earnings.

• 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, 2017, 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(*)	463	2021	2024
Alabama Power	66	2020	—
Georgia Power	159	2021	—
Gulf Power	28	2020	—
Mississippi Power	44	2021	—
Southern Power	13	2018	—
Southern Company Gas(*)	153	2020	2024

(*) 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 3.3 billion mmBtu and short natural gas positions of 3.1 billion mmBtu as of September 30, 2017, 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 34 million mmBtu for Southern Company, 11 million mmbtu for Georgia Power and Southern Power, 5 million mmbtu for Alabama Power, 3 million mmBtu for Gulf Power, and 4 million mmBtu for Mississippi 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, 2018 are $5 million for Southern Power and immaterial for all other 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 effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. 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, providing an offset, with any difference representing ineffectiveness. 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, 2017, 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, 2017
	(in millions)					(in millions)
Cash Flow Hedges of Existing Debt
Mississippi Power	$	900	1-month LIBOR	0.79%	March 2018	$	2
Fair Value Hedges of Existing Debt
Southern Company(*)	300		2.75%	3-month LIBOR + 0.92%	June 2020	—
Southern Company(*)	1,500		2.35%	1-month LIBOR + 0.87%	July 2021	(19		)
Georgia Power	250		5.40%	3-month LIBOR + 4.02%	June 2018	—
Georgia Power	500		1.95%	3-month LIBOR + 0.76%	December 2018	(2		)
Georgia Power	200		4.25%	3-month LIBOR + 2.46%	December 2019	—
Southern Company Consolidated	$	3,650				$	(19	)

(*) 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, 2018 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 effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time that the hedged transactions affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

At September 30, 2017, 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, 2017
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	42
Southern Power	564		3.78%	500		1.85%	June 2026	38
Total	$	1,241		€	1,100			$	80

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, 2018 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, 2017						As of December 31, 2016
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	$	21		$	25		$	73		$	27
Other deferred charges and assets/Other deferred credits and liabilities	13			23			25			33
Total derivatives designated as hedging instruments for regulatory purposes	$	34		$	48		$	98		$	60
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	8		$	6		$	23		$	7
Interest rate derivatives:
Other current assets/Other current liabilities	5			1			12			1
Other deferred charges and assets/Other deferred credits and liabilities	—			23			1			28
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			25
Other deferred charges and assets/Other deferred credits and liabilities	103			—			—			33
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	116		$	53		$	36		$	94
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	271		$	254		$	489		$	483
Other deferred charges and assets/Other deferred credits and liabilities	115			103			66			81
Interest rate derivatives:
Other current assets/Other current liabilities	—			—			1			—
Total derivatives not designated as hedging instruments	$	386		$	357		$	556		$	564
Gross amounts recognized	$	536		$	458		$	690		$	718
Gross amounts offset(*)	$	(275	)	$	(351	)	$	(462	)	$	(524	)
Net amounts recognized in the Balance Sheets	$	261		$	107		$	228		$	194

	As of September 30, 2017						As of December 31, 2016
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	$	6		$	4		$	13		$	5
Other deferred charges and assets/Other deferred credits and liabilities	3			3			7			4
Total derivatives designated as hedging instruments for regulatory purposes	$	9		$	7		$	20		$	9
Gross amounts recognized	$	9		$	7		$	20		$	9
Gross amounts offset	$	(5	)	$	(5	)	$	(8	)	$	(8	)
Net amounts recognized in the Balance Sheets	$	4		$	2		$	12		$	1
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	10		$	3		$	30		$	1
Other deferred charges and assets/Other deferred credits and liabilities	8			8			14			7
Total derivatives designated as hedging instruments for regulatory purposes	$	18		$	11		$	44		$	8
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	1		$	1		$	2		$	—
Other deferred charges and assets/Other deferred credits and liabilities	—			2			—			3
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	1		$	3		$	2		$	3
Gross amounts recognized	$	19		$	14		$	46		$	11
Gross amounts offset	$	(10	)	$	(10	)	$	(8	)	$	(8	)
Net amounts recognized in the Balance Sheets	$	9		$	4		$	38		$	3
Gulf Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	—		$	13		$	4		$	12
Other deferred charges and assets/Other deferred credits and liabilities	—			9			1			17
Total derivatives designated as hedging instruments for regulatory purposes	$	—		$	22		$	5		$	29
Gross amounts recognized	$	—		$	22		$	5		$	29
Gross amounts offset	$	—		$	—		$	(4	)	$	(4	)
Net amounts recognized in the Balance Sheets	$	—		$	22		$	1		$	25

	As of September 30, 2017						As of December 31, 2016
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	4		$	2		$	6
Other deferred charges and assets/Other deferred credits and liabilities	2			3			2			5
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	7		$	4		$	11
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	2		$	—		$	2		$	—
Other deferred charges and assets/Other deferred credits and liabilities	—			—			1			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	2		$	—		$	3		$	—
Gross amounts recognized	$	5		$	7		$	7		$	11
Gross amounts offset	$	(3	)	$	(3	)	$	(3	)	$	(3	)
Net amounts recognized in the Balance Sheets	$	2		$	4		$	4		$	8
Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	8		$	4		$	18		$	4
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			25
Other deferred charges and assets/Other deferred credits and liabilities	103			—			—			33
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	111		$	27		$	18		$	62
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	—		$	3		$	1
Interest rate derivatives:
Other current assets/Other current liabilities	—			—			1			—
Total derivatives not designated as hedging instruments	$	1		$	—		$	4		$	1
Gross amounts recognized	$	112		$	27		$	22		$	63
Gross amounts offset	$	(1	)	$	(1	)	$	(5	)	$	(5	)
Net amounts recognized in the Balance Sheets	$	111		$	26		$	17		$	58

	As of September 30, 2017						As of December 31, 2016
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	$	4		$	1		$	24		$	3
Other deferred charges and assets/Other deferred credits and liabilities	—			—			1			—
Total derivatives designated as hedging instruments for regulatory purposes	$	4		$	1		$	25		$	3
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	$	—		$	2		$	4		$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	270		$	254		$	486		$	482
Other deferred charges and assets/Other deferred credits and liabilities	115			103			66			81
Total derivatives not designated as hedging instruments	$	385		$	357		$	552		$	563
Gross amounts of recognized	$	389		$	360		$	581		$	569
Gross amounts offset(*)	$	(251	)	$	(327	)	$	(435	)	$	(497	)
Net amounts recognized in the Balance Sheets	$	138		$	33		$	146		$	72

(*) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $76 million and $62 million as of September 30, 2017 and December 31, 2016, respectively.

At September 30, 2017 and December 31, 2016, 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, 2017
Derivative Category and Balance Sheet Location	Southern Company(b)			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas(c)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(18	)	$	(1	)	$	—		$	(13	)	$	(3	)	$	(1	)
Other regulatory assets, deferred	(12		)	(1		)	(1		)	(9		)	(1		)	—
Other regulatory liabilities, current(a)	14			3			7			—			—			4
Other regulatory liabilities, deferred(b)	2			1			1			—			—			—
Total energy-related derivative gains (losses)	$	(14	)	$	2		$	7		$	(22	)	$	(4	)	$	3

(a) Georgia Power includes other regulatory liabilities, current in other current liabilities.

(b) Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.

(c) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $1 million at September 30, 2017.

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2016
Derivative Category and Balance Sheet Location	Southern Company(c)			Alabama Power			Georgia Power		Gulf Power			Mississippi Power			Southern Company Gas(c)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(16	)	$	(1	)	$	—	$	(9	)	$	(5	)	$	(1	)
Other regulatory assets, deferred	(19		)	—			—		(16		)	(3		)	—
Other regulatory liabilities, current(a)	56			8			29		1			1			17
Other regulatory liabilities, deferred(b)	12			4			7		—			—			1
Total energy-related derivative gains (losses)	$	33		$	11		$	36	$	(24	)	$	(7	)	$	17

(a) Georgia Power includes other regulatory liabilities, current in other current liabilities.

(b) Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.

(c) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $8 million at December 31, 2016.

For the three months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments were as follows:

Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)						Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
							Statements of Income Location	Amount
	2017			2016				2017			2016
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	(6	)	$	—		Depreciation and amortization	$	(6	)	$	1
Interest rate derivatives	(1		)	(6		)	Interest expense, net of amounts capitalized	(5		)	(6		)
Foreign currency derivatives	46			37			Interest expense, net of amounts capitalized	(5		)	(6		)
							Other income (expense), net(*)	43			7
Total	$	39		$	31			$	27		$	(4	)
Alabama Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(2	)	$	(2	)
Georgia Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Mississippi Power
Interest rate derivatives	$	(1	)	$	(1	)	Interest expense, net of amounts capitalized	$	—		$	—
Southern Power
Energy-related derivatives	$	(6	)	$	—		Depreciation and amortization	$	(6	)	$	1
Foreign currency derivatives	46			37			Interest expense, net of amounts capitalized	(5		)	(6		)
							Other income (expense), net(*)	43			7
Total	$	40		$	37			$	32		$	2
Southern Company Gas
Interest rate derivatives	$	—		$	(5	)	Interest expense, net of amounts capitalized	$	—		$	—

(*) 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 nine months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments were as follows:

Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)						Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
							Statements of Income Location	Amount
	2017			2016				2017			2016
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	(26	)	$	(1	)	Depreciation and amortization	$	(12	)	$	1
Interest rate derivatives	(2		)	(189		)	Interest expense, net of amounts capitalized	(15		)	(13		)
Foreign currency derivatives	114			(1		)	Interest expense, net of amounts capitalized	(17		)	(7		)
							Other income (expense), net(*)	139			(13		)
Total	$	86		$	(191	)		$	95		$	(32	)
Alabama Power
Interest rate derivatives	$	—		$	(3	)	Interest expense, net of amounts capitalized	$	(5	)	$	(5	)
Georgia Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(3	)	$	(3	)
Gulf Power
Energy-related derivatives	$	(1	)	$	—		Depreciation and amortization	$	—		$	—
Interest rate derivatives	(1		)	(7		)	Interest expense, net of amounts capitalized	—			—
Total	$	(2	)	$	(7	)		$	—		$	—
Mississippi Power
Interest rate derivatives	$	—		$	(1	)	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Southern Power
Energy-related derivatives	$	(21	)	$	(1	)	Depreciation and amortization	$	(12	)	$	1
Interest rate derivatives	—			—			Interest expense, net of amounts capitalized	—			(1		)
Foreign currency derivatives	114			(1		)	Interest expense, net of amounts capitalized	(17		)	(7		)
							Other income (expense), net(*)	139			(13		)
Total	$	93		$	(2	)		$	110		$	(20	)

(*) 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 Southern Company Gas, the pre-tax effect of energy related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings for the successor nine months ended September 30, 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016 were as follows:

	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)				Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Derivatives in Cash Flow Hedging Relationships	Nine Months Ended September 30, 2017			Statements of Income Location	Nine Months Ended September 30, 2017
	(in millions)				(in millions)
Energy-related derivatives	$	(4	)	Cost of natural gas	$	—

	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)							Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
	Successor			Predecessor				Successor		Predecessor
Derivatives in Cash Flow Hedging Relationships	July 1, 2016 through September 30, 2016			January 1, 2016 through June 30, 2016			Statements of Income Location	July 1, 2016 through September 30, 2016		January 1, 2016 through June 30, 2016
	(in millions)			(in millions)				(in millions)		(in millions)
Energy-related derivatives	$	—		$	—		Cost of natural gas	$	—	$	(1	)
Interest rate derivatives	(5		)	(64		)	Interest expense, net of amounts capitalized	—		—
Total	$	(5	)	$	(64	)		$	—	$	(1	)

For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments were immaterial for the other registrants.

For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments on the statements of income 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	2017			2016		2017			2016
		(in millions)					(in millions)
Southern Company
Energy Related derivatives:	Natural gas revenues(*)	$	(17	)	$	—	$	48		$	—
	Cost of natural gas	2			6		(2		)	6
Total derivatives in non-designated hedging relationships		$	(15	)	$	6	$	46		$	6

(*) Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $15 million for the nine months ended September 30, 2017 and immaterial amounts for all other periods presented.

		Gain (Loss)
		Successor			Successor		Successor			Successor		Predecessor
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	Three Months Ended September 30, 2017			Three Months Ended September 30, 2016		Nine Months Ended September 30, 2017			July 1, 2016 through September 30, 2016		January 1, 2016 through June 30, 2016
		(in millions)			(in millions)		(in millions)			(in millions)
Southern Company Gas
Energy Related derivatives:	Natural gas revenues(*)	$	(17	)	$	—	$	48		$	—	$	(1	)
	Cost of natural gas	2			6		(2		)	6		(62		)
Total derivatives in non-designated hedging relationships		$	(15	)	$	6	$	46		$	6	$	(63	)

(*) Excludes gains recorded in cost of natural gas associated with weather derivatives of $15 million for the successor nine months ended September 30, 2017 and immaterial amounts for all other periods presented.

For the three and nine months ended September 30, 2017 and 2016, 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.

For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:

Derivatives in Fair Value Hedging Relationships
		Gain (Loss)
		Three Months Ended September 30,						Nine Months Ended September 30,
Derivative Category	Statements of Income Location	2017			2016			2017			2016
		(in millions)						(in millions)
Southern Company
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	(5	)	$	(9	)	$	(6	)	$	15
Georgia Power
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	—		$	(5	)	$	(1	)	$	10

For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt.

There was no material ineffectiveness recorded in earnings for any registrant for any period presented.

Contingent Features

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At September 30, 2017, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

At September 30, 2017, the fair value of derivative liabilities with contingent features was immaterial for all registrants. 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, 2017, 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, 2017, cash collateral held on deposit in broker margin accounts was $76 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, 2017

Business Combinations [Abstract]

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS

Southern Company

Merger with Southern Company Gas

Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. On July 1, 2016, Southern Company completed the Merger for a total purchase price of approximately $8.0 billion and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company.

The Merger was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation:

Southern Company Gas Purchase Price
	(in millions)
Current assets	$	1,557
Property, plant, and equipment	10,108
Goodwill	5,967
Intangible assets	400
Regulatory assets	1,118
Other assets	229
Current liabilities	(2,201		)
Other liabilities	(4,742		)
Long-term debt	(4,261		)
Noncontrolling interest	(174		)
Total purchase price	$	8,001

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $6.0 billion is recognized as goodwill, which is primarily attributable to positioning the Southern Company system to provide natural gas infrastructure to meet customers' growing energy needs and to compete for growth across the energy value chain. Southern Company anticipates that much of the value assigned to goodwill will not be deductible for tax purposes.

The valuation of identifiable intangible assets included customer relationships, trade names, and storage and transportation contracts with estimated lives of one to 28 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).

The results of operations for Southern Company Gas have been included in Southern Company's consolidated financial statements from the date of acquisition and consist of operating revenues of $565 million and $2.8 billion and net income of $15 million and $303 million for the three and nine months ended September 30, 2017, respectively, and operating revenues and net income of $543 million and $4 million, respectively, for the three months ended September 30, 2016.

The following summarized unaudited pro forma consolidated statement of earnings information assumes that the acquisition of Southern Company Gas was completed on January 1, 2015. The summarized unaudited pro forma consolidated statement of earnings information includes adjustments for (i) intercompany sales, (ii) amortization of intangible assets, (iii) adjustments to interest expense to reflect current interest rates on Southern Company Gas debt and additional interest expense associated with borrowings by Southern Company to fund the Merger, and (iv) the elimination of nonrecurring expenses associated with the Merger.

	For the Nine Months Ended September 30,
	2016
Operating revenues (in millions)	$	16,609
Net income attributable to Southern Company (in millions)	$	2,394
Basic Earnings Per Share (EPS)	$	2.52
Diluted EPS	$	2.51

These unaudited pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2015 or the results that would be attained in the future.

Acquisition of PowerSecure

On May 9, 2016, Southern Company acquired all of the outstanding stock of PowerSecure, a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, for $18.75 per common share in cash, resulting in an aggregate purchase price of $429 million. As a result, PowerSecure became a wholly-owned subsidiary of Southern Company.

The acquisition of PowerSecure was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation:

PowerSecure Purchase Price
	(in millions)
Current assets	$	172
Property, plant, and equipment	46
Intangible assets	106
Goodwill	284
Other assets	4
Current liabilities	(121		)
Long-term debt, including current portion	(48		)
Deferred credits and other liabilities	(14		)
Total purchase price	$	429

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $284 million was recognized as goodwill, which is primarily attributable to expected business expansion opportunities for PowerSecure. Southern Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes.

The valuation of identifiable intangible assets included customer relationships, trade names, patents, backlog, and software with estimated lives of one to 26 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).

The results of operations for PowerSecure have been included in Southern Company's consolidated financial statements from the date of acquisition and are immaterial to the consolidated financial results of Southern Company. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were immaterial to Southern Company's consolidated financial results for all periods presented.

Southern Power

See Note 2 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, 2017

During the nine months ended September 30, 2017, in accordance with Southern Power's overall growth strategy, one of Southern Power's wholly-owned subsidiaries acquired the project discussed below. 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
Bethel	Wind	Invenergy, January 6, 2017	276	Castro County, TX	100	%	January 2017	12 years

The aggregate amounts of revenue and net income recognized by Southern Power related to the Bethel facility included in Southern Power's condensed consolidated statements of income for year-to-date 2017 were immaterial. The Bethel facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service; therefore, supplemental pro forma information as though the acquisition occurred as of the beginning of 2017 and for the comparable 2016 period is not meaningful and has been omitted.

In connection with Southern Power's 2016 acquisitions, allocations of the purchase price to individual assets were finalized during the nine months ended September 30, 2017 with no changes to amounts originally reported for Boulder 1, Grant Plains, Grant Wind, Henrietta, Mankato, Passadumkeag, Salt Fork, Tyler Bluff, and Wake Wind.

Subsequent to September 30, 2017, Southern Power purchased all of the redeemable noncontrolling interests, representing10%of the membership interests, in Southern Turner Renewable Energy, LLC and repaid$14 millionof notes payable to Turner Renewable Energy, LLC.

Construction Projects Completed and in Progress

During the nine months ended September 30, 2017, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through September 30, 2017, total costs of construction incurred for these projects were $494 million, of which $122 million remained in CWIP. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $360 million and $415 million for the Mankato and Cactus Flats facilities. The ultimate outcome of these matters cannot be determined at this time.

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Projects Completed During the Nine Months Ended September 30, 2017
East Pecos	Solar	120	Pecos County, TX	March 2017	15 years
Lamesa	Solar	102	Dawson County, TX	April 2017	15 years
Projects Under Construction as of September 30, 2017
Cactus Flats(*)	Wind	148	Concho County, TX	Third quarter 2018	12-15 years
Mankato	Natural Gas	345	Mankato, MN	Second quarter 2019	20 years

(*) On July 31, 2017, Southern Power acquired a 100% ownership interest in the Cactus Flats facility, which is in the early stages of construction, from RES America Developments, Inc.

Development Projects

In December 2016, as part of Southern Power's renewable development strategy, one of Southern Power's wholly-owned subsidiaries entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct approximately 3,000 MWs of wind projects. Also in December 2016, Southern Power signed agreements and made payments to purchase wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. All of the wind turbine equipment was delivered by April 2017, which allows the projects to qualify for 100% PTCs for 10 years following their expected commercial operation dates between 2018 and 2020. The ultimate outcome of these matters cannot be determined at this time.

Southern Company Gas

On October 15, 2017, Southern Company Gas subsidiary, Pivotal Utility Holdings, entered into agreements for the sale 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. The completion of each sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act; (ii) the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, the New Jersey BPU, and, with respect to the sale of Elkton Gas, the Maryland PSC; and (iii) other customary closing conditions. The sales are expected to be completed by the end of the third quarter 2018.

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

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Joint Ownership Agreements

9 Months Ended

Sep. 30, 2017

Regulated Operations [Abstract]

JOINT OWNERSHIP AGREEMENTS

JOINT OWNERSHIP AGREEMENTS

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.

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments as of September 30, 2017 and December 31, 2016 and related income from those investments for the successor three and nine month periods ended September 30, 2017, the successor three-month period ended September 30, 2016, and for the predecessor period January 1, 2016 through June 30, 2016 were as follows:

Balance Sheet Information	September 30, 2017		December 31, 2016
	(in millions)
SNG	$	1,385	$	1,394
Atlantic Coast Pipeline	61		33
PennEast Pipeline	49		22
Triton	43		44
Pivotal JAX LNG, LLC	40		16
Horizon Pipeline	30		30
Other	1		2
Total	$	1,609	$	1,541

	Successor		Successor		Successor		Predecessor
Income Statement Information	Three Months Ended September 30, 2017		Three Months Ended September 30, 2016		Nine Months Ended September 30, 2017		January 1, 2016 through June 30, 2016
	(in millions)		(in millions)		(in millions)		(in millions)
SNG	$	28	$	27	$	86	$	—
PennEast Pipeline	1		—		5		—
Atlantic Coast Pipeline	1		1		4		—
Triton	1		1		3		1
Horizon Pipeline	1		—		2		1
Total	$	32	$	29	$	100	$	2

Southern Natural Gas

In September 2016, Southern Company Gas, through a wholly-owned, indirect subsidiary, acquired a 50% equity interest in SNG, which is accounted for as an equity method investment. On March 31, 2017, Southern Company Gas made an additional $50 million contribution to maintain its 50% equity interest in SNG. See Note 11 to the financial statements of Southern Company Gas under "Investment in SNG" in Item 8 of the Form 10-K for additional information on this investment. Selected financial information of SNG for the three and nine months ended September 30, 2017 and for the period September 1, 2016 through September 30, 2016 is as follows:

Income Statement Information	Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017		September 1, 2016 through September 30, 2016
	(in millions)
Revenues	$	146	$	445	$	82
Operating income	$	71	$	218	$	60
Net income	$	57	$	172	$	55

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Segment and Related Information

9 Months Ended

Sep. 30, 2017

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 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 the seven natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations.

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 $105 million and $295 million for the three and nine months ended September 30, 2017, respectively, and $110 million and $313 million for the three and nine months ended September 30, 2016, 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, 2017 and 2016 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, 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)(c)	—		276		—			276		303		(232		)	—			347
Total assets at September 30, 2017	$	73,056	$	14,648	$	(322	)	$	87,382	$	22,190	$	2,275		$	(1,532	)	$	110,315
Three Months Ended September 30, 2016:
Operating revenues	$	5,236	$	500	$	(117	)	$	5,619	$	543	$	139		$	(37	)	$	6,264
Segment net income (loss)(a)(b)	1,022		176		—			1,198		4		(62		)	(1		)	1,139
Nine Months Ended September 30, 2016:
Operating revenues	$	13,120	$	1,189	$	(330	)	$	13,979	$	543	$	311		$	(118	)	$	14,715
Segment net income (loss)(a)(b)	2,086		315		—			2,401		4		(146		)	(8		)	2,251
Total assets at December 31, 2016	$	72,141	$	15,169	$	(316	)	$	86,994	$	21,853	$	2,474		$	(1,624	)	$	109,697

(a) Attributable to Southern Company.

(b) Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $34 million ($21 million after tax) and $88 million ($54 million after tax) for the three months ended September 30, 2017 and 2016, respectively, and $3.2 billion ($2.2 billion after tax) and $222 million ($137 million after tax) for the nine months ended September 30, 2017 and 2016, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.

(c) Segment net income (loss) for the traditional electric operating companies also 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 (B) under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information.

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2017	$	4,615	$	718	$	190	$	5,523
Three Months Ended September 30, 2016	4,808		613		198		5,619
Nine Months Ended September 30, 2017	$	11,786	$	1,867	$	586	$	14,239
Nine Months Ended September 30, 2016	11,932		1,455		592		13,979

	Southern Company Gas' Revenues
Period	Gas Distribution Operations		Gas Marketing Services		Other			Total
	(in millions)
Three Months Ended September 30, 2017	$	430	$	143	$	(8	)	$	565
Nine Months Ended September 30, 2017	$	2,119	$	597	$	125		$	2,841
Three and Nine Months Ended September 30, 2016	$	420	$	126	$	(3	)	$	543

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. Gas marketing services includes natural gas marketing to end-use customers primarily in Georgia and Illinois. Additionally, gas marketing services provides home equipment protection products and services. 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.

After the Merger, Southern Company Gas changed its segment performance measure to net income. In order to properly assess net income by segment, Southern Company Gas executed various intercompany note agreements to revise interest charges to its segments. Since such agreements did not exist in the predecessor period, Southern Company Gas is unable to provide the comparable net income.

Business segment financial data for the successor three months ended September 30, 2017 and 2016, the successor nine months ended September 30, 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016 was as follows:

	Gas Distribution Operations		Gas Marketing Services		Wholesale Gas Services(*)			Gas Midstream Operations		Total		All Other			Eliminations			Consolidated
	(in millions)
Successor – Three Months Ended September 30, 2017:
Operating revenues	$	472	$	143	$	(24	)	$	16	$	607	$	2		$	(44	)	$	565
Segment net income	52		1		(23		)	14		44		(29		)	—			15
Successor – Nine Months Ended September 30, 2017:
Operating revenues	$	2,255	$	597	$	95		$	53	$	3,000	$	7		$	(166	)	$	2,841
Segment net income	223		36		28			38		325		(22		)	—			303
Successor – Total assets at September 30, 2017	$	18,711	$	2,089	$	893		$	2,359	$	24,052	$	11,400		$	(13,262	)	$	22,190

	Gas Distribution Operations		Gas Marketing Services			Wholesale Gas Services(*)			Gas Midstream Operations			Total		All Other			Eliminations			Consolidated
	(in millions)
Successor – Three Months Ended September 30, 2016:
Operating revenues	$	455	$	126		$	(8	)	$	13		$	586	$	2		$	(45	)	$	543
Segment net income (loss)	27		(4		)	(11		)	14			26		(22		)	—			4
Predecessor – January 1, 2016 through June 30, 2016:
Operating revenues	$	1,575	$	435		$	(32	)	$	25		$	2,003	$	4		$	(102	)	$	1,905
Segment EBIT	353		109			(68		)	(6		)	388		(60		)	—			328
Successor – Total assets at December 31, 2016	$	19,453	$	2,084		$	1,127		$	2,211		$	24,875	$	11,145		$	(14,167	)	$	21,853

(*) 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)
Successor – Three Months Ended September 30, 2017	$	1,411	$	103	$	1,514	$	1,538	$	(24	)
Successor – Nine Months Ended September 30, 2017	4,781		362		5,143		5,048		95
Successor – Three Months Ended September 30, 2016	1,688		77		1,765		1,773		(8		)
Predecessor – January 1, 2016 through June 30, 2016	$	2,500	$	143	$	2,643	$	2,675	$	(32	)

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Introduction (Policies)

9 Months Ended

Sep. 30, 2017

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, 2016 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, 2017 and 2016. 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.

Southern Company's financial statements reflect its investments in its subsidiaries, including Southern Company Gas as a result of the Merger, on a consolidated basis. Southern Company Gas' results of operations and cash flows for the three and nine months ended September 30, 2017 and the three months ended September 30, 2016, as well as its financial condition as of September 30, 2017 and December 31, 2016, are reflected within Southern Company's consolidated amounts in these accompanying notes herein. The equity method is used for entities in which Southern Company has significant influence but does not control, including Southern Company Gas' investment in SNG, and for variable interest entities where Southern Company has an equity investment but is not the primary beneficiary. See Note (I) under "Southern Company– Merger with Southern Company Gas" for additional information regarding the Merger.

Pursuant to the Merger, Southern Company pushed down the application of the acquisition method of accounting to the consolidated financial statements of Southern Company Gas such that the assets and liabilities are recorded at their respective fair values, and goodwill has been established for the excess of the purchase price over the fair value of net identifiable assets. Accordingly, the consolidated financial statements of Southern Company Gas for periods before and after July 1, 2016 (acquisition date) reflect different bases of accounting, and the financial positions and results of operations of those periods are not comparable. Throughout Southern Company Gas' condensed consolidated financial statements and the accompanying notes herein, periods prior to July 1, 2016 are identified as "predecessor," while periods after the acquisition date are identified as "successor."

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 Issued Accounting Standards

Recently Issued 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.

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. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While the registrants expect most of their revenue to be included in the scope of ASC 606, they have not fully completed the evaluation of all revenue arrangements. The majority of Southern Company's, the traditional electric operating companies', and Southern Company Gas' revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined contractual term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements. The majority of Southern Power's revenues includes longer-term PPAs for generation capacity and energy. The registrants expect the adoption of ASC 606 will not result in a significant shift from the current timing of revenue recognition for such transactions.

The registrants' ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as certain PPAs, energy-related derivatives, and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the registrants' financial statements.In addition, the power and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company, the traditional electric operating companies, and Southern Company Gas expect CIAC to be out of the scope of ASC 606.

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The registrants intend to use the modified retrospective method of adoption effective January 1, 2018. The registrants have also elected to utilize practical expedients which allow them to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. In addition, disclosures will include comparative information on 2018 financial statement line items under current guidance. While the adoption of ASC 606, including the cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in the registrants' financial statements, the registrants will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.

On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for annual and interim periods beginning on or after December 15, 2019, and early adoption is permitted on testing dates after January 1, 2017. Southern Company and Southern Company Gas are evaluating the standard and expect to early adopt ASU 2017-04 effective January 1, 2018.

On March 10, 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 income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's, the traditional electric operating companies', and Southern Company Gas' operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Southern Company's, the traditional electric operating companies', or Southern Company Gas' financial statements.

On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. 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 and interim periods within those fiscal years, with early adoption permitted. The registrants are evaluating the standard and expect to early adopt ASU 2017-12 effective January 1, 2018. The adoption of ASU 2017-12 is not expected to have a material impact on the registrants' financial statements.

Affiliate Transactions

Affiliate Transactions

Prior to the completion of Southern Company Gas' acquisition of its 50% equity interest in SNG, SCS (as agent for Alabama Power, Georgia Power, and Southern Power) and Southern Company Gas had entered into long-term interstate natural gas transportation agreements with SNG. The interstate transportation service provided to Alabama Power, Georgia Power, Southern Power, and Southern Company Gas by SNG pursuant to these agreements is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the nine months ended September 30, 2017, transportation costs under these agreements for Alabama Power, Georgia Power, Southern Power, and Southern Company Gas were approximately $8 million, $77 million, $19 million, and $24 million, respectively. For the period subsequent to Southern Company Gas' investment in SNG through September 30, 2016, transportation costs under these agreements for Alabama Power, Georgia Power, Southern Power, and Southern Company Gas were approximately $1 million, $8 million, $2 million, and $4 million, respectively.

SCS, as agent for Georgia Power and Southern Power, has agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. For the nine months ended September 30, 2017, natural gas purchases made by Georgia Power and Southern Power from Southern Company Gas' subsidiaries were approximately $18 million and $94 million, respectively. For the period subsequent to Southern Company's acquisition of Southern Company Gas through September 30, 2016, natural gas purchases made by Georgia Power and Southern Power from Southern Company Gas' subsidiaries were approximately $7 million and $2 million, respectively.

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.

Property Damage Reserve

Property Damage Reserve

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.

Gulf Power's cost of repairing damages from major storms and other uninsured property damages, including uninsured damages to transmission and distribution facilities, generation facilities, and other property is charged to Gulf Power's property damage reserve. In accordance with a settlement agreement approved by the Florida PSC on April 4, 2017 (2017 Rate Case Settlement Agreement), Gulf Power suspended further property damage reserve accruals effective April 2017. Gulf Power may make discretionary accruals and is required to resume accruals of $3.5 million annually if the reserve balance falls below zero. In addition, Gulf Power may initiate a storm surcharge to recover costs associated with any tropical systems named by the National Hurricane Center or other catastrophic storm events that reduce the property damage reserve in the aggregate by approximately $31 million (75% of the April 1, 2017 balance) or more. The storm surcharge would begin, on an interim basis, 60 days following the filing of a cost recovery petition, would be limited to $4.00/month for a 1,000 KWH residential customer unless Gulf Power incurs in excess of $100 million in qualified storm recovery costs in a calendar year, and would replenish the property damage reserve to approximately $40 million. As of September 30, 2017, Gulf Power's property damage reserve totaled approximately $39 million. See Note (B) under "Regulatory Matters–Gulf Power– Retail Base Rate Cases" for additional details regarding the 2017 Rate Case Settlement Agreement.

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, 2017. 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.

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 (H) for additional information on how these derivatives are used.

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning 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. 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 obligated to make generation-based payments to the seller over a period ranging from 10 to 30 years, beginning at the commercial operation date. 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, and is evaluated periodically. 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 the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method.

Derivatives

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 effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. 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, providing an offset, with any difference representing ineffectiveness. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (C) 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.

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 extended the moratorium on Gulf Power's fuel-hedging program until January 1, 2021 in connection with the 2017 Rate Case Settlement Agreement. 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 the statements of income.

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 as the hedged transactions are reflected in earnings.

• 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.

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Introduction (Tables)

9 Months Ended

Sep. 30, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Goodwill

At September 30, 2017 and December 31, 2016, goodwill was as follows:

	Goodwill
	At September 30, 2017		At December 31, 2016
	(in millions)
Southern Company	$	6,267	$	6,251
Southern Power	$	2	$	2
Southern Company Gas
Gas distribution operations	$	4,702	$	4,702
Gas marketing services	1,265		1,265
Southern Company Gas total	$	5,967	$	5,967

Schedule of Goodwill and Other Intangible Assets

Other intangible assets were as follows:

	At September 30, 2017							At December 31, 2016
	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	$	288	$	(70	)	$	218	$	268	$	(32	)	$	236
Trade names	159		(15		)	144		158		(5		)	153
Storage and transportation contracts	64		(27		)	37		64		(2		)	62
PPA fair value adjustments	456		(41		)	415		456		(22		)	434
Other	16		(3		)	13		11		(1		)	10
Total other intangible assets subject to amortization	$	983	$	(156	)	$	827	$	957	$	(62	)	$	895
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	$	75	$	—		$	75	$	75	$	—		$	75
Total other intangible assets	$	1,058	$	(156	)	$	902	$	1,032	$	(62	)	$	970
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	456	$	(41	)	$	415	$	456	$	(22	)	$	434
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	221	$	(65	)	$	156	$	221	$	(30	)	$	191
Trade names	115		(8		)	107		115		(2		)	113
Wholesale gas services
Storage and transportation contracts	64		(27		)	37		64		(2		)	62
Total other intangible assets subject to amortization	$	400	$	(100	)	$	300	$	400	$	(34	)	$	366

Finite-lived Intangible Assets Amortization Expense

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Nine Months Ended
	September 30, 2017
	(in millions)
Southern Company	$	29	$	94
Southern Power	$	6	$	19
Southern Company Gas	$	20	$	66

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Contingencies and Regulatory Matters (Tables)

9 Months Ended

Sep. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Revised Cost and Schedule

	Cancellation Cost Estimate
	(in billions)
CWIP as of September 30, 2017	$	4.6
Financing costs collected, net of tax	1.5
Cancellation costs(*)	0.4
Guarantee Obligations	(1.7		)
Estimated net cancellation cost	$	4.8

(*) The estimate for cancellation costs includes, but is not limited to, costs to terminate contracts for construction and other services, as well as costs to secure the Plant Vogtle Units 3 and 4 construction site.

Georgia Power's approximate proportionate share of the remaining estimated cost to complete Plant Vogtle Units 3 and 4 is as follows:

	(in billions)
Estimated cost to complete	$	4.2
CWIP as of September 30, 2017	4.6
Guarantee Obligations	(1.7		)
Estimated capital costs	$	7.1
Vogtle Cost Settlement Agreement Revised Forecast	(5.7		)
Estimated net additional capital costs	$	1.4

Recovery Balance of Each Regulatory Clause

The balance of each regulatory clause recovery on the balance sheet follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2017		December 31, 2016
		(in millions)
Rate CNP Compliance	Deferred over recovered regulatory clause revenues	$	9	$	—
Rate CNP Compliance(*)	Deferred under recovered regulatory clause revenues	—		9
Rate CNP PPA	Deferred under recovered regulatory clause revenues	17		142
Retail Energy Cost Recovery(*)	Other regulatory liabilities, current	—		76
Natural Disaster Reserve	Other regulatory liabilities, deferred	51		69

(*) In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified $36 million of its under recovered balance for Rate CNP Compliance and $11 million of its under recovered balance for Retail Energy Cost Recovery to a deferred regulatory asset account.

The balance of each regulatory clause recovery on the balance sheet follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2017		December 31, 2016
		(in millions)
Fuel Cost Recovery	Under recovered regulatory clause revenues	$	13	$	—
Fuel Cost Recovery	Other regulatory liabilities, current	—		15
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	1		—
Environmental Cost Recovery	Other regulatory liabilities, current	1		—
Environmental Cost Recovery	Under recovered regulatory clause revenues	—		13
Energy Conservation Cost Recovery	Under recovered regulatory clause revenues	1		4

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Assets and Liabilities Measured at Fair Value on a Recurring Basis

As of September 30, 2017, 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, 2017:	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)	$	231	$	184	$	—	$	—	$	415
Interest rate derivatives	—		5		—		—		5
Foreign currency derivatives	—		103		—		—		103
Nuclear decommissioning trusts(c)	752		1,004		—		26		1,782
Cash equivalents	1,271		—		—		—		1,271
Other investments	9		—		1		—		10
Total	$	2,263	$	1,296	$	1	$	26	$	3,586
Liabilities:
Energy-related derivatives(a)(b)	$	265	$	146	$	—	$	—	$	411
Interest rate derivatives	—		24		—		—		24
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		20		—		20
Total	$	265	$	193	$	20	$	—	$	478
Alabama Power
Assets:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9
Nuclear decommissioning trusts:(d)
Domestic equity	422		81		—		—		503
Foreign equity	60		57		—		—		117
U.S. Treasury and government agency securities	—		27		—		—		27
Corporate bonds	19		150		—		—		169
Mortgage and asset backed securities	—		18		—		—		18
Private Equity	—		—		—		26		26
Other	—		8		—		—		8
Cash equivalents	808		—		—		—		808
Total	$	1,309	$	350	$	—	$	26	$	1,685
Liabilities:
Energy-related derivatives	$	—	$	7	$	—	$	—	$	7

	Fair Value Measurements Using:
As of September 30, 2017:	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)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	18	$	—	$	—	$	18
Interest rate derivatives	—		1		—		—		1
Nuclear decommissioning trusts:(d) (e)
Domestic equity	235		1		—		—		236
Foreign equity	—		156		—		—		156
U.S. Treasury and government agency securities	—		225		—		—		225
Municipal bonds	—		64		—		—		64
Corporate bonds	—		160		—		—		160
Mortgage and asset backed securities	—		38		—		—		38
Other	16		19		—		—		35
Cash equivalents	112		—		—		—		112
Total	$	363	$	682	$	—	$	—	$	1,045
Liabilities:
Energy-related derivatives	$	—	$	11	$	—	$	—	$	11
Interest rate derivatives	—		3		—		—		3
Total	$	—	$	14	$	—	$	—	$	14
Gulf Power
Assets:
Cash equivalents	$	21	$	—	$	—	$	—	$	21
Liabilities:
Energy-related derivatives	$	—	$	22	$	—	$	—	$	22
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Interest rate derivatives	—		2		—		—		2
Cash equivalents	209		—		—		—		209
Total	$	209	$	5	$	—	$	—	$	214
Liabilities:
Energy-related derivatives	$	—	$	7	$	—	$	—	$	7

	Fair Value Measurements Using:
As of September 30, 2017:	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 Power
Assets:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9
Foreign currency derivatives	—		103		—		—		103
Cash equivalents	90		—		—		—		90
Total	$	90	$	112	$	—	$	—	$	202
Liabilities:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		20		—		20
Total	$	—	$	27	$	20	$	—	$	47
Southern Company Gas
Assets:
Energy-related derivatives(a)(b)	$	231	$	145	$	—	$	—	$	376
Liabilities:
Energy-related derivatives(a)(b)	$	265	$	95	$	—	$	—	$	360

(a) Excludes $13 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value.

(b) Excludes cash collateral of $76 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, 2017, approximately $66 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.

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, 2017, the fair value measurements of private equity investments held in the nuclear decommissioning trust 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, 2017:	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company	$	26	$	24	Not Applicable	Not Applicable
Alabama Power	$	26	$	24	Not Applicable	Not Applicable

Financial Instruments for Which Carrying Amount Did Not Equal Fair Value

As of September 30, 2017, 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	$	47,269	$	49,348
Alabama Power	$	7,404	$	8,031
Georgia Power	$	11,713	$	12,237
Gulf Power	$	1,292	$	1,352
Mississippi Power	$	2,123	$	2,117
Southern Power	$	5,810	$	5,916
Southern Company Gas	$	5,862	$	6,230

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Stockholders' Equity (Tables)

9 Months Ended

Sep. 30, 2017

Equity [Abstract]

Earnings per Share

Shares used to compute diluted earnings per share were as follows:

	Three Months Ended September 30, 2017	Three Months Ended September 30, 2016	Nine Months Ended September 30, 2017	Nine Months Ended September 30, 2016
	(in millions)
As reported shares	1,003	968	998	940
Effect of options and performance share award units	7	7	7	5
Diluted shares	1,010	975	1,005	945

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(*)
	(in thousands)			(in millions)
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
Balance at December 31, 2015	915,073	(3,352	)	$	20,592		$	609		$	781		$	21,982
Consolidated net income attributable to Southern Company	—	—		2,251			—			—			2,251
Other comprehensive income (loss)	—	—		(95		)	—			—			(95		)
Stock issued	65,725	2,599		3,265			—			—			3,265
Stock-based compensation	—	—		94			—			—			94
Cash dividends on common stock	—	—		(1,553		)	—			—			(1,553		)
Contributions from noncontrolling interests	—	—		—			—			357			357
Distributions to noncontrolling interests	—	—		—			—			(21		)	(21		)
Purchase of membership interests from noncontrolling interests	—	—		—			—			(129		)	(129		)
Net income attributable to noncontrolling interests	—	—		—			—			36			36
Other	—	(46	)	(7		)	—			—			(7		)
Balance at September 30, 2016	980,798	(799	)	$	24,547		$	609		$	1,024		$	26,180

(*) Related to Southern Power Company and excludes redeemable noncontrolling interests. In April 2017, approximately $114 million was reclassified from redeemable noncontrolling interests to noncontrolling interests, included in stockholder's equity, due to the expiration of SunPower Corp's option to require Southern Power to purchase its membership interests in one of the solar partnerships. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

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Financing (Tables)

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Credit Arrangements by Company

The following table outlines the committed credit arrangements by company as of September 30, 2017:

	Expires														Executable Term Loans				Expires Within One Year
Company	2017		2018		2019		2020		2022		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)
Southern Company(a)	$	—	$	—	$	—	$	—	$	2,000	$	2,000	$	2,000	$	—	$	—	$	—	$	—
Alabama Power	—		35		—		500		800		1,335		1,335		—		—		—		35
Georgia Power	—		—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	30		195		25		30		—		280		280		45		—		—		40
Mississippi Power	100		—		—		—		—		100		100		—		—		—		100
Southern Power Company(b)	—		—		—		—		750		750		728		—		—		—		—
Southern Company Gas(c)	—		—		—		—		1,900		1,900		1,861		—		—		—		—
Other	—		30		—		—		—		30		30		20		—		20		10
Southern Company Consolidated	$	130	$	260	$	25	$	530	$	7,200	$	8,145	$	8,066	$	65	$	—	$	20	$	185

(a) Represents the Southern Company parent entity.

(b) Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $111 million has been used for letters of credit and $9 million remains unused at September 30, 2017.

(c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.2 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 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 2017:

Company	Senior Note Issuances		Senior Note Maturities and Redemptions		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions and Maturities(a)
	(in millions)
Southern Company(b)	$	300	$	400	$	—	$	500		$	400
Alabama Power	550		200		36		—			—
Georgia Power	1,350		450		65		370			13
Gulf Power	300		85		—		6			—
Mississippi Power	—		—		—		40			893
Southern Power	—		—		—		43			4
Southern Company Gas(c)	450		—		—		200			22
Other	—		—		—		—			12
Elimination(d)	—		—		—		(40		)	(599		)
Southern Company Consolidated	$	2,950	$	1,135	$	101	$	1,119		$	745

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

(b) Represents the Southern Company parent entity.

(c) The senior notes were issued by Southern Company Gas Capital and guaranteed by the Southern Company Gas parent entity. Other long-term debt issued represents first mortgage bonds issued by Nicor Gas.

(d) Includes intercompany loans from Southern Company to Mississippi Power and reductions in affiliate capital lease obligations at Georgia Power. These transactions are eliminated in Southern Company's Consolidated Financial Statements.

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Retirement Benefits (Tables)

9 Months Ended

Sep. 30, 2017

Retirement Benefits [Abstract]

Pension Plans and Postretirement Plans

Components of the net periodic benefit costs for the three and nine months ended September 30, 2017 and 2016 are presented in the following tables.

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended September 30, 2017
Service cost	$	73		$	15		$	19		$	3		$	4
Interest cost	114			25			34			5			5
Expected return on plan assets	(224		)	(49		)	(71		)	(10		)	(9		)
Amortization:
Prior service costs	3			1			—			—			—
Net (gain)/loss	41			10			15			2			1
Net periodic pension cost (income)	$	7		$	2		$	(3	)	$	—		$	1
Nine Months Ended September 30, 2017
Service cost	$	220		$	47		$	56		$	10		$	11
Interest cost	341			73			103			15			15
Expected return on plan assets	(673		)	(147		)	(212		)	(29		)	(29		)
Amortization:
Prior service costs	9			2			2			—			1
Net (gain)/loss	122			31			43			5			5
Net periodic pension cost (income)	$	19		$	6		$	(8	)	$	1		$	3
Three Months Ended September 30, 2016
Service cost	$	68		$	14		$	17		$	3		$	3
Interest cost	110			23			34			5			4
Expected return on plan assets	(203		)	(46		)	(64		)	(9		)	(9		)
Amortization:
Prior service costs	3			1			1			—			1
Net (gain)/loss	45			10			14			2			2
Net periodic pension cost	$	23		$	2		$	2		$	1		$	1
Nine Months Ended September 30, 2016
Service cost	$	192		$	43		$	52		$	9		$	9
Interest cost	311			71			102			14			14
Expected return on plan assets	(577		)	(138		)	(193		)	(26		)	(26		)
Amortization:
Prior service costs	10			2			4			1			1
Net (gain)/loss	120			30			41			5			5
Net periodic pension cost	$	56		$	8		$	6		$	3		$	3

Pension Plans	Southern Company Gas
	(in millions)
Successor – Three Months Ended September 30, 2017
Service cost	$	6
Interest cost	10
Expected return on plan assets	(18		)
Amortization of net (gain)/loss	5
Net periodic pension cost	$	3
Successor – Nine Months Ended September 30, 2017
Service cost	$	17
Interest cost	30
Expected return on plan assets	(53		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	15
Net periodic pension cost	$	8
Successor – July 1, 2016 through September 30, 2016
Service cost	$	7
Interest cost	10
Expected return on plan assets	(17		)
Amortization of regulatory asset	6
Net periodic pension cost	$	6
Predecessor – January 1, 2016 through June 30, 2016
Service cost	$	13
Interest cost	21
Expected return on plan assets	(33		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	13
Net periodic pension cost	$	13

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended September 30, 2017
Service cost	$	6		$	1		$	2		$	—		$	—
Interest cost	19			4			6			1			1
Expected return on plan assets	(16		)	(5		)	(6		)	—			—
Amortization:
Prior service costs	2			1			—			—			—
Net (gain)/loss	3			—			3			—			—
Net periodic postretirement benefit cost	$	14		$	1		$	5		$	1		$	1
Nine Months Ended September 30, 2017
Service cost	$	18		$	4		$	5		$	1		$	1
Interest cost	59			13			21			2			3
Expected return on plan assets	(49		)	(19		)	(18		)	(1		)	(1		)
Amortization:
Prior service costs	5			3			1			—			—
Net (gain)/loss	10			1			6			—			—
Net periodic postretirement benefit cost	$	43		$	2		$	15		$	2		$	3
Three Months Ended September 30, 2016
Service cost	$	6		$	1		$	2		$	—		$	—
Interest cost	20			5			7			1			—
Expected return on plan assets	(16		)	(6		)	(6		)	—			—
Amortization:
Prior service costs	1			1			—			—			—
Net (gain)/loss	5			—			3			—			1
Net periodic postretirement benefit cost	$	16		$	1		$	6		$	1		$	1
Nine Months Ended September 30, 2016
Service cost	$	17		$	4		$	5		$	1		$	1
Interest cost	55			14			22			2			2
Expected return on plan assets	(44		)	(19		)	(17		)	(1		)	(1		)
Amortization:
Prior service costs	4			3			1			—			—
Net (gain)/loss	12			1			7			—			1
Net periodic postretirement benefit cost	$	44		$	3		$	18		$	2		$	3

Postretirement Benefits	Southern Company Gas
	(in millions)
Successor – Three Months Ended September 30, 2017
Service cost	$	1
Interest cost	3
Expected return on plan assets	(2		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	1
Net periodic postretirement benefit cost	$	2
Successor – Nine Months Ended September 30, 2017
Service cost	$	2
Interest cost	8
Expected return on plan assets	(5		)
Amortization:
Prior service costs	(2		)
Net (gain)/loss	3
Net periodic postretirement benefit cost	$	6
Successor – July 1, 2016 through September 30, 2016
Service cost	$	1
Interest cost	2
Expected return on plan assets	(2		)
Amortization of regulatory asset	1
Net periodic postretirement benefit cost	$	2
Predecessor – January 1, 2016 through June 30, 2016
Service cost	$	1
Interest cost	5
Expected return on plan assets	(3		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	2
Net periodic postretirement benefit cost	$	4

XML

Income Taxes (Tables)

9 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

Summary of Valuation Allowance

At September 30, 2017, valuation allowances were as follows:

	Mississippi Power		Southern Company Gas		Southern Company
	(in millions)
Federal	$	—	$	18	$	18
State (net of federal benefit)	46		1		64
Balance at September 30, 2017	$	46	$	19	$	82

Change in Unrecognized Tax Benefits

Changes during the nine months ended September 30, 2017 for unrecognized tax benefits were as follows:

	Mississippi Power			Southern Power			Southern Company
	(in millions)
Unrecognized tax benefits as of December 31, 2016	$	465		$	17		$	484
Tax positions from current periods	2			—			9
Tax positions from prior periods	(175		)	(17		)	(186		)
Reductions due to settlements	(290		)	—			(290		)
Balance as of September 30, 2017	$	2		$	—		$	17

Impact on Effective Tax Rate, If Recognized

The impact on the effective tax rate, if recognized, is as follows:

	As of September 30, 2017				As of December 31, 2016
	Mississippi Power		Southern Company		Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	2	$	17	$	20
Tax positions not impacting the effective tax rate	—		—		464
Balance of unrecognized tax benefits	$	2	$	17	$	484

XML

Derivatives (Tables)

9 Months Ended

Sep. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Energy-Related Derivatives

At September 30, 2017, 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(*)	463	2021	2024
Alabama Power	66	2020	—
Georgia Power	159	2021	—
Gulf Power	28	2020	—
Mississippi Power	44	2021	—
Southern Power	13	2018	—
Southern Company Gas(*)	153	2020	2024

(*) 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 3.3 billion mmBtu and short natural gas positions of 3.1 billion mmBtu as of September 30, 2017, which is also included in Southern Company's total volume.

Schedule of Interest Rate Derivatives

At September 30, 2017, 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, 2017
	(in millions)					(in millions)
Cash Flow Hedges of Existing Debt
Mississippi Power	$	900	1-month LIBOR	0.79%	March 2018	$	2
Fair Value Hedges of Existing Debt
Southern Company(*)	300		2.75%	3-month LIBOR + 0.92%	June 2020	—
Southern Company(*)	1,500		2.35%	1-month LIBOR + 0.87%	July 2021	(19		)
Georgia Power	250		5.40%	3-month LIBOR + 4.02%	June 2018	—
Georgia Power	500		1.95%	3-month LIBOR + 0.76%	December 2018	(2		)
Georgia Power	200		4.25%	3-month LIBOR + 2.46%	December 2019	—
Southern Company Consolidated	$	3,650				$	(19	)

(*) Represents the Southern Company parent entity.

Schedule of Foreign Currency Derivatives

At September 30, 2017, 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, 2017
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	42
Southern Power	564		3.78%	500		1.85%	June 2026	38
Total	$	1,241		€	1,100			$	80

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, 2017						As of December 31, 2016
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	$	21		$	25		$	73		$	27
Other deferred charges and assets/Other deferred credits and liabilities	13			23			25			33
Total derivatives designated as hedging instruments for regulatory purposes	$	34		$	48		$	98		$	60
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	8		$	6		$	23		$	7
Interest rate derivatives:
Other current assets/Other current liabilities	5			1			12			1
Other deferred charges and assets/Other deferred credits and liabilities	—			23			1			28
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			25
Other deferred charges and assets/Other deferred credits and liabilities	103			—			—			33
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	116		$	53		$	36		$	94
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	271		$	254		$	489		$	483
Other deferred charges and assets/Other deferred credits and liabilities	115			103			66			81
Interest rate derivatives:
Other current assets/Other current liabilities	—			—			1			—
Total derivatives not designated as hedging instruments	$	386		$	357		$	556		$	564
Gross amounts recognized	$	536		$	458		$	690		$	718
Gross amounts offset(*)	$	(275	)	$	(351	)	$	(462	)	$	(524	)
Net amounts recognized in the Balance Sheets	$	261		$	107		$	228		$	194

	As of September 30, 2017						As of December 31, 2016
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	$	6		$	4		$	13		$	5
Other deferred charges and assets/Other deferred credits and liabilities	3			3			7			4
Total derivatives designated as hedging instruments for regulatory purposes	$	9		$	7		$	20		$	9
Gross amounts recognized	$	9		$	7		$	20		$	9
Gross amounts offset	$	(5	)	$	(5	)	$	(8	)	$	(8	)
Net amounts recognized in the Balance Sheets	$	4		$	2		$	12		$	1
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	10		$	3		$	30		$	1
Other deferred charges and assets/Other deferred credits and liabilities	8			8			14			7
Total derivatives designated as hedging instruments for regulatory purposes	$	18		$	11		$	44		$	8
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	1		$	1		$	2		$	—
Other deferred charges and assets/Other deferred credits and liabilities	—			2			—			3
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	1		$	3		$	2		$	3
Gross amounts recognized	$	19		$	14		$	46		$	11
Gross amounts offset	$	(10	)	$	(10	)	$	(8	)	$	(8	)
Net amounts recognized in the Balance Sheets	$	9		$	4		$	38		$	3
Gulf Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	—		$	13		$	4		$	12
Other deferred charges and assets/Other deferred credits and liabilities	—			9			1			17
Total derivatives designated as hedging instruments for regulatory purposes	$	—		$	22		$	5		$	29
Gross amounts recognized	$	—		$	22		$	5		$	29
Gross amounts offset	$	—		$	—		$	(4	)	$	(4	)
Net amounts recognized in the Balance Sheets	$	—		$	22		$	1		$	25

	As of September 30, 2017						As of December 31, 2016
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	4		$	2		$	6
Other deferred charges and assets/Other deferred credits and liabilities	2			3			2			5
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	7		$	4		$	11
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	2		$	—		$	2		$	—
Other deferred charges and assets/Other deferred credits and liabilities	—			—			1			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	2		$	—		$	3		$	—
Gross amounts recognized	$	5		$	7		$	7		$	11
Gross amounts offset	$	(3	)	$	(3	)	$	(3	)	$	(3	)
Net amounts recognized in the Balance Sheets	$	2		$	4		$	4		$	8
Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	8		$	4		$	18		$	4
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			25
Other deferred charges and assets/Other deferred credits and liabilities	103			—			—			33
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	111		$	27		$	18		$	62
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	—		$	3		$	1
Interest rate derivatives:
Other current assets/Other current liabilities	—			—			1			—
Total derivatives not designated as hedging instruments	$	1		$	—		$	4		$	1
Gross amounts recognized	$	112		$	27		$	22		$	63
Gross amounts offset	$	(1	)	$	(1	)	$	(5	)	$	(5	)
Net amounts recognized in the Balance Sheets	$	111		$	26		$	17		$	58

	As of September 30, 2017						As of December 31, 2016
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	$	4		$	1		$	24		$	3
Other deferred charges and assets/Other deferred credits and liabilities	—			—			1			—
Total derivatives designated as hedging instruments for regulatory purposes	$	4		$	1		$	25		$	3
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	$	—		$	2		$	4		$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	270		$	254		$	486		$	482
Other deferred charges and assets/Other deferred credits and liabilities	115			103			66			81
Total derivatives not designated as hedging instruments	$	385		$	357		$	552		$	563
Gross amounts of recognized	$	389		$	360		$	581		$	569
Gross amounts offset(*)	$	(251	)	$	(327	)	$	(435	)	$	(497	)
Net amounts recognized in the Balance Sheets	$	138		$	33		$	146		$	72

(*) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $76 million and $62 million as of September 30, 2017 and December 31, 2016, respectively.

Pre-tax Effects of Unrealized Derivative Gains (Losses) Arising from Energy-Related Derivative Instruments

At September 30, 2017 and December 31, 2016, 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, 2017
Derivative Category and Balance Sheet Location	Southern Company(b)			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas(c)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(18	)	$	(1	)	$	—		$	(13	)	$	(3	)	$	(1	)
Other regulatory assets, deferred	(12		)	(1		)	(1		)	(9		)	(1		)	—
Other regulatory liabilities, current(a)	14			3			7			—			—			4
Other regulatory liabilities, deferred(b)	2			1			1			—			—			—
Total energy-related derivative gains (losses)	$	(14	)	$	2		$	7		$	(22	)	$	(4	)	$	3

(a) Georgia Power includes other regulatory liabilities, current in other current liabilities.

(b) Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.

(c) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $1 million at September 30, 2017.

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2016
Derivative Category and Balance Sheet Location	Southern Company(c)			Alabama Power			Georgia Power		Gulf Power			Mississippi Power			Southern Company Gas(c)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(16	)	$	(1	)	$	—	$	(9	)	$	(5	)	$	(1	)
Other regulatory assets, deferred	(19		)	—			—		(16		)	(3		)	—
Other regulatory liabilities, current(a)	56			8			29		1			1			17
Other regulatory liabilities, deferred(b)	12			4			7		—			—			1
Total energy-related derivative gains (losses)	$	33		$	11		$	36	$	(24	)	$	(7	)	$	17

(a) Georgia Power includes other regulatory liabilities, current in other current liabilities.

(b) Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.

(c) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $8 million at December 31, 2016.

Pre-tax Effects of Interest Rate Derivatives, Designated as Cash Flow Hedging Instruments

For the three months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments were as follows:

Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)						Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
							Statements of Income Location	Amount
	2017			2016				2017			2016
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	(6	)	$	—		Depreciation and amortization	$	(6	)	$	1
Interest rate derivatives	(1		)	(6		)	Interest expense, net of amounts capitalized	(5		)	(6		)
Foreign currency derivatives	46			37			Interest expense, net of amounts capitalized	(5		)	(6		)
							Other income (expense), net(*)	43			7
Total	$	39		$	31			$	27		$	(4	)
Alabama Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(2	)	$	(2	)
Georgia Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Mississippi Power
Interest rate derivatives	$	(1	)	$	(1	)	Interest expense, net of amounts capitalized	$	—		$	—
Southern Power
Energy-related derivatives	$	(6	)	$	—		Depreciation and amortization	$	(6	)	$	1
Foreign currency derivatives	46			37			Interest expense, net of amounts capitalized	(5		)	(6		)
							Other income (expense), net(*)	43			7
Total	$	40		$	37			$	32		$	2
Southern Company Gas
Interest rate derivatives	$	—		$	(5	)	Interest expense, net of amounts capitalized	$	—		$	—

(*) 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 nine months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments were as follows:

Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)						Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
							Statements of Income Location	Amount
	2017			2016				2017			2016
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	(26	)	$	(1	)	Depreciation and amortization	$	(12	)	$	1
Interest rate derivatives	(2		)	(189		)	Interest expense, net of amounts capitalized	(15		)	(13		)
Foreign currency derivatives	114			(1		)	Interest expense, net of amounts capitalized	(17		)	(7		)
							Other income (expense), net(*)	139			(13		)
Total	$	86		$	(191	)		$	95		$	(32	)
Alabama Power
Interest rate derivatives	$	—		$	(3	)	Interest expense, net of amounts capitalized	$	(5	)	$	(5	)
Georgia Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(3	)	$	(3	)
Gulf Power
Energy-related derivatives	$	(1	)	$	—		Depreciation and amortization	$	—		$	—
Interest rate derivatives	(1		)	(7		)	Interest expense, net of amounts capitalized	—			—
Total	$	(2	)	$	(7	)		$	—		$	—
Mississippi Power
Interest rate derivatives	$	—		$	(1	)	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Southern Power
Energy-related derivatives	$	(21	)	$	(1	)	Depreciation and amortization	$	(12	)	$	1
Interest rate derivatives	—			—			Interest expense, net of amounts capitalized	—			(1		)
Foreign currency derivatives	114			(1		)	Interest expense, net of amounts capitalized	(17		)	(7		)
							Other income (expense), net(*)	139			(13		)
Total	$	93		$	(2	)		$	110		$	(20	)

(*) 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 Southern Company Gas, the pre-tax effect of energy related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings for the successor nine months ended September 30, 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016 were as follows:

	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)				Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
Derivatives in Cash Flow Hedging Relationships	Nine Months Ended September 30, 2017			Statements of Income Location	Nine Months Ended September 30, 2017
	(in millions)				(in millions)
Energy-related derivatives	$	(4	)	Cost of natural gas	$	—

	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)							Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
	Successor			Predecessor				Successor		Predecessor
Derivatives in Cash Flow Hedging Relationships	July 1, 2016 through September 30, 2016			January 1, 2016 through June 30, 2016			Statements of Income Location	July 1, 2016 through September 30, 2016		January 1, 2016 through June 30, 2016
	(in millions)			(in millions)				(in millions)		(in millions)
Energy-related derivatives	$	—		$	—		Cost of natural gas	$	—	$	(1	)
Interest rate derivatives	(5		)	(64		)	Interest expense, net of amounts capitalized	—		—
Total	$	(5	)	$	(64	)		$	—	$	(1	)

Pre-tax Effect of Interest Rate and Energy Related Derivatives

For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments on the statements of income 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	2017			2016		2017			2016
		(in millions)					(in millions)
Southern Company
Energy Related derivatives:	Natural gas revenues(*)	$	(17	)	$	—	$	48		$	—
	Cost of natural gas	2			6		(2		)	6
Total derivatives in non-designated hedging relationships		$	(15	)	$	6	$	46		$	6

(*) Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $15 million for the nine months ended September 30, 2017 and immaterial amounts for all other periods presented.

		Gain (Loss)
		Successor			Successor		Successor			Successor		Predecessor
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	Three Months Ended September 30, 2017			Three Months Ended September 30, 2016		Nine Months Ended September 30, 2017			July 1, 2016 through September 30, 2016		January 1, 2016 through June 30, 2016
		(in millions)			(in millions)		(in millions)			(in millions)
Southern Company Gas
Energy Related derivatives:	Natural gas revenues(*)	$	(17	)	$	—	$	48		$	—	$	(1	)
	Cost of natural gas	2			6		(2		)	6		(62		)
Total derivatives in non-designated hedging relationships		$	(15	)	$	6	$	46		$	6	$	(63	)

(*) Excludes gains recorded in cost of natural gas associated with weather derivatives of $15 million for the successor nine months ended September 30, 2017 and immaterial amounts for all other periods presented.

Pre-tax Effects of Interest Rate Derivatives, Designated as Fair Value Hedging Instruments

For the three and nine months ended September 30, 2017 and 2016, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:

Derivatives in Fair Value Hedging Relationships
		Gain (Loss)
		Three Months Ended September 30,						Nine Months Ended September 30,
Derivative Category	Statements of Income Location	2017			2016			2017			2016
		(in millions)						(in millions)
Southern Company
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	(5	)	$	(9	)	$	(6	)	$	15
Georgia Power
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	—		$	(5	)	$	(1	)	$	10

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Acquisitions and Dispositions (Tables)

9 Months Ended

Sep. 30, 2017

Business Combinations [Abstract]

Schedule of Business Acquisitions

The following table presents the final purchase price allocation:

PowerSecure Purchase Price
	(in millions)
Current assets	$	172
Property, plant, and equipment	46
Intangible assets	106
Goodwill	284
Other assets	4
Current liabilities	(121		)
Long-term debt, including current portion	(48		)
Deferred credits and other liabilities	(14		)
Total purchase price	$	429

The following table presents the final purchase price allocation:

Southern Company Gas Purchase Price
	(in millions)
Current assets	$	1,557
Property, plant, and equipment	10,108
Goodwill	5,967
Intangible assets	400
Regulatory assets	1,118
Other assets	229
Current liabilities	(2,201		)
Other liabilities	(4,742		)
Long-term debt	(4,261		)
Noncontrolling interest	(174		)
Total purchase price	$	8,001

During the nine months ended September 30, 2017, in accordance with Southern Power's overall growth strategy, one of Southern Power's wholly-owned subsidiaries acquired the project discussed below. 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
Bethel	Wind	Invenergy, January 6, 2017	276	Castro County, TX	100	%	January 2017	12 years

Business Acquisition, Pro Forma Information

The following summarized unaudited pro forma consolidated statement of earnings information assumes that the acquisition of Southern Company Gas was completed on January 1, 2015. The summarized unaudited pro forma consolidated statement of earnings information includes adjustments for (i) intercompany sales, (ii) amortization of intangible assets, (iii) adjustments to interest expense to reflect current interest rates on Southern Company Gas debt and additional interest expense associated with borrowings by Southern Company to fund the Merger, and (iv) the elimination of nonrecurring expenses associated with the Merger.

	For the Nine Months Ended September 30,
	2016
Operating revenues (in millions)	$	16,609
Net income attributable to Southern Company (in millions)	$	2,394
Basic Earnings Per Share (EPS)	$	2.52
Diluted EPS	$	2.51

Schedule of Construction Projects

During the nine months ended September 30, 2017, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through September 30, 2017, total costs of construction incurred for these projects were $494 million, of which $122 million remained in CWIP. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $360 million and $415 million for the Mankato and Cactus Flats facilities. The ultimate outcome of these matters cannot be determined at this time.

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Projects Completed During the Nine Months Ended September 30, 2017
East Pecos	Solar	120	Pecos County, TX	March 2017	15 years
Lamesa	Solar	102	Dawson County, TX	April 2017	15 years
Projects Under Construction as of September 30, 2017
Cactus Flats(*)	Wind	148	Concho County, TX	Third quarter 2018	12-15 years
Mankato	Natural Gas	345	Mankato, MN	Second quarter 2019	20 years

(*) On July 31, 2017, Southern Power acquired a 100% ownership interest in the Cactus Flats facility, which is in the early stages of construction, from RES America Developments, Inc.

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Joint Ownership Agreements (Tables)

9 Months Ended

Sep. 30, 2017

Regulated Operations [Abstract]

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments as of September 30, 2017 and December 31, 2016 and related income from those investments for the successor three and nine month periods ended September 30, 2017, the successor three-month period ended September 30, 2016, and for the predecessor period January 1, 2016 through June 30, 2016 were as follows:

Balance Sheet Information	September 30, 2017		December 31, 2016
	(in millions)
SNG	$	1,385	$	1,394
Atlantic Coast Pipeline	61		33
PennEast Pipeline	49		22
Triton	43		44
Pivotal JAX LNG, LLC	40		16
Horizon Pipeline	30		30
Other	1		2
Total	$	1,609	$	1,541

Selected financial information of SNG for the three and nine months ended September 30, 2017 and for the period September 1, 2016 through September 30, 2016 is as follows:

Income Statement Information	Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017		September 1, 2016 through September 30, 2016
	(in millions)
Revenues	$	146	$	445	$	82
Operating income	$	71	$	218	$	60
Net income	$	57	$	172	$	55

Schedule of Other Nonoperating Income, by Component

	Successor		Successor		Successor		Predecessor
Income Statement Information	Three Months Ended September 30, 2017		Three Months Ended September 30, 2016		Nine Months Ended September 30, 2017		January 1, 2016 through June 30, 2016
	(in millions)		(in millions)		(in millions)		(in millions)
SNG	$	28	$	27	$	86	$	—
PennEast Pipeline	1		—		5		—
Atlantic Coast Pipeline	1		1		4		—
Triton	1		1		3		1
Horizon Pipeline	1		—		2		1
Total	$	32	$	29	$	100	$	2

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Segment and Related Information (Tables)

9 Months Ended

Sep. 30, 2017

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, 2017 and 2016 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, 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)(c)	—		276		—			276		303		(232		)	—			347
Total assets at September 30, 2017	$	73,056	$	14,648	$	(322	)	$	87,382	$	22,190	$	2,275		$	(1,532	)	$	110,315
Three Months Ended September 30, 2016:
Operating revenues	$	5,236	$	500	$	(117	)	$	5,619	$	543	$	139		$	(37	)	$	6,264
Segment net income (loss)(a)(b)	1,022		176		—			1,198		4		(62		)	(1		)	1,139
Nine Months Ended September 30, 2016:
Operating revenues	$	13,120	$	1,189	$	(330	)	$	13,979	$	543	$	311		$	(118	)	$	14,715
Segment net income (loss)(a)(b)	2,086		315		—			2,401		4		(146		)	(8		)	2,251
Total assets at December 31, 2016	$	72,141	$	15,169	$	(316	)	$	86,994	$	21,853	$	2,474		$	(1,624	)	$	109,697

(a) Attributable to Southern Company.

(b) Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $34 million ($21 million after tax) and $88 million ($54 million after tax) for the three months ended September 30, 2017 and 2016, respectively, and $3.2 billion ($2.2 billion after tax) and $222 million ($137 million after tax) for the nine months ended September 30, 2017 and 2016, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.

(c) Segment net income (loss) for the traditional electric operating companies also 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 (B) under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information.

Business segment financial data for the successor three months ended September 30, 2017 and 2016, the successor nine months ended September 30, 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through June 30, 2016 was as follows:

	Gas Distribution Operations		Gas Marketing Services		Wholesale Gas Services(*)			Gas Midstream Operations		Total		All Other			Eliminations			Consolidated
	(in millions)
Successor – Three Months Ended September 30, 2017:
Operating revenues	$	472	$	143	$	(24	)	$	16	$	607	$	2		$	(44	)	$	565
Segment net income	52		1		(23		)	14		44		(29		)	—			15
Successor – Nine Months Ended September 30, 2017:
Operating revenues	$	2,255	$	597	$	95		$	53	$	3,000	$	7		$	(166	)	$	2,841
Segment net income	223		36		28			38		325		(22		)	—			303
Successor – Total assets at September 30, 2017	$	18,711	$	2,089	$	893		$	2,359	$	24,052	$	11,400		$	(13,262	)	$	22,190

	Gas Distribution Operations		Gas Marketing Services			Wholesale Gas Services(*)			Gas Midstream Operations			Total		All Other			Eliminations			Consolidated
	(in millions)
Successor – Three Months Ended September 30, 2016:
Operating revenues	$	455	$	126		$	(8	)	$	13		$	586	$	2		$	(45	)	$	543
Segment net income (loss)	27		(4		)	(11		)	14			26		(22		)	—			4
Predecessor – January 1, 2016 through June 30, 2016:
Operating revenues	$	1,575	$	435		$	(32	)	$	25		$	2,003	$	4		$	(102	)	$	1,905
Segment EBIT	353		109			(68		)	(6		)	388		(60		)	—			328
Successor – Total assets at December 31, 2016	$	19,453	$	2,084		$	1,127		$	2,211		$	24,875	$	11,145		$	(14,167	)	$	21,853

(*) 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)
Successor – Three Months Ended September 30, 2017	$	1,411	$	103	$	1,514	$	1,538	$	(24	)
Successor – Nine Months Ended September 30, 2017	4,781		362		5,143		5,048		95
Successor – Three Months Ended September 30, 2016	1,688		77		1,765		1,773		(8		)
Predecessor – January 1, 2016 through June 30, 2016	$	2,500	$	143	$	2,643	$	2,675	$	(32	)

Financial Data for Products and Services

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2017	$	4,615	$	718	$	190	$	5,523
Three Months Ended September 30, 2016	4,808		613		198		5,619
Nine Months Ended September 30, 2017	$	11,786	$	1,867	$	586	$	14,239
Nine Months Ended September 30, 2016	11,932		1,455		592		13,979

	Southern Company Gas' Revenues
Period	Gas Distribution Operations		Gas Marketing Services		Other			Total
	(in millions)
Three Months Ended September 30, 2017	$	430	$	143	$	(8	)	$	565
Nine Months Ended September 30, 2017	$	2,119	$	597	$	125		$	2,841
Three and Nine Months Ended September 30, 2016	$	420	$	126	$	(3	)	$	543

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Introduction - Narrative (Details)			3 Months Ended		6 Months Ended	9 Months Ended
	Apr. 04, 2017 USD ($)	Apr. 01, 2017	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Sep. 30, 2017 USD ($) kWh
GEORGIA POWER CO
Related Party Transaction [Line Items]
Property damage reserve, percentage of balance		0.75
GULF POWER CO
Related Party Transaction [Line Items]
PSC approved annual property damage reserve accrual	$ 3,500,000
Number of agreements for renewable generation	0		$ 39,000,000			$ 39,000,000
Increase (decrease) in recoverable property damage costs	$ 31,000,000
Recovery period for natural disaster reserve costs						60 days
Cumulative costs limit under PSC order						$ 100,000,000
Accrued storm reserve damaged property costs			40,000,000			40,000,000
SOUTHERN Co GAS | GEORGIA POWER CO
Related Party Transaction [Line Items]
Related party transactions				$ 7,000,000		18,000,000
SOUTHERN Co GAS | SOUTHERN POWER CO
Related Party Transaction [Line Items]
Related party transactions				2,000,000		94,000,000
Southern Natural Gas Company, LLC | SOUTHERN Co GAS
Related Party Transaction [Line Items]
Related party transactions				4,000,000		24,000,000
Southern Natural Gas Company, LLC | ALABAMA POWER CO
Related Party Transaction [Line Items]
Related party transactions				1,000,000		8,000,000
Southern Natural Gas Company, LLC | GEORGIA POWER CO
Related Party Transaction [Line Items]
Related party transactions				8,000,000		77,000,000
Southern Natural Gas Company, LLC | SOUTHERN POWER CO
Related Party Transaction [Line Items]
Related party transactions				2,000,000		19,000,000
Maximum | GULF POWER CO
Related Party Transaction [Line Items]
Customer surcharge storm recovery costs						$ 4.00
Customer surcharge storm recovery capacity | kWh						1,000
Wholesale Gas Services | SOUTHERN Co GAS
Related Party Transaction [Line Items]
Inventory decrement			0			$ 0
Inventory write-down			$ 0	$ 0		$ 0
Predecessor | Wholesale Gas Services | SOUTHERN Co GAS
Related Party Transaction [Line Items]
Inventory write-down					$ 0

XML

Introduction - Goodwill (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Goodwill [Line Items]
Goodwill	$ 6,267	$ 6,251
SOUTHERN POWER CO
Goodwill [Line Items]
Goodwill	2	2
SOUTHERN Co GAS
Goodwill [Line Items]
Goodwill	5,967	5,967
SOUTHERN Co GAS | Gas distribution operations
Goodwill [Line Items]
Goodwill	4,702	4,702
SOUTHERN Co GAS | Gas marketing services
Goodwill [Line Items]
Goodwill	$ 1,265	$ 1,265

XML

Introduction - Other Intangibles (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 983	$ 957
Accumulated Amortization	(156)	(62)
Other Intangible Assets, Net	827	895
Total other intangible assets - gross	1,058	1,032
Total other intangible assets - net	902	970
Customer relationships | Southern Company
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	288	268
Accumulated Amortization	(70)	(32)
Other Intangible Assets, Net	218	236
Trade names | Southern Company
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	159	158
Accumulated Amortization	(15)	(5)
Other Intangible Assets, Net	144	153
Storage and transportation contracts | Southern Company
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	64	64
Accumulated Amortization	(27)	(2)
Other Intangible Assets, Net	37	62
PPA fair value adjustments | Southern Company
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	456	456
Accumulated Amortization	(41)	(22)
Other Intangible Assets, Net	415	434
Other | Southern Company
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	16	11
Accumulated Amortization	(3)	(1)
Other Intangible Assets, Net	13	10
Federal Communications Commission licenses | Southern Company
Indefinite-lived Intangible Assets [Line Items]
Other intangible assets not subject to amortization	75	75
SOUTHERN POWER CO
Indefinite-lived Intangible Assets [Line Items]
Accumulated Amortization	(41)	(22)
SOUTHERN POWER CO | PPA fair value adjustments
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	456	456
Accumulated Amortization	(41)	(22)
Other Intangible Assets, Net	415	434
SOUTHERN Co GAS
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	400	400
Accumulated Amortization	(100)	(34)
Other Intangible Assets, Net	300	366
Total other intangible assets - net	300	366
SOUTHERN Co GAS | Customer relationships
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	221	221
Accumulated Amortization	(65)	(30)
Other Intangible Assets, Net	156	191
SOUTHERN Co GAS | Trade names
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	115	115
Accumulated Amortization	(8)	(2)
Other Intangible Assets, Net	107	113
SOUTHERN Co GAS | Storage and transportation contracts
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	64	64
Accumulated Amortization	(27)	(2)
Other Intangible Assets, Net	$ 37	$ 62

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Introduction - Intangibles, Amortization (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2017
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 29	$ 94
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	$ 20	$ 66

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Contingencies and Regulatory Matters - Narrative (Details)																				1 Months Ended		3 Months Ended		6 Months Ended	9 Months Ended		12 Months Ended										38 Months Ended	48 Months Ended	96 Months Ended	105 Months Ended
	Nov. 01, 2017 USD ($)	Oct. 23, 2017 USD ($)	Oct. 03, 2017 USD ($)	Oct. 02, 2017 USD ($)	Aug. 21, 2017 USD ($)	Aug. 15, 2017	Jul. 01, 2017	Jun. 30, 2017 USD ($)	Jun. 09, 2017 USD ($)	May 04, 2017 USD ($)	Apr. 04, 2017 intervenor	Mar. 31, 2017 USD ($)	Mar. 27, 2017	Mar. 10, 2017 USD ($)	Feb. 21, 2017 USD ($)	Dec. 20, 2016 USD ($)	May 01, 2016 USD ($)	Mar. 31, 2016	Jan. 01, 2016	Sep. 30, 2016 USD ($)	Jan. 31, 2016 USD ($)	Sep. 30, 2017 USD ($) MW	Sep. 30, 2016 USD ($)	Jun. 30, 2017 USD ($)	Sep. 30, 2017 USD ($) clause MW	Sep. 30, 2016 USD ($)	Dec. 31, 2018 USD ($)	Aug. 31, 2018	Dec. 31, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2008 USD ($)	Jun. 30, 2017 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2016 USD ($)	Sep. 30, 2017 USD ($) MW	Jan. 01, 2121	Sep. 28, 2017 USD ($)	Jul. 06, 2017 USD ($)	Jun. 23, 2017 USD ($)	May 31, 2017 USD ($)	Mar. 07, 2017 USD ($)	Feb. 17, 2017 USD ($)	Aug. 31, 2016 USD ($)
Loss Contingencies [Line Items]
Lawsuit deferral period						30 days							30 days
Maximum borrowing capacity																						$ 8,145,000,000			$ 8,145,000,000															$ 8,145,000,000
Stockholders' equity, including portion attributable to noncontrolling interest																				$ (26,180,000,000)		(25,939,000,000)	$ (26,180,000,000)		(25,939,000,000)	$ (26,180,000,000)					$ (26,612,000,000)	$ (21,982,000,000)							$ (26,612,000,000)	(25,939,000,000)
Property, plant and equipment, gross																						102,014,000,000			102,014,000,000						98,416,000,000								98,416,000,000	102,014,000,000
SOUTHERN POWER CO
Loss Contingencies [Line Items]
Maximum borrowing capacity																						750,000,000			750,000,000															750,000,000					$ 600,000,000
Stockholders' equity, including portion attributable to noncontrolling interest																						(5,843,000,000)			(5,843,000,000)						(5,675,000,000)								(5,675,000,000)	(5,843,000,000)
Wholesale revenues, non-affiliates																						510,000,000	387,000,000		1,293,000,000	866,000,000
Property, plant and equipment, gross																						13,734,000,000			13,734,000,000						12,728,000,000								12,728,000,000	13,734,000,000
GEORGIA POWER CO
Loss Contingencies [Line Items]
Environmental remediation liability																						26,000,000			$ 26,000,000						17,000,000								17,000,000	26,000,000
Cost recovery, new nuclear																																														$ (50,000,000)
Percentage of Proportionate share owed in consortium agreement																																				45.70%
Liquidated damages, percentage																									40.00%											10.00%
Maximum borrowing capacity																						1,750,000,000			$ 1,750,000,000															1,750,000,000
Estimated in-service capital cost																																			$ 4,418,000,000
Financing costs collected, net of tax																									1,500,000,000
Additional construction capital costs																$ 3,300,000,000								$ 542,000,000															3,900,000,000
Estimate of possible loss																$ 240,000,000
Retail rate of return on common equity																																		10.95%
Public utilities, approved return on equity percentage																			10.00%
Financing costs incurred																																								1,500,000,000
Estimated cancellation costs																																								350,000,000
Wholesale revenues, non-affiliates																						45,000,000	49,000,000		124,000,000	131,000,000
Property, plant and equipment, gross																						34,589,000,000			34,589,000,000						33,841,000,000								33,841,000,000	34,589,000,000
GEORGIA POWER CO | Minimum
Loss Contingencies [Line Items]
Estimated financing costs																																								3,400,000,000
GEORGIA POWER CO | Other current liabilities
Loss Contingencies [Line Items]
Over recovered fuel balance																						100,000,000			100,000,000															100,000,000
GEORGIA POWER CO | Other deferred credits and liabilities
Loss Contingencies [Line Items]
Over recovered fuel balance																															84,000,000								84,000,000
GULF POWER CO
Loss Contingencies [Line Items]
Environmental remediation liability																						53,000,000			53,000,000						44,000,000								44,000,000	53,000,000
Accrued storm reserve damaged property costs																						40,000,000			40,000,000															40,000,000
Maximum borrowing capacity																						$ 280,000,000			$ 280,000,000															$ 280,000,000
Retail rate of return on common equity																						10.25%			10.25%															10.25%
Reduction in depreciation expense																								34,000,000							0	$ 20,100,000	$ 8,400,000	$ 62,500,000
Wholesale revenues, non-affiliates																						$ 14,000,000	17,000,000		$ 44,000,000	48,000,000
Retail regulatory equity ratio							0.525
Loss on Plant Scherer Unit 3																						0	0		$ 33,000,000	0
Number of regulatory clauses | clause																									4
Property, plant and equipment, gross																						$ 5,181,000,000			$ 5,181,000,000						5,140,000,000								5,140,000,000	$ 5,181,000,000
GULF POWER CO | Minimum
Loss Contingencies [Line Items]
Retail rate of return on common equity																						9.25%			9.25%															9.25%
GULF POWER CO | Maximum
Loss Contingencies [Line Items]
Retail rate of return on common equity																						11.25%			11.25%															11.25%
SOUTHERN Co GAS
Loss Contingencies [Line Items]
Environmental remediation liability																						$ 399,000,000			$ 399,000,000						426,000,000								426,000,000	$ 399,000,000
Maximum borrowing capacity																						1,900,000,000			1,900,000,000															1,900,000,000
Stockholders' equity, including portion attributable to noncontrolling interest																						(9,167,000,000)			(9,167,000,000)						(9,109,000,000)								(9,109,000,000)	(9,167,000,000)
Property, plant and equipment, gross																						15,383,000,000			15,383,000,000						14,508,000,000								14,508,000,000	15,383,000,000
MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Gain contingency, surcharge revenue																															5,000,000
Increase in base rate under cost based electric tariff due to settlement																	$ 7,000,000
AFUDC cost																									22,000,000
Fuel cost recovery																						2,000,000			2,000,000						37,000,000								37,000,000	2,000,000
Percentage of PSC retail rate increase																																											(0.85%)
Maximum borrowing capacity																						100,000,000			100,000,000															100,000,000
Wholesale revenues, non-affiliates																						72,000,000	78,000,000		196,000,000	198,000,000
PSC retail rate increase (decrease)																																											$ 8,000,000
Maximum annual percentage increase in revenue										2.00%
Maximum annual increase in revenue										$ 18,000,000
Deferred revenue										$ 26,000,000
Property, plant and equipment, gross																						4,836,000,000			4,836,000,000						4,865,000,000								4,865,000,000	4,836,000,000
ALABAMA POWER CO
Loss Contingencies [Line Items]
Maximum borrowing capacity																						1,335,000,000			1,335,000,000															1,335,000,000
Wholesale revenues, non-affiliates																						77,000,000	$ 82,000,000		210,000,000	$ 211,000,000
Property, plant and equipment, gross																						26,619,000,000			26,619,000,000						26,031,000,000								26,031,000,000	26,619,000,000
ALABAMA POWER CO | Regulatory assets, deferred
Loss Contingencies [Line Items]
Over (under) recovered environmental clause																																															$ 36,000,000
Atlanta Gas Light
Loss Contingencies [Line Items]
Public utilities, approved return on equity percentage															10.75%
Annual proceeds from strategic economic development projects															$ 15,000,000
Approved increase (decrease) in fuel rates amount															$ 20,000,000
Elizabethtown Gas
Loss Contingencies [Line Items]
Public utilities, requested rate increase (decrease), amount								$ 13,000,000												$ 19,000,000
Test year duration																														12 months
Public utilities, requested return on equity, percentage								9.60%												10.25%
Public utilities, property, plant and equipment, accumulated depreciation								$ 3,000,000																$ 3,000,000													$ 3,000,000
Nicor Gas
Loss Contingencies [Line Items]
Maximum borrowing capacity																						700,000,000			700,000,000															700,000,000					700,000,000
Public utilities, requested rate increase (decrease), amount														$ 208,000,000
Public utilities, requested return on equity, percentage														10.70%
Virginia Natural Gas
Loss Contingencies [Line Items]
Public utilities, requested return on equity, percentage												10.25%
RE Roserock, LLC | SOUTHERN POWER CO
Loss Contingencies [Line Items]
Ownership percentage by parent																																51.00%
Loss contingency, payments																									26,000,000
Location One | SOUTHERN Co GAS
Loss Contingencies [Line Items]
Environmental remediation liability																						5,000,000			5,000,000															5,000,000
Natural Gas Storage
Loss Contingencies [Line Items]
Public utilities, property, plant and equipment, net																						111,000,000			$ 111,000,000															111,000,000
Natural Gas Storage - Salt Dome Caverns
Loss Contingencies [Line Items]
Public utilities, property, plant and equipment, percentage of total assets																									20.00%
Kemper IGCC | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Estimated Cost Incurred After in Service Date																																													$ 175,000,000
Period of amortization of regulatory assets																		36 months
AFUDC cost																																					$ 494,000,000
Approved increase (decrease) in fuel rates amount					$ 126,000,000
Transmission and Distribution Facilities | GEORGIA POWER CO
Loss Contingencies [Line Items]
Regulatory assets related to storm damage																						360,000,000			$ 360,000,000															360,000,000
Asset recovery damaged property costs																						150,000,000			150,000,000															150,000,000
Accrued storm reserve damaged property costs																						$ 145,000,000			145,000,000															$ 145,000,000
Annual accrual for asset recovery damaged property costs																									30,000,000
Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Guarantor obligations									$ 3,680,000,000.00
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO
Loss Contingencies [Line Items]
Liquidated damages, monetary amount																									$ 1,700,000,000											$ 920,000,000
Liquidated damages, monetary amount Received, based on percentage of ownership																																				$ 420,000,000
Maximum borrowing capacity																					$ 920,000,000
Percentage of ownership interest required for voting for continuing construction																						90.00%			90.00%															90.00%
Public utilities, increase in construction budget																									$ 1,000,000,000
Extension in project schedule																									1 year
Percentage of approval required to change primary construction contractor																						90.00%			90.00%															90.00%
Percentage of approval required for material amendments																						67.00%			67.00%															67.00%
Guarantor obligations									$ 1,700,000,000.0
Requested rate increase (decrease) amount																									$ (400,000,000)
Plant Scherer Unit 3
Loss Contingencies [Line Items]
Loss on Plant Scherer Unit 3																									$ 33,000,000
Plant Scherer Unit 3 | GULF POWER CO
Loss Contingencies [Line Items]
Number of intervenors | intervenor											3
Plant Smith Units 1 and 2 | GULF POWER CO
Loss Contingencies [Line Items]
Capacity of units included in request for decertification of units | MW																									357
Plant Scherer Unit Three | GULF POWER CO
Loss Contingencies [Line Items]
Loss on Plant Scherer Unit 3																									$ 32,500,000
MRA Revenue | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Fuel cost recovery																						$ 3,000,000			3,000,000						$ 13,000,000								$ 13,000,000	$ 3,000,000
Westinghouse | Plant Vogtle Units 3 And 4 | GEORGIA POWER CO
Loss Contingencies [Line Items]
Period of notice required in the event letters of credit are not renewed																					60 days
Vogtle Owners | Removal of Subcontractor Liens
Loss Contingencies [Line Items]
Loss contingency, payments																									340,000,000
Estimate of possible loss																						386,000,000			386,000,000															386,000,000
Vogtle Owners | GEORGIA POWER CO | Removal of Subcontractor Liens
Loss Contingencies [Line Items]
Estimate of possible loss																						176,000,000			176,000,000															176,000,000
Vogtle Owners | Plant Vogtle Units 3 And 4 | GEORGIA POWER CO
Loss Contingencies [Line Items]
Period of notice required in the event letters of credit are not renewed									30 days
Restatement Adjustment | Toshiba
Loss Contingencies [Line Items]
Stockholders' equity, including portion attributable to noncontrolling interest																																												$ 4,500,000,000
Scenario, Forecast | GEORGIA POWER CO
Loss Contingencies [Line Items]
Additional construction capital costs																																						$ 5,440,000,000
Percent of basis points																																						0.95%			0.30%
Decrease in basis points																																						$ 8,000,000
Amendment to estimated in-service capital cost																																						$ 5,680,000,000
Scenario, Forecast | GULF POWER CO
Loss Contingencies [Line Items]
Overall net customer impact from rate case settlement agreement																													$ 54,300,000
Increase (decrease) in revenue to be received from base rate change																											$ 63,000,000		62,000,000
Wholesale revenues, non-affiliates																													$ 7,700,000
Scenario, Forecast | Virginia Natural Gas
Loss Contingencies [Line Items]
Test year duration																												12 months
Scenario, Forecast | Plant Vogtle Units 3 And 4 | GEORGIA POWER CO
Loss Contingencies [Line Items]
Increase in NCCR tariff	$ 90,000,000
FFB Loan | GEORGIA POWER CO
Loss Contingencies [Line Items]
Long-term line of credit																						2,600,000,000			2,600,000,000															2,600,000,000
Maximum borrowing capacity																						$ 3,460,000,000.00			$ 3,460,000,000.00															$ 3,460,000,000.00
Conditional borrowing commitment																																										$ 1,670,000,000
Retirement Of Plant | Scenario, Forecast | GULF POWER CO
Loss Contingencies [Line Items]
Regulatory asset, amortization period																											15 years
Plant Scherer Unit Three | GULF POWER CO
Loss Contingencies [Line Items]
Electric generating units, capacity | MW																						205			205															205
Energy Efficiency Cost Rider | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
PSC retail rate increase (decrease)																																											$ 2,000,000
SAVE Program | Virginia Natural Gas
Loss Contingencies [Line Items]
Infrastructure replacement program, petitioned investment amount												$ 44,000,000																		$ 44,000,000
Regulated operation, allowable cost recovery												$ 13,000,000
Approved infrastructure replacement program																						$ 21,000,000			$ 21,000,000															$ 21,000,000
Regulatory Infrastructure Program | Nicor Gas
Loss Contingencies [Line Items]
Program duration period																																	9 years
Property, plant and equipment, gross																						178,000,000			178,000,000															178,000,000
STRIDE | Atlanta Gas Light
Loss Contingencies [Line Items]
Approved infrastructure replacement program																						127,000,000			$ 127,000,000															127,000,000
Integrated System Reinforcement Program | Atlanta Gas Light
Loss Contingencies [Line Items]
Infrastructure replacement program, petitioned investment amount																																																$ 177,000,000
Integrated System Reinforcement Program | Atlanta Gas Light | Minimum
Loss Contingencies [Line Items]
Program duration period																									4 years
Aging Infrastructure Replacement Program | Elizabethtown Gas
Loss Contingencies [Line Items]
Approved infrastructure replacement program																						16,000,000			$ 16,000,000															16,000,000
Safety, Access, and Facility Enhancement Program | Florida City Gas
Loss Contingencies [Line Items]
Approved infrastructure replacement program																						$ 9,000,000			$ 9,000,000															$ 9,000,000
Subsequent Event | Virginia Natural Gas | Minimum
Loss Contingencies [Line Items]
Public utilities, requested return on equity, percentage			9.00%
Subsequent Event | Virginia Natural Gas | Maximum
Loss Contingencies [Line Items]
Public utilities, requested return on equity, percentage			10.00%
Subsequent Event | Virginia Natural Gas | Midpoint
Loss Contingencies [Line Items]
Public utilities, requested return on equity, percentage			9.50%
Subsequent Event | Florida City Gas
Loss Contingencies [Line Items]
Public utilities, requested rate increase (decrease), amount		$ 19,000,000
Public utilities, requested return on equity, percentage		11.25%
Regulated operation, allowable cost recovery		$ 3,000,000
Public utilities, interim rate		$ 5,000,000
Subsequent Event | Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Proceeds from guarantor obligations				$ 300,000,000
Subsequent Event | Plant Vogtle Units 3 And 4 | GEORGIA POWER CO
Loss Contingencies [Line Items]
Proceeds from guarantor obligations				$ 137,000,000
Subsequent Event | SAVE Program | Virginia Natural Gas
Loss Contingencies [Line Items]
Infrastructure replacement program, petitioned investment amount			$ 34,000,000
Regulated operation, allowable cost recovery			$ 13,000,000

XML

Contingencies and Regulatory Matters - Recovery Balance of Each Regulatory Clause - Alabama Power (Details) - ALABAMA POWER CO - USD ($) $ in Millions	Sep. 30, 2017	Feb. 17, 2017	Dec. 31, 2016
Deferred over recovered regulatory clause revenues
Loss Contingencies [Line Items]
Rate CNP Compliance	$ 9		$ 0
Deferred under recovered regulatory clause revenues
Loss Contingencies [Line Items]
Rate CNP Compliance	0		9
Rate CNP PPA	17		142
Other regulatory liabilities, current
Loss Contingencies [Line Items]
Retail Energy Cost Recovery()	0		76
Over (under) recovered environmental clause		$ (11)
Other regulatory liabilities, deferred
Loss Contingencies [Line Items]
Natural Disaster Reserve	$ 51		$ 69
Regulatory assets, deferred
Loss Contingencies [Line Items]
Over (under) recovered environmental clause		$ 36

XML

Contingencies and Regulatory Matters - Revised Cost and Schedule - Georgia Power (Details) - USD ($) $ in Millions	9 Months Ended	105 Months Ended
	Sep. 30, 2017	Sep. 30, 2017	Dec. 31, 2016
Loss Contingencies [Line Items]
Construction work in progress	$ 8,026	$ 8,026	$ 8,977
GEORGIA POWER CO
Loss Contingencies [Line Items]
Construction work in progress	5,751	5,751	$ 4,939
Financing costs incurred		1,500
Financing costs collected, net of tax	1,500
Estimated cancellation costs		350
GEORGIA POWER CO | Minimum
Loss Contingencies [Line Items]
Estimated financing costs		3,400
Cancellation Decision | GEORGIA POWER CO
Loss Contingencies [Line Items]
Construction work in progress	4,600	4,600
Guarantee Obligations	(1,700)	(1,700)
Financing costs collected, net of tax		1,500
Estimated cancellation costs		400
Estimated net cancellation cost	4,800	4,800
Plant Vogtle Units 3 And 4 | GEORGIA POWER CO
Loss Contingencies [Line Items]
Estimated cost to complete	4,200	4,200
Construction work in progress	4,600	4,600
Guarantee Obligations	(1,700)	(1,700)
Estimated capital costs	7,100	7,100
Vogtle Cost Settlement Agreement Revised Forecast	(5,700)	(5,700)
Estimated net additional capital costs	$ 1,400	$ 1,400

XML

Contingencies and Regulatory Matters - Recovery Balance of Each Regulatory Clause - Gulf Power (Details) - GULF POWER CO - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Under recovered regulatory clause revenues, current
Loss Contingencies [Line Items]
Fuel Cost Recovery	$ 13	$ 0
Purchased Power Capacity Recovery	1	0
Environmental Cost Recovery	0	13
Energy Conservation Cost Recovery	1	4
Other regulatory liabilities, current
Loss Contingencies [Line Items]
Fuel Cost Recovery	0	15
Environmental Cost Recovery	$ 1	$ 0

XML

Contingencies and Regulatory Matters - IGCC (Details) $ in Millions												1 Months Ended		2 Months Ended	3 Months Ended		5 Months Ended	6 Months Ended		9 Months Ended		12 Months Ended		38 Months Ended	65 Months Ended
	Dec. 31, 2017 USD ($)	Aug. 21, 2017 USD ($)	Jun. 28, 2017 USD ($)	Nov. 17, 2016 USD ($)	Jun. 09, 2016 USD ($)	Jun. 03, 2016	Dec. 03, 2015 USD ($)	Jul. 07, 2015 USD ($)	Jun. 03, 2015 USD ($)	Jan. 01, 2014 USD ($)	Mar. 19, 2013	Jun. 30, 2017 USD ($)	Jan. 31, 2013 USD ($)	May 31, 2017 USD ($)	Sep. 30, 2017 USD ($) mi	Sep. 30, 2016 USD ($)	May 31, 2017 USD ($)	Dec. 31, 2017 USD ($)	Jun. 30, 2017 USD ($)	Sep. 30, 2017 USD ($) mi MW	Sep. 30, 2016 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2010 USD ($)	Jun. 30, 2017 USD ($)	May 31, 2017 USD ($)	May 20, 2015 USD ($)
MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Plant capacity under coal gasification combined cycle technology | MW																				582
Cost related to grant funding																						$ 245
Maximum cap construction cost																						2,880
Reduced percentage interest transferred under asset purchase agreement											15.00%												15.00%
Regulatory liabilities															$ 10					$ 10
Public utilities, approved rate increase (decrease), percentage										3.00%
Settlement agreement collection amount to mitigate rate impact, year two										$ 156
Retail rate recovery								$ 342
Carrying costs associated with retail rate recovery								$ 29
AFUDC cost																				22
Interest bearing refundable deposit related to assets sale																										$ 275
Promissory note									$ 301
Kemper IGCC
Loss Contingencies [Line Items]
Pre-tax charge to income															34	$ 88				3,200	$ 222
After tax charge to income															$ 21	$ 54				$ 2,200	$ 137
Kemper IGCC | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Pipeline infrastructure | mi															61					61
Estimated cost			$ 7,380	$ 68								$ 7,380										2,880	$ 2,970	$ 2,880
Cost related to grant funding			137									137
Maximum cap construction cost			5,950									5,950											$ 2,400
Period of commercial operations established by discovery docket																				5 years
Pre-tax charge to income												2,800		$ 196	$ 34		$ 305			$ 3,200					$ 3,070
After tax charge to income												$ 2,000		$ 121	21		$ 188			2,200					$ 1,890
Construction and development costs																			$ 1,300	1,300
Average annual increase (decrease) in operations and maintenance expenses																				105
Average annual increase (decrease) in maintenance capital																				44
Approved increase (decrease) in fuel rates amount		$ 126
Regulatory assets															113					113
Regulatory liabilities															7					$ 7
AFUDC cost																								494
Kemper IGCC | MISSISSIPPI POWER CO | Minimum
Loss Contingencies [Line Items]
Amortization period of regulatory assets and liabilities																				2 years
Kemper IGCC | MISSISSIPPI POWER CO | Maximum
Loss Contingencies [Line Items]
Amortization period of regulatory assets and liabilities																				10 years
Kemper IGCC | MISSISSIPPI POWER CO | Pending Litigation
Loss Contingencies [Line Items]
Loss contingency, value of damages sought			$ 500		$ 100
Kemper IGCC | MISSISSIPPI POWER CO | Property, Plant and Equipment
Loss Contingencies [Line Items]
Construction and development costs																				$ 1,100
Kemper IGCC | MISSISSIPPI POWER CO | Property, Plant, and Equipment Accumulated Depreciation
Loss Contingencies [Line Items]
Construction and development costs																				80
Kemper IGCC | MISSISSIPPI POWER CO | Materials And Supplies
Loss Contingencies [Line Items]
Construction and development costs																				15
Kemper IGCC | MISSISSIPPI POWER CO | Other deferred charges and assets
Loss Contingencies [Line Items]
Construction and development costs																				10
Kemper IGCC | MISSISSIPPI POWER CO | Regulatory Assets
Loss Contingencies [Line Items]
Construction and development costs																				113
Kemper IGCC | MISSISSIPPI POWER CO | Regulatory Assets Accumulated Depreciation
Loss Contingencies [Line Items]
Construction and development costs																				63
Kemper IGCC | MISSISSIPPI POWER CO | Other regulatory assets current
Loss Contingencies [Line Items]
Construction and development costs																				21
Kemper IGCC | MISSISSIPPI POWER CO | Other regulatory assets, deferred
Loss Contingencies [Line Items]
Construction and development costs																				92
Kemper IGCC | MISSISSIPPI POWER CO | Transmission and Related Regulatory Assets
Loss Contingencies [Line Items]
Construction and development costs																				800
Kemper IGCC | MISSISSIPPI POWER CO | Assets, Current
Loss Contingencies [Line Items]
Regulatory assets															$ 21					21
Electricity Generation Plant, Non-Nuclear | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Estimated cost													$ 2,400									$ 2,400
Kemper IGCC - Combined Cycle | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
CIP expenditures incurred but not yet paid																				$ 500
Percentage of costs contracted to third party																				15.00%
Kemper IGCC - Gasification | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
AFUDC cost																								$ 460
Mine | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Term of management fee contract																							40 years
Monthly payments of contributed capital																							$ 2
Scenario, Forecast | Kemper IGCC | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Additional suspension costs	$ 5
Scenario, Forecast | Kemper IGCC | MISSISSIPPI POWER CO | Minimum
Loss Contingencies [Line Items]
Pre-tax charge to income																		$ 100
Scenario, Forecast | Kemper IGCC | MISSISSIPPI POWER CO | Maximum
Loss Contingencies [Line Items]
Pre-tax charge to income																		$ 200
In-Service Asset Proposal | Kemper IGCC | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Approved increase (decrease) in fuel rates amount							$ 126
Public utilities, approved equity capital structure, percentage							49.733%
Public utilities, approved return on equity percentage							9.225%
Denbury Onshore, Contractor | Kemper IGCC | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Long term contract for purchase of percentage of carbon dioxide captured from plant						100.00%									70.00%					70.00%
Treetop Midstream Services, LLC, Contractor | Kemper IGCC | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Long term contract for purchase of percentage of carbon dioxide captured from plant															30.00%					30.00%
Denbury Onshore, Contractor | Electricity Generation Plant, Non-Nuclear | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Long-term contract for purchase of carbon dioxide, term						16 years

XML

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Assets:
Fair Value	$ 26
Liabilities:
Collateral already posted, aggregate fair value	76
Fair Value, Measurements, Recurring
Assets:
Energy-related derivatives	415
Interest rate derivatives	5
Foreign currency derivatives	103
Nuclear decommissioning trusts	1,782
Cash equivalents	1,271
Other investments	10
Total	3,586
Liabilities:
Energy-related derivatives	411
Interest rate derivatives	24
Foreign currency derivatives	23
Contingent consideration	20
Total	478
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives	231
Interest rate derivatives	0
Foreign currency derivatives	0
Nuclear decommissioning trusts	752
Cash equivalents	1,271
Other investments	9
Total	2,263
Liabilities:
Energy-related derivatives	265
Interest rate derivatives	0
Foreign currency derivatives	0
Contingent consideration	0
Total	265
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives	184
Interest rate derivatives	5
Foreign currency derivatives	103
Nuclear decommissioning trusts	1,004
Cash equivalents	0
Other investments	0
Total	1,296
Liabilities:
Energy-related derivatives	146
Interest rate derivatives	24
Foreign currency derivatives	23
Contingent consideration	0
Total	193
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Foreign currency derivatives	0
Nuclear decommissioning trusts	0
Cash equivalents	0
Other investments	1
Total	1
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Foreign currency derivatives	0
Contingent consideration	20
Total	20
ALABAMA POWER CO
Assets:
Energy-related derivatives	9	$ 20
Fair Value	26
Liabilities:
Energy-related derivatives	7	9
ALABAMA POWER CO | Fair Value, Measurements, Recurring
Assets:
Energy-related derivatives	9
Cash equivalents	808
Total	1,685
Liabilities:
Energy-related derivatives	7
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Domestic equity
Assets:
Nuclear decommissioning trusts	503
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Foreign equity
Assets:
Nuclear decommissioning trusts	117
ALABAMA POWER CO | Fair Value, Measurements, Recurring | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	27
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Corporate bonds
Assets:
Nuclear decommissioning trusts	169
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	18
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Private Equity
Assets:
Nuclear decommissioning trusts	26
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Other
Assets:
Nuclear decommissioning trusts	8
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives	0
Cash equivalents	808
Total	1,309
Liabilities:
Energy-related derivatives	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity
Assets:
Nuclear decommissioning trusts	422
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign equity
Assets:
Nuclear decommissioning trusts	60
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate bonds
Assets:
Nuclear decommissioning trusts	19
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Private Equity
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives	9
Cash equivalents	0
Total	350
Liabilities:
Energy-related derivatives	7
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Domestic equity
Assets:
Nuclear decommissioning trusts	81
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Foreign equity
Assets:
Nuclear decommissioning trusts	57
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	27
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Corporate bonds
Assets:
Nuclear decommissioning trusts	150
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	18
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Private Equity
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Other
Assets:
Nuclear decommissioning trusts	8
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Domestic equity
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Foreign equity
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Corporate bonds
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Private Equity
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Other
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO
Assets:
Energy-related derivatives	19	46
Nuclear decommissioning trusts	66
Liabilities:
Energy-related derivatives	14	11
GEORGIA POWER CO | Fair Value, Measurements, Recurring
Assets:
Energy-related derivatives	18
Interest rate derivatives	1
Cash equivalents	112
Total	1,045
Liabilities:
Energy-related derivatives	11
Interest rate derivatives	3
Total	14
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Domestic equity
Assets:
Nuclear decommissioning trusts	236
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Foreign equity
Assets:
Nuclear decommissioning trusts	156
GEORGIA POWER CO | Fair Value, Measurements, Recurring | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	225
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Corporate bonds
Assets:
Nuclear decommissioning trusts	160
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	38
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Other
Assets:
Nuclear decommissioning trusts	35
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Municipal bonds
Assets:
Nuclear decommissioning trusts	64
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Cash equivalents	112
Total	363
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Total	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity
Assets:
Nuclear decommissioning trusts	235
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign equity
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate bonds
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Assets:
Nuclear decommissioning trusts	16
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Municipal bonds
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives	18
Interest rate derivatives	1
Cash equivalents	0
Total	682
Liabilities:
Energy-related derivatives	11
Interest rate derivatives	3
Total	14
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Domestic equity
Assets:
Nuclear decommissioning trusts	1
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Foreign equity
Assets:
Nuclear decommissioning trusts	156
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	225
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Corporate bonds
Assets:
Nuclear decommissioning trusts	160
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	38
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Other
Assets:
Nuclear decommissioning trusts	19
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Municipal bonds
Assets:
Nuclear decommissioning trusts	64
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Total	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Domestic equity
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Foreign equity
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Corporate bonds
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Other
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Municipal bonds
Assets:
Nuclear decommissioning trusts	0
GULF POWER CO
Assets:
Energy-related derivatives	0	5
Liabilities:
Energy-related derivatives	22	29
GULF POWER CO | Fair Value, Measurements, Recurring
Assets:
Cash equivalents	21
Liabilities:
Energy-related derivatives	22
GULF POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	21
Liabilities:
Energy-related derivatives	0
GULF POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	0
Liabilities:
Energy-related derivatives	22
GULF POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents	0
Liabilities:
Energy-related derivatives	0
MISSISSIPPI POWER CO
Assets:
Energy-related derivatives	5	7
Liabilities:
Energy-related derivatives	7	11
MISSISSIPPI POWER CO | Fair Value, Measurements, Recurring
Assets:
Energy-related derivatives	3
Interest rate derivatives	2
Cash equivalents	209
Total	214
Liabilities:
Energy-related derivatives	7
MISSISSIPPI POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Cash equivalents	209
Total	209
Liabilities:
Energy-related derivatives	0
MISSISSIPPI POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives	3
Interest rate derivatives	2
Cash equivalents	0
Total	5
Liabilities:
Energy-related derivatives	7
MISSISSIPPI POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
SOUTHERN POWER CO
Assets:
Energy-related derivatives	112	22
Liabilities:
Energy-related derivatives	27	63
SOUTHERN POWER CO | Fair Value, Measurements, Recurring
Assets:
Energy-related derivatives	9
Foreign currency derivatives	103
Cash equivalents	90
Total	202
Liabilities:
Energy-related derivatives	4
Foreign currency derivatives	23
Contingent consideration	20
Total	47
SOUTHERN POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives	0
Foreign currency derivatives	0
Cash equivalents	90
Total	90
Liabilities:
Energy-related derivatives	0
Foreign currency derivatives	0
Contingent consideration	0
Total	0
SOUTHERN POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives	9
Foreign currency derivatives	103
Cash equivalents	0
Total	112
Liabilities:
Energy-related derivatives	4
Foreign currency derivatives	23
Contingent consideration	0
Total	27
SOUTHERN POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives	0
Foreign currency derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
Foreign currency derivatives	0
Contingent consideration	20
Total	20
SOUTHERN Co GAS
Assets:
Energy-related derivatives	389	581
Liabilities:
Energy-related derivatives	360	569
Collateral already posted, aggregate fair value	76	$ 62
SOUTHERN Co GAS | Fair Value, Measurements, Recurring
Assets:
Energy-related derivatives	376
Liabilities:
Energy-related derivatives	360
SOUTHERN Co GAS | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives	231
Liabilities:
Energy-related derivatives	265
SOUTHERN Co GAS | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives	145
Liabilities:
Energy-related derivatives	95
SOUTHERN Co GAS | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives	0
Liabilities:
Energy-related derivatives	0
Nuclear Decommissioning Trusts
Assets:
Fair Value	26
Nuclear Decommissioning Trusts | ALABAMA POWER CO
Assets:
Fair Value	26
Weather Derivative | Fair Value, Measurements, Recurring
Assets:
Energy-related derivatives	$ 13

XML

Fair Value Measurements - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ 50	$ 49	$ 168	$ 116
Private Equity
Fair Value, Option, Quantitative Disclosures [Line Items]
Liquidations term			10 years
ALABAMA POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Long-term Debt	7,404		$ 7,404
Increase (decrease) in fair value of funds	25	26	87	66
GEORGIA POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Long-term Debt	11,713		11,713
Increase (decrease) in fair value of funds	25	$ 23	81	$ 50
SOUTHERN POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Long-term Debt	5,810		5,810
SOUTHERN Co GAS
Fair Value, Option, Quantitative Disclosures [Line Items]
Long-term Debt	$ 5,862		$ 5,862
Minimum | SOUTHERN POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Contingent payment obligations, payment period			10 years
Maximum | SOUTHERN POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Contingent payment obligations, payment period			30 years

XML

Fair Value Measurements - Fair Value Measurements Of Investments Calculated At Net Asset Value Per Share (Details) $ in Millions	Sep. 30, 2017 USD ($)
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	$ 26
Private Equity
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	26
Unfunded Commitments	24
ALABAMA POWER CO
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	26
ALABAMA POWER CO | Private Equity
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	26
Unfunded Commitments	$ 24

XML

Fair Value Measurements - Financial Instruments for which Carrying Amount did not Equal Fair Value (Details) $ in Millions	Sep. 30, 2017 USD ($)
Southern Company
Long-term debt:
Carrying Amount	$ 47,269
Fair Value	49,348
ALABAMA POWER CO
Long-term debt:
Carrying Amount	7,404
Fair Value	8,031
GEORGIA POWER CO
Long-term debt:
Carrying Amount	11,713
Fair Value	12,237
GULF POWER CO
Long-term debt:
Carrying Amount	1,292
Fair Value	1,352
MISSISSIPPI POWER CO
Long-term debt:
Carrying Amount	2,123
Fair Value	2,117
SOUTHERN POWER CO
Long-term debt:
Carrying Amount	5,810
Fair Value	5,916
SOUTHERN Co GAS
Long-term debt:
Carrying Amount	5,862
Fair Value	$ 6,230

XML

Stockholders' Equity - Earnings per Share (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Equity [Abstract]
As reported shares (in shares)	1,003	968	998	940
Effect of options and performance share award units (in shares)	7	7	7	5
Diluted shares (in shares)	1,010	975	1,005	945
Stock options and performance share award units that were not included in the diluted earnings per share calculation (in shares)	0	0	0	0

XML

Stockholders' Equity - Changes in Stockholders' Equity (Details) - USD ($) shares in Thousands, $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	May 31, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Changes in Stockholders' Equity
Beginning balance, treasury shares (in shares)				(800)
Beginning balance				$ 26,612	$ 21,982
Consolidated net income attributable to Southern Company		$ 1,069	$ 1,139	347	2,251
Other comprehensive income (loss)				(2)	(95)
Stock issued				613	3,265
Stock-based compensation				97	94
Cash dividends on common stock				(1,716)	(1,553)
Preference stock redemption				(150)
Contributions from noncontrolling interests				77	357
Distributions to noncontrolling interests				(87)	(21)
Purchase of membership interests from noncontrolling interests					(129)
Net income attributable to noncontrolling interests				45	36
Reclassification from redeemable noncontrolling interests				114
Other				$ (11)	(7)
Ending balance, treasury shares (in shares)		(900)		(900)
Ending balance		$ 25,939	$ 26,180	$ 25,939	$ 26,180
Number of Common Shares Issued
Changes in Stockholders' Equity
Beginning balance (in shares)				991,213	915,073
Stock issued (in shares)				13,308	65,725
Other (in shares)				0
Ending balance (in shares)		1,004,521	980,798	1,004,521	980,798
Number of Common Shares Treasury Issued
Changes in Stockholders' Equity
Beginning balance, treasury shares (in shares)				(819)	(3,352)
Stock issued (in shares)				0	2,599
Other (in shares)				(75)	(46)
Ending balance, treasury shares (in shares)		(894)	(799)	(894)	(799)
Common Stockholders' Equity
Changes in Stockholders' Equity
Beginning balance				$ 24,758	$ 20,592
Consolidated net income attributable to Southern Company				347	2,251
Other comprehensive income (loss)				(2)	(95)
Stock issued				613	3,265
Stock-based compensation				97	94
Cash dividends on common stock				(1,716)	(1,553)
Other				(15)	(7)
Ending balance		$ 24,082	$ 24,547	24,082	24,547
Preferred and Preference Stock of Subsidiaries
Changes in Stockholders' Equity
Beginning balance				609	609
Preference stock redemption				(150)
Other				3
Ending balance		462	609	462	609
Noncontrolling Interest
Changes in Stockholders' Equity
Beginning balance				1,245	781
Contributions from noncontrolling interests				77	357
Distributions to noncontrolling interests				(87)	(21)
Purchase of membership interests from noncontrolling interests					(129)
Net income attributable to noncontrolling interests				45	36
Reclassification from redeemable noncontrolling interests				114
Other				1
Ending balance		$ 1,395	$ 1,024	$ 1,395	$ 1,024
SunPower Corp. | Noncontrolling Interest
Changes in Stockholders' Equity
Beginning balance	$ 114

XML

Financing - Narrative (Details) $ / shares in Units, shares in Thousands			1 Months Ended						3 Months Ended		9 Months Ended
	Jun. 03, 2015 USD ($)	Feb. 20, 2014	Oct. 31, 2017 USD ($) shares	Sep. 30, 2017 USD ($) $ / shares shares	Aug. 31, 2017 USD ($)	Jun. 30, 2017 USD ($) agreement	May 31, 2017 USD ($) shares	Feb. 28, 2017 USD ($)	Jun. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($) $ / shares	Sep. 30, 2016 USD ($)	Nov. 30, 2017 USD ($)	Sep. 29, 2017 USD ($)	Sep. 28, 2017 USD ($)	Aug. 10, 2017 USD ($)	Jul. 31, 2017 USD ($)	Apr. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Debt Instrument [Line Items]
Short-term debt				$ 2,579,000,000							$ 2,579,000,000									$ 2,241,000,000
Variable rate pollution control revenue bonds outstanding				1,500,000,000							1,500,000,000
Maximum borrowing capacity				8,145,000,000							8,145,000,000
Value of stock redeemed											150,000,000
Line Of Credit Expire Year Four				530,000,000							530,000,000
Southern Company
Debt Instrument [Line Items]
Maximum borrowing capacity				2,000,000,000			$ 1,250,000,000.00				2,000,000,000
Line Of Credit Expire Year Four				0							0
Southern Company | Line of Credit | Uncommitted Bank Credit Arrangement
Debt Instrument [Line Items]
Increase in debt instrument					$ 250,000,000
Payable to bank by demand, term					30 days
Southern Company | Senior Notes | Series 2017A
Debt Instrument [Line Items]
Debt face amount						$ 500,000,000			$ 500,000,000
Debt stated interest rate						5.325%			5.325%
Southern Company | Senior Notes | Series 2017A Floating Rate Senior Notes
Debt Instrument [Line Items]
Debt face amount						$ 300,000,000			$ 300,000,000
Southern Company | Notes Payable to Banks | Floating Rate Bank Term Loan Agreement
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
MISSISSIPPI POWER CO
Debt Instrument [Line Items]
Working capital				769,000,000							769,000,000
Senior notes, current				4,000,000							4,000,000
Short-term debt				4,000,000							4,000,000									23,000,000
Long-term pollution control bond				50,000,000							50,000,000
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
Promissory note	$ 301,000,000
Capital contributions from parent company						1,000,000,000					1,002,000,000	$ 227,000,000
Line Of Credit Expire Year Four				0							0
MISSISSIPPI POWER CO | Unsecured Debt
Debt Instrument [Line Items]
Loans payable to bank				935,000,000							935,000,000
MISSISSIPPI POWER CO | Tax-Exempt Variable Rate Demand Obligations
Debt Instrument [Line Items]
Short-term debt				40,000,000							40,000,000
MISSISSIPPI POWER CO | Short Term Note
Debt Instrument [Line Items]
Debt face amount																			$ 9,000,000
Debt stated interest rate																			5.00%
MISSISSIPPI POWER CO | Bank Loans | Loans Payable
Debt Instrument [Line Items]
Repayments of debt						10,000,000
MISSISSIPPI POWER CO | Notes Payable to Banks | Notes Payable to Banks
Debt Instrument [Line Items]
Repayments of debt					$ 12,500,000
MISSISSIPPI POWER CO | Promissory Notes | Promissory Notes
Debt Instrument [Line Items]
Debt face amount				150,000,000							150,000,000
Increase in debt instrument									40,000,000
Repayments of debt				109,000,000		591,000,000
MISSISSIPPI POWER CO | Unsecured Debt | Term Loan
Debt Instrument [Line Items]
Debt face amount						1,200,000,000.0			1,200,000,000.0
Repayments of debt						300,000,000
GEORGIA POWER CO
Debt Instrument [Line Items]
Short-term debt				400,000,000							400,000,000									391,000,000
Debt instrument, basis spread on variable rate		0.375%
Amortization period for line of credit facility		5 years
Variable rate pollution control revenue bonds outstanding				550,000,000							550,000,000
Variable rate pollution control revenue bonds outstanding, amount remarketed				318,000,000							318,000,000
Fixed rate pollution control revenue bonds outstanding				509,000,000							509,000,000
Maximum borrowing capacity				1,750,000,000							1,750,000,000
Capital contributions from parent company											412,000,000	294,000,000
Line Of Credit Expire Year Four				0							0
GEORGIA POWER CO | Loan Guarantee Agreement
Debt Instrument [Line Items]
Conditional borrowing commitment															$ 1,670,000,000
GEORGIA POWER CO | Line of Credit | Uncommitted Bank Credit Arrangement
Debt Instrument [Line Items]
Increase in debt instrument						$ 500,000,000
Repayments of debt					250,000,000
GEORGIA POWER CO | Senior Notes | Series 2017A
Debt Instrument [Line Items]
Debt face amount																			$ 450,000,000
Debt stated interest rate																			2.00%
GEORGIA POWER CO | Senior Notes | Series 2017B
Debt Instrument [Line Items]
Debt face amount																			$ 400,000,000
Debt stated interest rate																			3.25%
GEORGIA POWER CO | Senior Notes | Series 2017C
Debt Instrument [Line Items]
Debt face amount					$ 500,000,000
Debt stated interest rate					2.00%
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																		$ 27,000,000
GEORGIA POWER CO | Municipal Bonds | Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1997
Debt Instrument [Line Items]
Debt face amount					$ 38,000,000
GEORGIA POWER CO | Notes Payable to Banks | Floating Rate Bank Term Loan Agreement
Debt Instrument [Line Items]
Number of loan agreements | agreement						3
Payable to bank by demand, term						30 days
GEORGIA POWER CO | Notes Payable to Banks | Floating Rate Bank Term Loan Agreement 1
Debt Instrument [Line Items]
Debt face amount					50,000,000	$ 50,000,000			50,000,000
GEORGIA POWER CO | Notes Payable to Banks | Floating Rate Bank Term Loan Agreement 2
Debt Instrument [Line Items]
Debt face amount						150,000,000			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	$ 100,000,000			$ 100,000,000
GEORGIA POWER CO | Junior Subordinated Notes | Series 2017A
Debt Instrument [Line Items]
Debt face amount				$ 270,000,000							$ 270,000,000
Debt stated interest rate				5.00%							5.00%
ALABAMA POWER CO
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding				$ 854,000,000							$ 854,000,000
Maximum borrowing capacity				1,335,000,000							1,335,000,000
Capital contributions from parent company											337,000,000	253,000,000
Line Of Credit Expire Year Four				$ 500,000,000							$ 500,000,000
ALABAMA POWER CO | Senior Notes | Series 2017A
Debt Instrument [Line Items]
Debt face amount																			$ 550,000,000
Debt stated interest rate																			2.45%
ALABAMA POWER CO | Senior Notes | 5.00% Class A Preferred Stock
Debt Instrument [Line Items]
Preferred stock, shares issued (in shares) | shares				10,000
Preferred stock, value of shares issued				$ 250,000,000
Preferred stock, par value (in dollars per share) | $ / shares				$ 1							$ 1
Share price (in dollars per share) | $ / shares				$ 25							$ 25
Preferred stock, dividend rate				5.00%
GULF POWER CO
Debt Instrument [Line Items]
Short-term debt				$ 0							$ 0									268,000,000
Variable rate pollution control revenue bonds outstanding				82,000,000							82,000,000
Fixed rate pollution control revenue bonds outstanding				140,000,000							140,000,000
Maximum borrowing capacity				280,000,000							280,000,000
Capital contributions from parent company											7,000,000	10,000,000
Line Of Credit Expire Year Four				30,000,000							30,000,000
GULF POWER CO | Senior Notes | Series 2017A
Debt Instrument [Line Items]
Debt face amount							$ 300,000,000
Debt stated interest rate							3.30%
GULF POWER CO | Senior Notes | Series 2007A Preference Stock
Debt Instrument [Line Items]
Stock redeemed during period (in shares) | shares							450
Value of stock redeemed							$ 45,000,000
Preferred stock, dividend rate							6.45%
GULF POWER CO | Senior Notes | Series 2007A
Debt Instrument [Line Items]
Debt stated interest rate							5.90%
Repayments of debt							$ 85,000,000
GULF POWER CO | Senior Notes | Short-term Floating Rate Bank Loan
Debt Instrument [Line Items]
Repayments of debt							$ 100,000,000
GULF POWER CO | Senior Notes | Series Preference Stock
Debt Instrument [Line Items]
Stock redeemed during period (in shares) | shares							550
Value of stock redeemed							$ 55,000,000
Preferred stock, dividend rate							6.00%
GULF POWER CO | Senior Notes | Series 2013A Preference Stock
Debt Instrument [Line Items]
Stock redeemed during period (in shares) | shares							500
Value of stock redeemed							$ 50,000,000
Preferred stock, dividend rate							5.60%
GULF POWER CO | Bank Loans
Debt Instrument [Line Items]
Debt face amount																			$ 100,000,000
Traditional Electric Operating Companies
Debt Instrument [Line Items]
Fixed rate pollution control revenue bonds outstanding				699,000,000							699,000,000
SOUTHERN POWER CO
Debt Instrument [Line Items]
Short-term debt				120,000,000							120,000,000									209,000,000
Maximum borrowing capacity				750,000,000			$ 600,000,000				750,000,000
Repayments of debt				40,000,000
Capital contributions from parent company											0	$ 800,000,000
Line Of Credit Expire Year Four				0							0
SOUTHERN POWER CO | Notes Payable to Banks | Floating Rate Bank Loan
Debt Instrument [Line Items]
Debt face amount				100,000,000							100,000,000			$ 60,000,000
Southern Company Gas Capital
Debt Instrument [Line Items]
Maximum borrowing capacity				1,200,000,000.0			1,200,000,000.0				1,200,000,000.0
Nicor Gas
Debt Instrument [Line Items]
Maximum borrowing capacity				700,000,000			700,000,000				700,000,000
Nicor Gas | Collateralized Mortgage Backed Securities | First Mortgage Bonds
Debt Instrument [Line Items]
Debt face amount																	$ 400,000,000
Nicor Gas | Collateralized Mortgage Backed Securities | First Mortgage Bonds 3.03% Series
Debt Instrument [Line Items]
Debt face amount																$ 100,000,000
Debt stated interest rate																3.03%
Nicor Gas | Collateralized Mortgage Backed Securities | First Mortgage Bonds 3.62% Series
Debt Instrument [Line Items]
Debt face amount																$ 100,000,000
Debt stated interest rate																3.62%
SOUTHERN Co GAS
Debt Instrument [Line Items]
Short-term debt				934,000,000							934,000,000									$ 1,257,000,000
Maximum borrowing capacity				1,900,000,000							1,900,000,000
Capital contributions from parent company										$ 1,089,000,000	79,000,000
Line Of Credit Expire Year Four				$ 0							$ 0
SOUTHERN Co GAS | Senior Notes | Series 2017A
Debt Instrument [Line Items]
Debt face amount							$ 450,000,000
Debt stated interest rate							4.40%
Southern Company | MISSISSIPPI POWER CO
Debt Instrument [Line Items]
Promissory note								$ 551,000,000
Line of Credit | Southern Company | Line of Credit
Debt Instrument [Line Items]
Extinguishment of debt, amount							$ 1,000,000,000
Line of Credit | Southern Company Gas Capital
Debt Instrument [Line Items]
Termination of credit arrangement							1,300,000,000
Line of Credit | Nicor Gas | Line of Credit
Debt Instrument [Line Items]
Termination of credit arrangement							$ 700,000,000
Scenario, Forecast | Nicor Gas | Collateralized Mortgage Backed Securities | First Mortgage Bonds
Debt Instrument [Line Items]
Debt face amount													$ 200,000,000
Subsequent Event | GEORGIA POWER CO
Debt Instrument [Line Items]
Fixed rate pollution control revenue bonds outstanding, amount remarketed			$ 40,000,000
Subsequent Event | GEORGIA POWER CO | Senior Notes | Preferred Class A
Debt Instrument [Line Items]
Stock redeemed during period (in shares) | shares			1,800
Value of stock redeemed			$ 45,000,000
Preferred stock, dividend rate			6.125%
Subsequent Event | GEORGIA POWER CO | Senior Notes | Series 2007A Preference Stock
Debt Instrument [Line Items]
Stock redeemed during period (in shares) | shares			2,250
Value of stock redeemed			$ 225,000,000
Preferred stock, dividend rate			6.50%
Subsequent Event | ALABAMA POWER CO | Senior Notes | 6.50% Series Preference Stock
Debt Instrument [Line Items]
Stock redeemed during period (in shares) | shares			2,000
Value of stock redeemed			$ 50,000,000
Preferred stock, dividend rate			6.50%
Subsequent Event | ALABAMA POWER CO | Senior Notes | 6.45% Series Preference Stock
Debt Instrument [Line Items]
Stock redeemed during period (in shares) | shares			6,000
Value of stock redeemed			$ 150,000,000
Preferred stock, dividend rate			6.45%
Subsequent Event | ALABAMA POWER CO | Senior Notes | 5.83% Class A Preferred Stock
Debt Instrument [Line Items]
Stock redeemed during period (in shares) | shares			1,520
Value of stock redeemed			$ 38,000,000
Preferred stock, dividend rate			5.83%

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Financing - Schedule of Credit Arrangements (Details) - USD ($)	Sep. 30, 2017	May 31, 2017
Line of Credit Facility [Line Items]
Expires, 2017	$ 130,000,000
Expires, 2018	260,000,000
Expires, 2019	25,000,000
Expires, 2020	530,000,000
Expires, 2022	7,200,000,000
Total	8,145,000,000
Unused	8,066,000,000
Executable Term Loans, One Year	65,000,000
Executable Term Loans, Two Years	0
Expires Within One Year, Term Out	20,000,000
Expires Within One Year, No Term Out	185,000,000
Southern Company
Line of Credit Facility [Line Items]
Expires, 2017	0
Expires, 2018	0
Expires, 2019	0
Expires, 2020	0
Expires, 2022	2,000,000,000
Total	2,000,000,000	$ 1,250,000,000.00
Unused	2,000,000,000
Executable Term Loans, One Year	0
Executable Term Loans, Two Years	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, 2017	0
Expires, 2018	35,000,000
Expires, 2019	0
Expires, 2020	500,000,000
Expires, 2022	800,000,000
Total	1,335,000,000
Unused	1,335,000,000
Executable Term Loans, One Year	0
Executable Term Loans, Two Years	0
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	35,000,000
GEORGIA POWER CO
Line of Credit Facility [Line Items]
Expires, 2017	0
Expires, 2018	0
Expires, 2019	0
Expires, 2020	0
Expires, 2022	1,750,000,000
Total	1,750,000,000
Unused	1,732,000,000
Executable Term Loans, One Year	0
Executable Term Loans, Two Years	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, 2017	30,000,000
Expires, 2018	195,000,000
Expires, 2019	25,000,000
Expires, 2020	30,000,000
Expires, 2022	0
Total	280,000,000
Unused	280,000,000
Executable Term Loans, One Year	45,000,000
Executable Term Loans, Two Years	0
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	40,000,000
MISSISSIPPI POWER CO
Line of Credit Facility [Line Items]
Expires, 2017	100,000,000
Expires, 2018	0
Expires, 2019	0
Expires, 2020	0
Expires, 2022	0
Total	100,000,000
Unused	100,000,000
Executable Term Loans, One Year	0
Executable Term Loans, Two Years	0
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	100,000,000
SOUTHERN POWER CO
Line of Credit Facility [Line Items]
Expires, 2017	0
Expires, 2018	0
Expires, 2019	0
Expires, 2020	0
Expires, 2022	750,000,000
Total	750,000,000	600,000,000
Unused	728,000,000
Executable Term Loans, One Year	0
Executable Term Loans, Two Years	0
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	0
SOUTHERN Co GAS
Line of Credit Facility [Line Items]
Expires, 2017	0
Expires, 2018	0
Expires, 2019	0
Expires, 2020	0
Expires, 2022	1,900,000,000
Total	1,900,000,000
Unused	1,861,000,000
Executable Term Loans, One Year	0
Executable Term Loans, Two Years	0
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	0
Other
Line of Credit Facility [Line Items]
Expires, 2017	0
Expires, 2018	30,000,000
Expires, 2019	0
Expires, 2020	0
Expires, 2022	0
Total	30,000,000
Unused	30,000,000
Executable Term Loans, One Year	20,000,000
Executable Term Loans, Two Years	0
Expires Within One Year, Term Out	20,000,000
Expires Within One Year, No Term Out	10,000,000
Southern Company Gas Capital
Line of Credit Facility [Line Items]
Total	1,200,000,000.0	1,200,000,000.0
Nicor Gas
Line of Credit Facility [Line Items]
Total	700,000,000	$ 700,000,000
Standby Letters of Credit | SOUTHERN POWER CO
Line of Credit Facility [Line Items]
Total	120,000,000
Unused	9,000,000
Long-term line of credit	$ 111,000,000

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Financing - Schedule of Long-Term Debt Financing Activities (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017 USD ($)
Debt Instrument [Line Items]
Senior Note Issuances	$ 2,950
Senior Note Maturities and Redemptions	1,135
Revenue Bond Maturities, Redemptions, and Repurchases	101
Other Long-Term Debt Issuances	1,119
Other Long-Term Debt Redemptions and Maturities	745
Southern Company
Debt Instrument [Line Items]
Senior Note Issuances	300
Senior Note Maturities and Redemptions	400
Revenue Bond Maturities, Redemptions, and Repurchases	0
Other Long-Term Debt Issuances	500
Other Long-Term Debt Redemptions and Maturities	400
ALABAMA POWER CO
Debt Instrument [Line Items]
Senior Note Issuances	550
Senior Note Maturities and Redemptions	200
Revenue Bond Maturities, Redemptions, and Repurchases	36
Other Long-Term Debt Issuances	0
Other Long-Term Debt Redemptions and Maturities	0
GEORGIA POWER CO
Debt Instrument [Line Items]
Senior Note Issuances	1,350
Senior Note Maturities and Redemptions	450
Revenue Bond Maturities, Redemptions, and Repurchases	65
Other Long-Term Debt Issuances	370
Other Long-Term Debt Redemptions and Maturities	13
GULF POWER CO
Debt Instrument [Line Items]
Senior Note Issuances	300
Senior Note Maturities and Redemptions	85
Revenue Bond Maturities, Redemptions, and Repurchases	0
Other Long-Term Debt Issuances	6
Other Long-Term Debt Redemptions and Maturities	0
MISSISSIPPI POWER CO
Debt Instrument [Line Items]
Senior Note Issuances	0
Senior Note Maturities and Redemptions	0
Revenue Bond Maturities, Redemptions, and Repurchases	0
Other Long-Term Debt Issuances	40
Other Long-Term Debt Redemptions and Maturities	893
SOUTHERN POWER CO
Debt Instrument [Line Items]
Senior Note Issuances	0
Senior Note Maturities and Redemptions	0
Revenue Bond Maturities, Redemptions, and Repurchases	0
Other Long-Term Debt Issuances	43
Other Long-Term Debt Redemptions and Maturities	4
SOUTHERN Co GAS
Debt Instrument [Line Items]
Senior Note Issuances	450
Senior Note Maturities and Redemptions	0
Revenue Bond Maturities, Redemptions, and Repurchases	0
Other Long-Term Debt Issuances	200
Other Long-Term Debt Redemptions and Maturities	22
Other
Debt Instrument [Line Items]
Senior Note Issuances	0
Senior Note Maturities and Redemptions	0
Revenue Bond Maturities, Redemptions, and Repurchases	0
Other Long-Term Debt Issuances	0
Other Long-Term Debt Redemptions and Maturities	12
Elimination
Debt Instrument [Line Items]
Senior Note Issuances	0
Senior Note Maturities and Redemptions	0
Revenue Bond Maturities, Redemptions, and Repurchases	0
Other Long-Term Debt Issuances	(40)
Other Long-Term Debt Redemptions and Maturities	$ (599)

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Retirement Benefits (Details) - USD ($)	3 Months Ended		6 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, expected future employer contributions, remainder of fiscal year	$ 0			$ 0
Pension Plans | Southern Company
Pension Plans and Postretirement Plans
Service cost	73,000,000	$ 68,000,000		220,000,000	$ 192,000,000
Interest cost	114,000,000	110,000,000		341,000,000	311,000,000
Expected return on plan assets	(224,000,000)	(203,000,000)		(673,000,000)	(577,000,000)
Amortization:
Prior service costs	3,000,000	3,000,000		9,000,000	10,000,000
Net (gain)/loss	41,000,000	45,000,000		122,000,000	120,000,000
Net periodic pension cost (income)	7,000,000	23,000,000		19,000,000	56,000,000
Pension Plans | SOUTHERN Co GAS
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, expected future employer contributions, remainder of fiscal year	0			0
Pension Plans and Postretirement Plans
Service cost	6,000,000	7,000,000		17,000,000
Interest cost	10,000,000	10,000,000		30,000,000
Expected return on plan assets	(18,000,000)	(17,000,000)		(53,000,000)
Amortization of regulatory asset		6,000,000
Amortization:
Prior service costs				(1,000,000)
Net (gain)/loss	5,000,000			15,000,000
Net periodic pension cost (income)	3,000,000	6,000,000		8,000,000
Pension Plans | ALABAMA POWER CO
Pension Plans and Postretirement Plans
Service cost	15,000,000	14,000,000		47,000,000	43,000,000
Interest cost	25,000,000	23,000,000		73,000,000	71,000,000
Expected return on plan assets	(49,000,000)	(46,000,000)		(147,000,000)	(138,000,000)
Amortization:
Prior service costs	1,000,000	1,000,000		2,000,000	2,000,000
Net (gain)/loss	10,000,000	10,000,000		31,000,000	30,000,000
Net periodic pension cost (income)	2,000,000	2,000,000		6,000,000	8,000,000
Pension Plans | GEORGIA POWER CO
Pension Plans and Postretirement Plans
Service cost	19,000,000	17,000,000		56,000,000	52,000,000
Interest cost	34,000,000	34,000,000		103,000,000	102,000,000
Expected return on plan assets	(71,000,000)	(64,000,000)		(212,000,000)	(193,000,000)
Amortization:
Prior service costs	0	1,000,000		2,000,000	4,000,000
Net (gain)/loss	15,000,000	14,000,000		43,000,000	41,000,000
Net periodic pension cost (income)	(3,000,000)	2,000,000		(8,000,000)	6,000,000
Pension Plans | GULF POWER CO
Pension Plans and Postretirement Plans
Service cost	3,000,000	3,000,000		10,000,000	9,000,000
Interest cost	5,000,000	5,000,000		15,000,000	14,000,000
Expected return on plan assets	(10,000,000)	(9,000,000)		(29,000,000)	(26,000,000)
Amortization:
Prior service costs	0	0		0	1,000,000
Net (gain)/loss	2,000,000	2,000,000		5,000,000	5,000,000
Net periodic pension cost (income)	0	1,000,000		1,000,000	3,000,000
Pension Plans | MISSISSIPPI POWER CO
Pension Plans and Postretirement Plans
Service cost	4,000,000	3,000,000		11,000,000	9,000,000
Interest cost	5,000,000	4,000,000		15,000,000	14,000,000
Expected return on plan assets	(9,000,000)	(9,000,000)		(29,000,000)	(26,000,000)
Amortization:
Prior service costs	0	1,000,000		1,000,000	1,000,000
Net (gain)/loss	1,000,000	2,000,000		5,000,000	5,000,000
Net periodic pension cost (income)	1,000,000	1,000,000		3,000,000	3,000,000
Postretirement Benefits | Southern Company
Pension Plans and Postretirement Plans
Service cost	6,000,000	6,000,000		18,000,000	17,000,000
Interest cost	19,000,000	20,000,000		59,000,000	55,000,000
Expected return on plan assets	(16,000,000)	(16,000,000)		(49,000,000)	(44,000,000)
Amortization:
Prior service costs	2,000,000	1,000,000		5,000,000	4,000,000
Net (gain)/loss	3,000,000	5,000,000		10,000,000	12,000,000
Net periodic pension cost (income)	14,000,000	16,000,000		43,000,000	44,000,000
Postretirement Benefits | SOUTHERN Co GAS
Pension Plans and Postretirement Plans
Service cost	1,000,000	1,000,000		2,000,000
Interest cost	3,000,000	2,000,000		8,000,000
Expected return on plan assets	(2,000,000)	(2,000,000)		(5,000,000)
Amortization of regulatory asset		1,000,000
Amortization:
Prior service costs	(1,000,000)			(2,000,000)
Net (gain)/loss	1,000,000			3,000,000
Net periodic pension cost (income)	2,000,000	2,000,000		6,000,000
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	4,000,000	5,000,000		13,000,000	14,000,000
Expected return on plan assets	(5,000,000)	(6,000,000)		(19,000,000)	(19,000,000)
Amortization:
Prior service costs	1,000,000	1,000,000		3,000,000	3,000,000
Net (gain)/loss	0	0		1,000,000	1,000,000
Net periodic pension cost (income)	1,000,000	1,000,000		2,000,000	3,000,000
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	6,000,000	7,000,000		21,000,000	22,000,000
Expected return on plan assets	(6,000,000)	(6,000,000)		(18,000,000)	(17,000,000)
Amortization:
Prior service costs	0	0		1,000,000	1,000,000
Net (gain)/loss	3,000,000	3,000,000		6,000,000	7,000,000
Net periodic pension cost (income)	5,000,000	6,000,000		15,000,000	18,000,000
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
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	1,000,000	0		3,000,000	2,000,000
Expected return on plan assets	0	0		(1,000,000)	(1,000,000)
Amortization:
Prior service costs	0	0		0	0
Net (gain)/loss	0	1,000,000		0	1,000,000
Net periodic pension cost (income)	$ 1,000,000	$ 1,000,000		$ 3,000,000	$ 3,000,000
Predecessor | Pension Plans | SOUTHERN Co GAS
Pension Plans and Postretirement Plans
Service cost			$ 13,000,000
Interest cost			21,000,000
Expected return on plan assets			(33,000,000)
Amortization:
Prior service costs			(1,000,000)
Net (gain)/loss			13,000,000
Net periodic pension cost (income)			13,000,000
Predecessor | Postretirement Benefits | SOUTHERN Co GAS
Pension Plans and Postretirement Plans
Service cost			1,000,000
Interest cost			5,000,000
Expected return on plan assets			(3,000,000)
Amortization:
Prior service costs			(1,000,000)
Net (gain)/loss			2,000,000
Net periodic pension cost (income)			$ 4,000,000

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Income Taxes (Details) - USD ($) $ in Millions		3 Months Ended			6 Months Ended	9 Months Ended
	Sep. 08, 2017	Dec. 31, 2017	Sep. 30, 2017	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Dec. 31, 2016
Income Tax Contingency [Line Items]
Deferred tax assets, valuation allowance								$ 82	$ 21
Effective tax rate						42.60%	28.30%
Income benefit			$ (590)	$ (439)		$ (317)	$ (917)
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits as of December 31, 2016		$ 17				484
Tax positions from current periods						9
Tax positions from prior periods						186
Reductions due to settlements						290
Balance as of September 30, 2017			17			17
Tax positions impacting the effective tax rate								17	20
Tax positions not impacting the effective tax rate								0	464
Balance of unrecognized tax benefits		17	17			$ 484		17	484
Significantly increase (decrease) in amount of unrecognized tax benefits						12 months
Kemper IGCC
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Tax positions from prior periods	$ 36
Balance as of September 30, 2017	176
Balance of unrecognized tax benefits	$ 176
MISSISSIPPI POWER CO
Income Tax Contingency [Line Items]
Deferred tax assets, valuation allowance								46
Effective tax rate						(30.30%)	(282.80%)
Income benefit			(24)	$ 2		$ 885	$ 29
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits as of December 31, 2016		2				465
Tax positions from current periods						2
Tax positions from prior periods						175
Reductions due to settlements						290
Balance as of September 30, 2017			2			2
Tax positions impacting the effective tax rate								2
Tax positions not impacting the effective tax rate								0
Balance of unrecognized tax benefits		2	2			465		2	465
MISSISSIPPI POWER CO | Kemper IGCC
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits as of December 31, 2016
Balance as of September 30, 2017
Balance of unrecognized tax benefits
Interest on accrued income taxes
SOUTHERN Co GAS
Income Tax Contingency [Line Items]
Deferred tax assets, valuation allowance								19
Effective tax rate				60.30%		43.40%
Income benefit			(52)	$ (7)		$ (233)
SOUTHERN POWER CO
Income Tax Contingency [Line Items]
Effective tax rate						(66.50%)	(88.90%)
Income benefit			39	$ 102		$ 129	$ 167
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits as of December 31, 2016		0				17
Tax positions from current periods						0
Tax positions from prior periods						17
Reductions due to settlements						0
Balance as of September 30, 2017			0			0
Balance of unrecognized tax benefits		0	$ 0			$ 17		0	17
Investment Tax Credit Carryforward
Income Tax Contingency [Line Items]
Tax credit carryforward, amount								1,900	$ 1,800
Federal
Income Tax Contingency [Line Items]
Deferred tax assets, valuation allowance								18
Federal | MISSISSIPPI POWER CO
Income Tax Contingency [Line Items]
Deferred tax assets, valuation allowance								0
Federal | SOUTHERN Co GAS
Income Tax Contingency [Line Items]
Deferred tax assets, valuation allowance								18
State (net of federal benefit)
Income Tax Contingency [Line Items]
Deferred tax assets, valuation allowance								64
State (net of federal benefit) | MISSISSIPPI POWER CO
Income Tax Contingency [Line Items]
Deferred tax assets, valuation allowance								46
State (net of federal benefit) | SOUTHERN Co GAS
Income Tax Contingency [Line Items]
Deferred tax assets, valuation allowance								$ 1
Scenario, Forecast | SOUTHERN POWER CO
Income Tax Contingency [Line Items]
Income benefit		$ 40
Predecessor | SOUTHERN Co GAS
Income Tax Contingency [Line Items]
Effective tax rate					37.60%
Income benefit					$ (87)

XML

Derivatives - Energy-Related and Interest Rate Derivatives (Details) MMBTU in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2017 USD ($) MMBTU
Interest rate derivatives
Interest rate derivatives
Notional Amount	$ 3,650
Fair Value Gain (Loss) at September 30, 2017	$ (19)
Southern Company | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	463
Longest Hedge Date	2021
Longest Non-Hedge Date	2024
Southern Company | Interest rate derivatives | 2020-06-01 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Notional Amount	$ 300
Interest Rate Received	2.75%
Fair Value Gain (Loss) at September 30, 2017	$ 0
Southern Company | Interest rate derivatives | 2020-06-01 | London Interbank Offered Rate (LIBOR) | Fair Value Hedges of Existing Debt
Interest rate derivatives
Weighted Average Interest Rate Paid	0.92%
Southern Company | Interest rate derivatives | 7/31/2021 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Notional Amount	$ 1,500
Interest Rate Received	2.35%
Fair Value Gain (Loss) at September 30, 2017	$ (19)
Southern Company | Interest rate derivatives | 7/31/2021 | London Interbank Offered Rate (LIBOR) | Fair Value Hedges of Existing Debt
Interest rate derivatives
Weighted Average Interest Rate Paid	0.87%
ALABAMA POWER CO | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	66
Longest Hedge Date	2020
GEORGIA POWER CO | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	159
Longest Hedge Date	2021
GEORGIA POWER CO | Interest rate derivatives | 6/1/2018 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Notional Amount	$ 250
Interest Rate Received	5.40%
Fair Value Gain (Loss) at September 30, 2017	$ 0
GEORGIA POWER CO | Interest rate derivatives | 6/1/2018 | London Interbank Offered Rate (LIBOR) | Fair Value Hedges of Existing Debt
Interest rate derivatives
Weighted Average Interest Rate Paid	4.02%
GEORGIA POWER CO | Interest rate derivatives | 12/1/2018 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Notional Amount	$ 500
Interest Rate Received	1.95%
Fair Value Gain (Loss) at September 30, 2017	$ (2)
GEORGIA POWER CO | Interest rate derivatives | 12/1/2018 | London Interbank Offered Rate (LIBOR) | Fair Value Hedges of Existing Debt
Interest rate derivatives
Weighted Average Interest Rate Paid	0.76%
GEORGIA POWER CO | Interest rate derivatives | 12/1/2019 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Notional Amount	$ 200
Interest Rate Received	4.25%
Fair Value Gain (Loss) at September 30, 2017	$ 0
GEORGIA POWER CO | Interest rate derivatives | 12/1/2019 | London Interbank Offered Rate (LIBOR) | Fair Value Hedges of Existing Debt
Interest rate derivatives
Weighted Average Interest Rate Paid	2.46%
GULF POWER CO | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	28
Longest Hedge Date	2020
MISSISSIPPI POWER CO | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	44
Longest Hedge Date	2021
MISSISSIPPI POWER CO | Interest rate derivatives | 3/1/2018 | Cash Flow Hedges of Existing Debt
Interest rate derivatives
Notional Amount	$ 900
Weighted Average Interest Rate Paid	0.79%
Fair Value Gain (Loss) at September 30, 2017	$ 2
SOUTHERN POWER CO | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	13
Longest Hedge Date	2018
SOUTHERN Co GAS | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	153
Longest Hedge Date	2020
Longest Non-Hedge Date	2024
SOUTHERN Co GAS | Energy-related, Natural Gas | Long | Derivatives not designated as hedging instruments
Energy-related derivative contracts
Derivative nonmonetary notional amount net long short position volume | MMBTU	3,300
SOUTHERN Co GAS | Energy-related, Natural Gas | Short | Derivatives not designated as hedging instruments
Energy-related derivative contracts
Derivative nonmonetary notional amount net long short position volume | MMBTU	3,100

XML

Derivatives - Narrative (Details) MMBTU in Millions	9 Months Ended
	Sep. 30, 2017 USD ($) MMBTU	Dec. 31, 2016 USD ($)
Derivative [Line Items]
Collateral already posted, aggregate fair value	$ 76,000,000
Southern Company
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	34
Cash flow hedge gain (loss) to be reclassified within twelve months	$ (19,000,000)
GEORGIA POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	11
ALABAMA POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	5
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 | MMBTU	3
MISSISSIPPI POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | MMBTU	4
SOUTHERN POWER CO
Derivative [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months	$ 5,000,000
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)
SOUTHERN Co GAS
Derivative [Line Items]
Collateral already posted, aggregate fair value	76,000,000	$ 62,000,000
Derivative Counterparties | Registrants
Derivative [Line Items]
Collateral already posted, aggregate fair value	$ 0

XML

Derivatives - Foreign Currency Derivatives (Details) - 9 months ended Sep. 30, 2017 - Cash Flow Hedges of Existing Debt - Foreign Exchange Contract € in Millions, $ in Millions	USD ($)	EUR (€)
Derivative [Line Items]
Pay Notional	$ 1,241
Receive Notional | €		€ 1,100
Fair Value Gain (Loss) at September 30, 2017	80
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, 2017	$ 42
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, 2017	$ 38

XML

Derivatives - Derivative Financial Statement Presentation and Amounts With Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Collateral already posted, aggregate fair value	$ 76
Southern Company
Derivatives, Fair Value [Line Items]
Derivatives, assets	536	$ 690
Derivatives, liabilities	458	718
Derivative asset amount offset	(275)	(462)
Derivative liability amount offset	(351)	(524)
Derivative asset	261	228
Derivative liability	107	194
Southern Company | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivatives, assets	386	556
Derivatives, liabilities	357	564
Southern Company | Derivatives not designated as hedging instruments | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	271	489
Southern Company | Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	115	66
Southern Company | Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	103	81
Southern Company | Derivatives not designated as hedging instruments | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	254	483
Southern Company | Derivatives not designated as hedging instruments | Interest rate derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	1
Southern Company | Derivatives not designated as hedging instruments | Interest rate derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
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	34	98
Derivatives, liabilities	48	60
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	21	73
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	13	25
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	23	33
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	25	27
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	116	36
Derivatives, liabilities	53	94
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	8	23
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	7
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	5	12
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	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 deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	23	28
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	1	1
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 deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	103	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 deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	33
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	25
ALABAMA POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	9	20
Derivatives, liabilities	7	9
Derivative asset amount offset	(5)	(8)
Derivative liability amount offset	(5)	(8)
Derivative asset	4	12
Derivative liability	2	1
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	9	20
Derivatives, liabilities	7	9
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	6	13
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	3	7
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	3	4
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	5
GEORGIA POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	19	46
Derivatives, liabilities	14	11
Derivative asset amount offset	(10)	(8)
Derivative liability amount offset	(10)	(8)
Derivative asset	9	38
Derivative liability	4	3
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	18	44
Derivatives, liabilities	11	8
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	10	30
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	8	14
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	8	7
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	3	1
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	1	2
Derivatives, liabilities	3	3
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	1	2
GEORGIA POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other 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	2	3
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	1	0
GULF POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	5
Derivatives, liabilities	22	29
Derivative asset amount offset	0	(4)
Derivative liability amount offset	0	(4)
Derivative asset	0	1
Derivative liability	22	25
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	5
Derivatives, liabilities	22	29
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	4
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	1
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	9	17
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	13	12
MISSISSIPPI POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	5	7
Derivatives, liabilities	7	11
Derivative asset amount offset	(3)	(3)
Derivative liability amount offset	(3)	(3)
Derivative asset	2	4
Derivative liability	4	8
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	4
Derivatives, liabilities	7	11
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	1	2
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	2	2
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	3	5
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	4	6
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	2	3
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	2	2
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 deferred charges and 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 deferred credits and liabilities
Derivatives, Fair Value [Line Items]
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 liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
SOUTHERN POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	112	22
Derivatives, liabilities	27	63
Derivative asset amount offset	(1)	(5)
Derivative liability amount offset	(1)	(5)
Derivative asset	111	17
Derivative liability	26	58
SOUTHERN POWER CO | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	4
Derivatives, liabilities	0	1
SOUTHERN POWER CO | Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	3
SOUTHERN POWER CO | Derivatives not designated as hedging instruments | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	1
SOUTHERN POWER CO | Derivatives not designated as hedging instruments | Interest rate derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	1
SOUTHERN POWER CO | Derivatives not designated as hedging instruments | Interest rate derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	111	18
Derivatives, liabilities	27	62
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	8	18
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	4	4
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 deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	103	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 deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	33
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	25
SOUTHERN Co GAS
Derivatives, Fair Value [Line Items]
Derivatives, assets	389	581
Derivatives, liabilities	360	569
Derivative asset amount offset	(251)	(435)
Derivative liability amount offset	(327)	(497)
Derivative asset	138	146
Derivative liability	33	72
Collateral already posted, aggregate fair value	76	62
SOUTHERN Co GAS | Energy-related derivatives
Derivatives, Fair Value [Line Items]
Collateral already posted, aggregate fair value	1	8
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives
Derivatives, Fair Value [Line Items]
Derivatives, assets	385	552
Derivatives, liabilities	357	563
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	115	66
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	103	81
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, assets	270	486
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	254	482
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	4	25
Derivatives, liabilities	1	3
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	1
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	0	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	4	24
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	3
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	0	4
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	$ 2	$ 3

XML

Derivatives - Pre-tax Effects of Derivatives Designated as Cash Flow Hedging Instruments (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Collateral already posted, aggregate fair value	$ 76			$ 76
Southern Company
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	39	$ 31		86	$ (191)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	27	(4)		95	(32)
Southern Company | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(14)			(14)		$ 33
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(6)	0		(26)	(1)
Southern Company | Energy-related derivatives | Depreciation and amortization
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(6)	1		(12)	1
Southern Company | Energy-related derivatives | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(18)			(18)		(16)
Southern Company | Energy-related derivatives | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(12)			(12)		(19)
Southern Company | Energy-related derivatives | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	14			14		56
Southern Company | Energy-related derivatives | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	2			2		12
Southern Company | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(1)	(6)		(2)	(189)
Southern Company | Interest rate derivatives | Interest expense, net of amounts capitalized
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(5)	(6)		(15)	(13)
Southern Company | Foreign Exchange Contract
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	46	37		114	(1)
Southern Company | Foreign Exchange Contract | Interest expense, net of amounts capitalized
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(5)	(6)		(17)	(7)
Southern Company | Foreign Exchange Contract | Other income (expense), net
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	43	7		139	(13)
ALABAMA POWER CO | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	2			2		11
ALABAMA POWER CO | Energy-related derivatives | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(1)			(1)		(1)
ALABAMA POWER CO | Energy-related derivatives | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(1)			(1)		0
ALABAMA POWER CO | Energy-related derivatives | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	3			3		8
ALABAMA POWER CO | Energy-related derivatives | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	1			1		4
ALABAMA POWER CO | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	0		0	(3)
ALABAMA POWER CO | Interest rate derivatives | Interest expense, net of amounts capitalized
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(2)	(2)		(5)	(5)
GEORGIA POWER CO | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	7			7		36
GEORGIA POWER CO | Energy-related derivatives | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0			0		0
GEORGIA POWER CO | Energy-related derivatives | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(1)			(1)		0
GEORGIA POWER CO | Energy-related derivatives | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	7			7		29
GEORGIA POWER CO | Energy-related derivatives | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	1			1		7
GEORGIA POWER CO | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	0		0	0
GEORGIA POWER CO | Interest rate derivatives | Interest expense, net of amounts capitalized
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(1)	(1)		(3)	(3)
GULF POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)				(2)	(7)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)				0	0
GULF POWER CO | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(22)			(22)		(24)
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)				(1)	0
GULF POWER CO | Energy-related derivatives | Depreciation and amortization
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)				0	0
GULF POWER CO | Energy-related derivatives | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(13)			(13)		(9)
GULF POWER CO | Energy-related derivatives | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(9)			(9)		(16)
GULF POWER CO | Energy-related derivatives | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0			0		1
GULF POWER CO | Energy-related derivatives | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0			0		0
GULF POWER CO | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)				(1)	(7)
GULF POWER CO | Interest rate derivatives | Interest expense, net of amounts capitalized
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)				0	0
MISSISSIPPI POWER CO | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(4)			(4)		(7)
MISSISSIPPI POWER CO | Energy-related derivatives | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(3)			(3)		(5)
MISSISSIPPI POWER CO | Energy-related derivatives | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(1)			(1)		(3)
MISSISSIPPI POWER CO | Energy-related derivatives | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0			0		1
MISSISSIPPI POWER CO | Energy-related derivatives | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0			0		0
MISSISSIPPI POWER CO | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(1)	(1)		0	(1)
MISSISSIPPI POWER CO | Interest rate derivatives | Interest expense, net of amounts capitalized
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	0	0		(1)	(1)
SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Collateral already posted, aggregate fair value	76			76		62
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)		(5)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)		0
SOUTHERN Co GAS | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	3			3		17
Collateral already posted, aggregate fair value	1			1		8
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)		0		(4)
SOUTHERN Co GAS | Energy-related derivatives | Cost of natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)		0		0
SOUTHERN Co GAS | Energy-related derivatives | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(1)			(1)		(1)
SOUTHERN Co GAS | Energy-related derivatives | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0			0		0
SOUTHERN Co GAS | Energy-related derivatives | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	4			4		17
SOUTHERN Co GAS | Energy-related derivatives | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0			0		$ 1
SOUTHERN Co GAS | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	(5)
SOUTHERN Co GAS | Interest rate derivatives | Interest expense, net of amounts capitalized
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	0	0
SOUTHERN POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	40	37		93	(2)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	32	2		110	(20)
SOUTHERN POWER CO | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(6)	0		(21)	(1)
SOUTHERN POWER CO | Energy-related derivatives | Depreciation and amortization
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(6)	1		(12)	1
SOUTHERN POWER CO | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)				0	0
SOUTHERN POWER CO | Interest rate derivatives | Interest expense, net of amounts capitalized
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)				0	(1)
SOUTHERN POWER CO | Foreign Exchange Contract
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	46	37		114	(1)
SOUTHERN POWER CO | Foreign Exchange Contract | Interest expense, net of amounts capitalized
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(5)	(6)		(17)	(7)
SOUTHERN POWER CO | Foreign Exchange Contract | Other income (expense), net
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	$ 43	$ 7		$ 139	$ (13)
Predecessor | SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			$ (64)
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			(1)
Predecessor | SOUTHERN Co GAS | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			0
Predecessor | SOUTHERN Co GAS | Energy-related derivatives | Cost of natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			(1)
Predecessor | SOUTHERN Co GAS | Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			(64)
Predecessor | SOUTHERN Co GAS | Interest rate derivatives | Interest expense, net of amounts capitalized
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			$ 0

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Derivatives - Pre-tax Effects of Derivatives Not Designated as Hedging (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Energy-related derivatives | Derivatives not designated as hedging instruments
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	$ (15)	$ 6		$ 46	$ 6
Energy-related derivatives | Natural gas revenues | Derivatives not designated as hedging instruments
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	(17)	0		48	0
Energy-related derivatives | Cost of natural gas | Derivatives not designated as hedging instruments
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	2	6		(2)	$ 6
Southern Company | Weather Derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, gain (loss) on derivative, net				15
SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, gain (loss) on derivative, net		(17)		32
SOUTHERN Co GAS | Energy-related derivatives | Derivatives not designated as hedging instruments
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	(15)	6		46
SOUTHERN Co GAS | Energy-related derivatives | Natural gas revenues | Derivatives not designated as hedging instruments
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	(17)	0		48
SOUTHERN Co GAS | Energy-related derivatives | Cost of natural gas | Derivatives not designated as hedging instruments
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	$ 2	$ 6		(2)
SOUTHERN Co GAS | Weather Derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, gain (loss) on derivative, net				$ 15
SOUTHERN Co GAS | Predecessor
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, gain (loss) on derivative, net			$ (162)
SOUTHERN Co GAS | Predecessor | Energy-related derivatives | Derivatives not designated as hedging instruments
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net			(63)
SOUTHERN Co GAS | Predecessor | Energy-related derivatives | Natural gas revenues | Derivatives not designated as hedging instruments
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net			(1)
SOUTHERN Co GAS | Predecessor | Energy-related derivatives | Cost of natural gas | Derivatives not designated as hedging instruments
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net			$ (62)

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Derivatives - Pre-tax Effects of Derivatives as Fair Value Hedging Relationships (Details) - Interest rate derivatives - Interest expense, net of amounts capitalized - Fair Value Hedging - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Southern Company
Derivative Instruments, Gain (Loss) [Line Items]
Derivative assets, fair value, gross asset	$ (5)	$ (9)	$ (6)	$ 15
GEORGIA POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Derivative assets, fair value, gross asset	$ 0	$ (5)	$ (1)	$ 10

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Acquisitions and Dispositions - Narrative (Details) $ / shares in Units, MW in Thousands, $ in Millions			1 Months Ended		3 Months Ended			9 Months Ended		36 Months Ended
	Jul. 01, 2016 USD ($)	May 09, 2016 USD ($) $ / shares	Oct. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Dec. 31, 2020	Jan. 06, 2017	Dec. 31, 2016 USD ($) MW
Business Acquisition [Line Items]
Goodwill				$ 6,267		$ 6,267		$ 6,267				$ 6,251
Revenues						6,201	$ 6,264	17,403	$ 14,715
Consolidated net income attributable to Southern Company						1,069	1,139	347	2,251
Construction work in progress				8,026		8,026		8,026				8,977
SOUTHERN Co GAS
Business Acquisition [Line Items]
Goodwill				5,967		5,967		5,967				5,967
Revenues						565	543	2,841
Consolidated net income attributable to Southern Company						15	4	303
Construction work in progress				596		596		596				496
SOUTHERN POWER CO
Business Acquisition [Line Items]
Goodwill				2		2		2				2
Revenues						618	500	1,597	1,189
Consolidated net income attributable to Southern Company						124	176	276	315
Total costs of construction								494
Construction work in progress				425		425		425				$ 398
Repayments of debt				40
SOUTHERN Co GAS
Business Acquisition [Line Items]
Aggregate purchase price	$ 8,000
Goodwill				5,967		5,967		$ 5,967
SOUTHERN Co GAS | Minimum
Business Acquisition [Line Items]
Estimated lives of intangible assets								1 year
SOUTHERN Co GAS | Maximum
Business Acquisition [Line Items]
Estimated lives of intangible assets								28 years
PowerSecure International, Inc.
Business Acquisition [Line Items]
Aggregate purchase price		$ 429
Goodwill				284		284		$ 284
Acquisition, share price (in dollars per share) | $ / shares		$ 18.75
PowerSecure International, Inc. | Minimum
Business Acquisition [Line Items]
Estimated lives of intangible assets								1 year
PowerSecure International, Inc. | Maximum
Business Acquisition [Line Items]
Estimated lives of intangible assets								26 years
Bethel | SOUTHERN POWER CO
Business Acquisition [Line Items]
Ownership percentage by parent											100.00%
Series of Construction Projects | SOUTHERN POWER CO
Business Acquisition [Line Items]
Construction work in progress				122		122		$ 122
Series of Construction Projects | Minimum | SOUTHERN POWER CO
Business Acquisition [Line Items]
Estimated future construction payments				360		360		360
Series of Construction Projects | Maximum | SOUTHERN POWER CO
Business Acquisition [Line Items]
Estimated future construction payments				$ 415		415		415
Scenario, Forecast | Elizabethtown Gas and Elkton Gas
Business Acquisition [Line Items]
Aggregate purchase price					$ 1,700
Renewable Energy Systems Americas, Inc. | SOUTHERN POWER CO
Business Acquisition [Line Items]
Approximate nameplate capacity, wind (MW) | MW												3
Wind Generating Facility | Scenario, Forecast | SOUTHERN POWER CO
Business Acquisition [Line Items]
Project qualification for production tax credits, percentage										100.00%
Production tax credits, project qualification period										10 years
Operating Segments | SOUTHERN Co GAS
Business Acquisition [Line Items]
Revenues						607	586	3,000
Consolidated net income attributable to Southern Company						44		325
SOUTHERN Co GAS | Operating Segments
Business Acquisition [Line Items]
Revenues						565	543	2,841	543
Consolidated net income attributable to Southern Company						$ 15	$ 4	$ 303	$ 4
Subsequent Event | Southern Turner Renewable Energy, LLC [Member] | SOUTHERN POWER CO
Business Acquisition [Line Items]
Ownership percentage by parent			10.00%
Repayments of debt			$ 14

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Acquisitions and Dispositions - Schedule of Acquisitions (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Goodwill	$ 6,267	$ 6,251
SOUTHERN Co GAS
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Current assets	1,557
Property, plant, and equipment	10,108
Goodwill	5,967
Intangible assets	400
Regulatory assets	1,118
Other assets	229
Current liabilities	(2,201)
Other liabilities	(4,742)
Long-term debt	(4,261)
Noncontrolling interest	(174)
Total purchase price	8,001
PowerSecure International, Inc.
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Current assets	172
Property, plant, and equipment	46
Goodwill	284
Intangible assets	106
Other assets	4
Current liabilities	(121)
Long-term debt, including current portion	(48)
Other liabilities	(14)
Total purchase price	429
SOUTHERN POWER CO
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Goodwill	$ 2	$ 2

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Acquisitions and Dispositions - Schedule of Pro Forma Consolidated Information (Details) - SOUTHERN Co GAS $ / shares in Units, $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($) $ / shares
Business Acquisition [Line Items]
Operating revenues | $	$ 16,609
Net income attributable to Southern Company | $	$ 2,394
Basic EPS (in dollars per share) | $ / shares	$ 2.52
Diluted EPS (in dollars per share) | $ / shares	$ 2.51

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Acquisitions and Dispositions - Schedule of Construction Projects (Details) - SOUTHERN POWER CO - MW		1 Months Ended		3 Months Ended
	Jan. 06, 2017	Apr. 30, 2017	Mar. 31, 2017	Jun. 30, 2019	Sep. 30, 2018	Sep. 30, 2017	Jul. 31, 2017
Bethel
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)	276
Southern Power Percentage Ownership	100.00%
PPA Contract Period	12 years
East Pecos
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)						120
PPA Contract Period			15 years
Lamesa
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)						102
PPA Contract Period		15 years
Cactus Flats
Business Acquisition [Line Items]
Southern Power Percentage Ownership							100.00%
Scenario, Forecast | Cactus Flats
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)					148
Scenario, Forecast | Mankato
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)				345
PPA Contract Period				20 years
Minimum | Scenario, Forecast | Cactus Flats
Business Acquisition [Line Items]
PPA Contract Period					12 years
Maximum | Scenario, Forecast | Cactus Flats
Business Acquisition [Line Items]
PPA Contract Period					15 years

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Joint Ownership Agreements - Balance Sheet Equity Method Investment Carrying Amount (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	$ 1,637	$ 1,549
SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	1,609	1,541
SNG | SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	1,385	1,394
Atlantic Coast Pipeline | SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	61	33
PennEast Pipeline | SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	49	22
Triton | SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	43	44
Pivotal JAX LNG, LLC | SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	40	16
Horizon Pipeline | SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	30	30
Other | SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	$ 1	$ 2

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Joint Ownership Agreements - Income Statement Equity Method Investment Carrying Amount (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments	$ 32	$ 29		$ 100	$ 28
SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments	32	29		100
SOUTHERN Co GAS | Predecessor
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments			$ 2
SOUTHERN Co GAS | SNG
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments	28	27		86
SOUTHERN Co GAS | SNG | Predecessor
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments			0
SOUTHERN Co GAS | Triton
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments		0		5
SOUTHERN Co GAS | Triton | Predecessor
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments			0
SOUTHERN Co GAS | PennEast Pipeline
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments	1	1		4
SOUTHERN Co GAS | PennEast Pipeline | Predecessor
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments			1
SOUTHERN Co GAS | Atlantic Coast Pipeline
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments	1	1		3
SOUTHERN Co GAS | Atlantic Coast Pipeline | Predecessor
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments			1
SOUTHERN Co GAS | Horizon Pipeline
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments	$ 1	$ 0		$ 2
SOUTHERN Co GAS | Horizon Pipeline | Predecessor
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments			$ 0

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Joint Ownership Agreements - Narrative (Details) - SNG - SOUTHERN Co GAS - USD ($) $ in Millions	Mar. 31, 2017	Sep. 30, 2016
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage		50.00%
Capital contributions from parent company	$ 50

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Joint Ownership Agreements - Investment in SNG (Details) - SNG - USD ($) $ in Millions	1 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2017	Sep. 30, 2017
Schedule of Equity Method Investments [Line Items]
Revenues	$ 82	$ 146	$ 445
Operating income	60	71	218
Net income	$ 55	$ 57	$ 172

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Segment and Related Information - Narrative (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017 USD ($) state segment	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($) state segment	Sep. 30, 2016 USD ($)
Segment Reporting Information [Line Items]
Number of states in which entity operates | state	4		4
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Number of states in which entity operates | state	7		7
Number of natural gas distribution utilities | segment	7		7
Number of reportable segments | segment			4
SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Wholesale revenues, affiliates | $	$ 105	$ 110	$ 295	$ 313

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Segment and Related Information - Financial Data for Business Segments (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Segment Reporting Information [Line Items]
Operating revenues	$ 6,201	$ 6,264		$ 17,403	$ 14,715
Segment net income	1,069	1,139		347	2,251
Total assets	110,315			110,315		$ 109,697
Kemper IGCC
Segment Reporting Information [Line Items]
Pre-tax charge to income	34	88		3,200	222
After tax charge to income	21	54		2,200	137
Plant Scherer Unit 3
Segment Reporting Information [Line Items]
After tax charge to income				20
Loss on Plant Scherer Unit 3				33
Eliminations
Segment Reporting Information [Line Items]
Operating revenues	(40)	(37)		(119)	(118)
Segment net income	2	(1)		0	(8)
Total assets	(1,532)			(1,532)		(1,624)
Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	5,523	5,619		14,239	13,979
Segment net income	1,132	1,198		276	2,401
Total assets	87,382			87,382		86,994
SOUTHERN Co GAS | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	565	543		2,841	543
Segment net income	15	4		303	4
Total assets	22,190			22,190		21,853
All Other | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	153	139		442	311
Segment net income	(80)	(62)		(232)	(146)
Total assets	2,275			2,275		2,474
SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Operating revenues	618	500		1,597	1,189
Segment net income	124	176		276	315
Total assets	14,648			14,648		15,169
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	565	543		2,841
Segment net income	15	4		303
Total assets	22,190			22,190		21,853
EBIT		4
SOUTHERN Co GAS | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	607	586		3,000
Segment net income	44			325
Total assets	24,052			24,052		24,875
EBIT		26
SOUTHERN Co GAS | Eliminations
Segment Reporting Information [Line Items]
Operating revenues	(44)	(45)		(166)
Segment net income	0			0
Total assets	(13,262)			(13,262)		(14,167)
EBIT		0
SOUTHERN Co GAS | All Other | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	2	2		7
Segment net income	(29)			(22)
Total assets	11,400			11,400		11,145
EBIT		(22)
SOUTHERN Co GAS | Gas distribution operations | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	472	455		2,255
Segment net income	52			223
Total assets	18,711			18,711		19,453
EBIT		27
SOUTHERN Co GAS | Gas marketing services | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	143	126		597
Segment net income	1			36
Total assets	2,089			2,089		2,084
EBIT		(4)
SOUTHERN Co GAS | Wholesale Gas Services | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	(24)	(8)		95
Segment net income	(23)			28
Total assets	893			893		1,127
EBIT		(11)
Less Gross Gas Costs	1,538	1,773		5,048
SOUTHERN Co GAS | Gas Midstream Operations | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	16	13		53
Segment net income	14			38
Total assets	2,359			2,359		2,211
EBIT		14
Predecessor | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues			$ 1,905
Segment net income			131
EBIT			328
Predecessor | SOUTHERN Co GAS | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues			2,003
EBIT			388
Predecessor | SOUTHERN Co GAS | Eliminations
Segment Reporting Information [Line Items]
Operating revenues			(102)
EBIT			0
Predecessor | SOUTHERN Co GAS | All Other | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues			4
EBIT			(60)
Predecessor | SOUTHERN Co GAS | Gas distribution operations | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues			1,575
EBIT			353
Predecessor | SOUTHERN Co GAS | Gas marketing services | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues			435
EBIT			109
Predecessor | SOUTHERN Co GAS | Wholesale Gas Services | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues			(32)
EBIT			(68)
Less Gross Gas Costs			2,675
Predecessor | SOUTHERN Co GAS | Gas Midstream Operations | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues			25
EBIT			(6)
Third Party Gross Revenues | SOUTHERN Co GAS | Wholesale Gas Services | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	1,411	1,688		4,781
Third Party Gross Revenues | Predecessor | SOUTHERN Co GAS | Wholesale Gas Services | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues			2,500
Intercompany Revenues | SOUTHERN Co GAS | Wholesale Gas Services | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	103	77		362
Intercompany Revenues | Predecessor | SOUTHERN Co GAS | Wholesale Gas Services | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues			143
Total Gross Revenues | SOUTHERN Co GAS | Wholesale Gas Services | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	1,514	1,765		5,143
Total Gross Revenues | Predecessor | SOUTHERN Co GAS | Wholesale Gas Services | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues			$ 2,643
Reportable Subsegments | Traditional Electric Operating Companies | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	5,017	5,236		12,960	13,120
Segment net income	1,008	1,022		0	2,086
Total assets	73,056			73,056		72,141
Reportable Subsegments | SOUTHERN POWER CO | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	618	500		1,597	1,189
Segment net income	124	176		276	315
Total assets	14,648			14,648		15,169
Intersubsegment Eliminations | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	(112)	(117)		(318)	(330)
Segment net income	0	$ 0		0	$ 0
Total assets	$ (322)			$ (322)		$ (316)

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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, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	$ 5,523	$ 5,619	$ 14,239	$ 13,979
Gas Revenue	565	543	2,841	543
Retail
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	4,615	4,808	11,786	11,932
Wholesale
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	718	613	1,867	1,455
Other
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	190	198	586	592
Gas distribution operations
Revenue from External Customer [Line Items]
Gas Revenue	430	420	2,119	420
Gas marketing services
Revenue from External Customer [Line Items]
Gas Revenue	143	126	597	126
Other
Revenue from External Customer [Line Items]
Gas Revenue	$ (8)	$ (3)	$ 125	$ (3)

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Label	Element	Value
Southern Company Gas [Member]
Proceeds from (Payments for) Other Financing Activities	us-gaap_ProceedsFromPaymentsForOtherFinancingActivities	$ (8,000,000)
Increase (Decrease) in Prepaid Taxes	us-gaap_IncreaseDecreaseInPrepaidTaxes	(1,000,000)
Payments to Acquire Equity Method Investments	us-gaap_PaymentsToAcquireEquityMethodInvestments	1,421,000,000
Deferred Income Tax Expense (Benefit)	us-gaap_DeferredIncomeTaxExpenseBenefit	(30,000,000)
Repayments of Senior Debt	us-gaap_RepaymentsOfSeniorDebt	300,000,000
Depreciation, Amortization and Accretion, Net	us-gaap_DepreciationAmortizationAndAccretionNet	116,000,000
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	us-gaap_PensionAndOtherPostretirementBenefitExpense	(123,000,000)
Increase (Decrease) in Accounts Payable	us-gaap_IncreaseDecreaseInAccountsPayable	78,000,000
Increase Decrease in Accrued Taxes	so_IncreaseDecreaseInAccruedTaxes	(11,000,000)
Stock or Unit Option Plan Expense	us-gaap_StockOptionPlanExpense	11,000,000
Interest Paid, Net	us-gaap_InterestPaidNet	86,000,000
Repayments of First Mortgage Bond	us-gaap_RepaymentsOfFirstMortgageBond	0
Increase (Decrease) in Other Operating Assets	us-gaap_IncreaseDecreaseInOtherOperatingAssets	36,000,000
Payments for (Proceeds from) Removal Costs	us-gaap_PaymentsForProceedsFromRemovalCosts	21,000,000
Proceeds from Issuance of First Mortgage Bond	us-gaap_ProceedsFromIssuanceOfFirstMortgageBond	0
Proceeds from Equity Method Investment, Distribution, Return of Capital	us-gaap_ProceedsFromEquityMethodInvestmentDividendsOrDistributionsReturnOfCapital	2,000,000
Cash and Cash Equivalents, Period Increase (Decrease)	us-gaap_CashAndCashEquivalentsPeriodIncreaseDecrease	33,000,000
Net Cash Provided by (Used in) Financing Activities	us-gaap_NetCashProvidedByUsedInFinancingActivities	2,090,000,000
Income Taxes Paid, Net	us-gaap_IncomeTaxesPaidNet	54,000,000
Increase (Decrease) in Receivables	us-gaap_IncreaseDecreaseInReceivables	18,000,000
Proceeds from Issuance of Senior Long-term Debt	us-gaap_ProceedsFromIssuanceOfSeniorLongTermDebt	900,000,000
Net Cash Provided by (Used in) Operating Activities	us-gaap_NetCashProvidedByUsedInOperatingActivities	(342,000,000)
Hedge Settlements	so_HedgeSettlements	35,000,000
Other Noncash Income (Expense)	us-gaap_OtherNoncashIncomeExpense	47,000,000
Increase (Decrease) in Energy Related Inventory, Natural Gas in Storage	so_IncreaseDecreaseinEnergyRelatedInventoryNaturalGasinStorage	222,000,000
Payments to Acquire Property, Plant, and Equipment	us-gaap_PaymentsToAcquirePropertyPlantAndEquipment	287,000,000
Change in Construction Payables	so_ChangeInConstructionPayables	9,000,000
Repayments of Long-term Debt	us-gaap_RepaymentsOfLongTermDebt	0
Payments to Noncontrolling Interests	us-gaap_PaymentsToMinorityShareholders	0
Increase (Decrease) in Other Operating Liabilities	us-gaap_IncreaseDecreaseInOtherOperatingLiabilities	(11,000,000)
Payments of Ordinary Dividends, Common Stock	us-gaap_PaymentsOfDividendsCommonStock	63,000,000
Proceeds from (Repayments of) Short-term Debt	us-gaap_ProceedsFromRepaymentsOfShortTermDebt	472,000,000
Increase (Decrease) in Accrued Salaries	us-gaap_IncreaseDecreaseInAccruedSalaries	(36,000,000)
Payments for (Proceeds from) Other Investing Activities	us-gaap_PaymentsForProceedsFromOtherInvestingActivities	(3,000,000)
Capital Expenditures Incurred but Not yet Paid	us-gaap_CapitalExpendituresIncurredButNotYetPaid	50,000,000
Net Cash Provided by (Used in) Investing Activities	us-gaap_NetCashProvidedByUsedInInvestingActivities	(1,715,000,000)
Southern Company Gas [Member] | Predecessor [Member]
Proceeds from (Payments for) Other Financing Activities	us-gaap_ProceedsFromPaymentsForOtherFinancingActivities	10,000,000
Increase (Decrease) in Prepaid Taxes	us-gaap_IncreaseDecreaseInPrepaidTaxes	(151,000,000)
Payments to Acquire Equity Method Investments	us-gaap_PaymentsToAcquireEquityMethodInvestments	14,000,000
Deferred Income Tax Expense (Benefit)	us-gaap_DeferredIncomeTaxExpenseBenefit	8,000,000
Repayments of Senior Debt	us-gaap_RepaymentsOfSeniorDebt	0
Depreciation, Amortization and Accretion, Net	us-gaap_DepreciationAmortizationAndAccretionNet	206,000,000
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	us-gaap_PensionAndOtherPostretirementBenefitExpense	5,000,000
Increase (Decrease) in Accounts Payable	us-gaap_IncreaseDecreaseInAccountsPayable	43,000,000
Increase Decrease in Accrued Taxes	so_IncreaseDecreaseInAccruedTaxes	41,000,000
Stock or Unit Option Plan Expense	us-gaap_StockOptionPlanExpense	20,000,000
Interest Paid, Net	us-gaap_InterestPaidNet	119,000,000
Repayments of First Mortgage Bond	us-gaap_RepaymentsOfFirstMortgageBond	125,000,000
Increase (Decrease) in Other Operating Assets	us-gaap_IncreaseDecreaseInOtherOperatingAssets	(37,000,000)
Payments for (Proceeds from) Removal Costs	us-gaap_PaymentsForProceedsFromRemovalCosts	32,000,000
Proceeds from Issuance of First Mortgage Bond	us-gaap_ProceedsFromIssuanceOfFirstMortgageBond	250,000,000
Proceeds from Equity Method Investment, Distribution, Return of Capital	us-gaap_ProceedsFromEquityMethodInvestmentDividendsOrDistributionsReturnOfCapital	3,000,000
Cash and Cash Equivalents, Period Increase (Decrease)	us-gaap_CashAndCashEquivalentsPeriodIncreaseDecrease	(4,000,000)
Net Cash Provided by (Used in) Financing Activities	us-gaap_NetCashProvidedByUsedInFinancingActivities	(558,000,000)
Income Taxes Paid, Net	us-gaap_IncomeTaxesPaidNet	(100,000,000)
Proceeds from Contributions from Parent	us-gaap_ProceedsFromContributionsFromParent	0
Increase (Decrease) in Receivables	us-gaap_IncreaseDecreaseInReceivables	(181,000,000)
Proceeds from Issuance of Senior Long-term Debt	us-gaap_ProceedsFromIssuanceOfSeniorLongTermDebt	350,000,000
Net Cash Provided by (Used in) Operating Activities	us-gaap_NetCashProvidedByUsedInOperatingActivities	1,113,000,000
Cash and Cash Equivalents, at Carrying Value	us-gaap_CashAndCashEquivalentsAtCarryingValue	15,000,000
Hedge Settlements	so_HedgeSettlements	26,000,000
Other Noncash Income (Expense)	us-gaap_OtherNoncashIncomeExpense	82,000,000
Increase (Decrease) in Energy Related Inventory, Natural Gas in Storage	so_IncreaseDecreaseinEnergyRelatedInventoryNaturalGasinStorage	(273,000,000)
Payments to Acquire Property, Plant, and Equipment	us-gaap_PaymentsToAcquirePropertyPlantAndEquipment	509,000,000
Change in Construction Payables	so_ChangeInConstructionPayables	(7,000,000)
Repayments of Long-term Debt	us-gaap_RepaymentsOfLongTermDebt	0
Payments to Noncontrolling Interests	us-gaap_PaymentsToMinorityShareholders	19,000,000
Increase (Decrease) in Other Operating Liabilities	us-gaap_IncreaseDecreaseInOtherOperatingLiabilities	(30,000,000)
Payments of Ordinary Dividends, Common Stock	us-gaap_PaymentsOfDividendsCommonStock	128,000,000
Proceeds from (Repayments of) Short-term Debt	us-gaap_ProceedsFromRepaymentsOfShortTermDebt	(896,000,000)
Increase (Decrease) in Accrued Salaries	us-gaap_IncreaseDecreaseInAccruedSalaries	(21,000,000)
Payments for (Proceeds from) Other Investing Activities	us-gaap_PaymentsForProceedsFromOtherInvestingActivities	0
Capital Expenditures Incurred but Not yet Paid	us-gaap_CapitalExpendituresIncurredButNotYetPaid	41,000,000
Net Cash Provided by (Used in) Investing Activities	us-gaap_NetCashProvidedByUsedInInvestingActivities	$ (559,000,000)