UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~March 31,~~September 30, 2017

¨ 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 18^th 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

Table of Contents

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 ~~March 31,~~September 30, 2017
The Southern Company	Par Value $5 Per Share	~~994,598,783~~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.

INDEX TO QUARTERLY REPORT ON FORM 10-Q

~~March 31,~~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	4657
	Condensed Statements of Comprehensive Income	4657
	Condensed Statements of Cash Flows	4758
	Condensed Balance Sheets	4859
	Management's Discussion and Analysis of Financial Condition and Results of Operations	5061
	Georgia Power Company
	Condensed Statements of Income	6175
	Condensed Statements of Comprehensive Income	6175
	Condensed Statements of Cash Flows	6276
	Condensed Balance Sheets	6377
	Management's Discussion and Analysis of Financial Condition and Results of Operations	6579
	Gulf Power Company
	Condensed Statements of Income	82101
	Condensed Statements of Comprehensive Income	82101
	Condensed Statements of Cash Flows	83102
	Condensed Balance Sheets	84103
	Management's Discussion and Analysis of Financial Condition and Results of Operations	86105
	Mississippi Power Company
	Condensed Statements of Income	99120
	Condensed Statements of Comprehensive Income	99120
	Condensed Statements of Cash Flows	~~100~~121
	Condensed Balance Sheets	~~101~~122
	Management's Discussion and Analysis of Financial Condition and Results of Operations	~~103~~124
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	~~130~~152
	Condensed Consolidated Statements of Comprehensive Income	~~130~~152
	Condensed Consolidated Statements of Cash Flows	~~131~~153
	Condensed Consolidated Balance Sheets	~~132~~154
	Management's Discussion and Analysis of Financial Condition and Results of Operations	~~134~~156

INDEX TO QUARTERLY REPORT ON FORM 10-Q

~~March 31,~~September 30, 2017



		Page Number
	PART I—FINANCIAL INFORMATION (CONTINUED)
	Southern Company Gas and Subsidiary Companies
	Condensed Consolidated Statements of Income	~~146~~171
	Condensed Consolidated Statements of Comprehensive Income	~~146~~172
	Condensed Consolidated Statements of Cash Flows	~~147~~173
	Condensed Consolidated Balance Sheets	~~148~~174
	Management's Discussion and Analysis of Financial Condition and Results of Operations	~~150~~176
	Notes to the Condensed Financial Statements	~~169~~206
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	4455
Item 4.	Controls and Procedures	4455

	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	~~229~~279
Item 1A.	Risk Factors	~~229~~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	~~231~~ Inapplicable
Item 6.	Exhibits	~~231~~282
	Signatures	~~236~~286

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 ~~its affiliate, WECTEC Global Project Services Inc. (formerly~~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 ~~CB&I Stone & Webster, Inc.), formerly a subsidiary of The Shaw Group Inc. and Chicago Bridge & Iron Company N.V.~~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

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
~~Internal Revenue Code~~IRC	Internal Revenue Code of 1986, as amended
IRS	Internal Revenue Service
ITC	Investment tax credit
Kemper IGCC	Mississippi Power's IGCC ~~facility under construction by Mississippi Power~~project in Kemper County, Mississippi

~~DEFINITIONS~~

~~(continued)~~



~~Term~~	~~Meaning~~

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
~~Nicor Gas Credit Facility~~	~~$700 million credit facility entered into by Nicor Gas to support its commercial paper program~~
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

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

~~DEFINITIONS~~

~~(continued)~~



~~Term~~	~~Meaning~~

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
~~SMEPA~~	~~South Mississippi Electric Power Association (now known as Cooperative Energy)~~
SNG	Southern Natural Gas Company, L.L.C.
Southern Company	The Southern Company
Southern Company Gas	Southern Company Gas and its subsidiaries
Southern Company Gas Capital	Southern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas
~~Southern Company Gas Credit Facility~~	~~$1.3 billion credit agreement entered into by Southern Company Gas Capital to support its commercial paper program~~
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

~~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, 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, sustaining nitrogen supply, 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 results of the Contractor's bankruptcy filing and 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, as well as the engineering, procurement, and construction agreement for Plant Vogtle Units 3 and 4 and Georgia Power's DOE loan guarantees;

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;~~

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:

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;

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;

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;

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)

actions related to cost recovery for the Kemper IGCC, including ~~the ultimate impact of the 2015 decision of the Mississippi Supreme Court and related legal or regulatory proceedings,~~ongoing settlement discussions, Mississippi PSC review of the prudence of Kemper IGCC costs and approval of further permanent rate recovery plans, ~~actions relating to proposed securitization, satisfaction of requirements to utilize grants,~~ and ~~the ultimate impact of the termination of the proposed sale of an interest in the Kemper IGCC to SMEPA;~~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.

THE SOUTHERN COMPANY

AND SUBSIDIARY COMPANIES

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months Ended March 31,						For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016			2017			2016
	(in millions)						(in millions)						(in millions)
Operating Revenues:
Retail electric revenues	$	3,394		$	3,377		$	4,615		$	4,808		$	11,786		$	11,932
Wholesale electric revenues	531			396			718			613			1,867			1,455
Other electric revenues	175			181			168			181			510			529
Natural gas revenues	1,530			—			532			518			2,746			518
Other revenues	141			38			168			144			494			281
Total operating revenues	5,771			3,992			6,201			6,264			17,403			14,715
Operating Expenses:
Fuel	996			911			1,285			1,400			3,372			3,334
Purchased power	179			165			256			227			646			581
Cost of natural gas	719			—			134			133			1,085			133
Cost of other sales	88			19			90			84			293			161
Other operations and maintenance	1,329			1,107			1,287			1,411			3,918			3,616
Depreciation and amortization	716			541			767			695			2,236			1,805
Taxes other than income taxes	330			256			303			309			941			821
Estimated loss on Kemper IGCC	108			53			34			88			3,155			222
Total operating expenses	4,465			3,052			4,156			4,347			15,646			10,673
Operating Income	1,306			940			2,045			1,917			1,757			4,042
Other Income and (Expense):
Allowance for equity funds used during construction	57			53			18			52			133			150
Earnings from equity method investments	39			—			32			29			100			28
Interest expense, net of amounts capitalized	(416		)	(246		)	(407		)	(374		)	(1,248		)	(913		)
Other income (expense), net	(6		)	(29		)	11			(8		)	2			(66		)
Total other income and (expense)	(326		)	(222		)	(346		)	(301		)	(1,013		)	(801		)
Earnings Before Income Taxes	980			718			1,699			1,616			744			3,241
Income taxes	315			217			590			439			317			917
Consolidated Net Income	665			501			1,109			1,177			427			2,324
Less:
Dividends on preferred and preference stock of subsidiaries	11			11			10			11			32			34
Net income (loss) attributable to noncontrolling interests	(4		)	1
Net income attributable to noncontrolling interests							30			27			48			39
Consolidated Net Income Attributable to Southern Company	$	658		$	489		$	1,069		$	1,139		$	347		$	2,251
Common Stock Data:
Earnings per share (EPS) —
Basic EPS	$	0.66		$	0.53
Diluted EPS	$	0.66		$	0.53
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	993			916			1,003			968			998			940
Diluted	1,000			922			1,010			975			1,005			945
Cash dividends paid per share of common stock	$	0.5600		$	0.5425		$	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.

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months Ended March 31,						For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2017			2016			2017			2016		2017			2016
	(in millions)						(in millions)					(in millions)
Consolidated Net Income	$	665		$	501		$	1,109		$	1,177	$	427		$	2,324
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(5) and $(72), respectively	(9		)	(117		)
Reclassification adjustment for amounts included in net income, net of tax of $(1) and $1, respectively	(1		)	2
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $- and $1, respectively	1			1
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		)	(114		)	9			22		(2		)	(95		)
Comprehensive Income							1,118			1,199		425			2,229
Less:
Dividends on preferred and preference stock of subsidiaries	11			11			10			11		32			34
Comprehensive income (loss) attributable to noncontrolling interests	(4		)	1
Comprehensive income attributable to noncontrolling interests							30			27		48			39
Consolidated Comprehensive Income Attributable to Southern Company	$	649		$	375		$	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.

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Three Months Ended March 31,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Operating Activities:
Consolidated net income	$	665		$	501		$	427		$	2,324
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	823			639			2,564			2,109
Deferred income taxes	161			(4		)	15			(22		)
Allowance for equity funds used during construction	(57		)	(53		)	(133		)	(150		)
Stock based compensation expense	61			58
Pension, postretirement, and other employee benefits							(64		)	(158		)
Settlement of asset retirement obligations							(137		)	(117		)
Hedge settlements							—			(236		)
Estimated loss on Kemper IGCC	108			53			3,148			222
Mark-to-market adjustments	(81		)	(2		)
Other, net	(11		)	(6		)	(8		)	(1		)
Changes in certain current assets and liabilities —
-Receivables	312			235			426			(458		)
-Prepayments	(111		)	(65		)
-Fossil fuel for generation							59			204
-Natural gas for sale, net of temporary LIFO liquidation	411			—			—			(222		)
-Other current assets	(31		)	(7		)	(164		)	(112		)
-Accounts payable	(533		)	(72		)	(467		)	(9		)
-Accrued taxes	(212		)	(57		)	157			1,062
-Accrued compensation	(438		)	(332		)	(230		)	(122		)
-Retail fuel cost over recovery	(122		)	25			(211		)	(106		)
-Other current liabilities	(48		)	(35		)	(129		)	88
Net cash provided from operating activities	897			878			5,253			4,296
Investing Activities:
Business acquisitions, net of cash acquired	(1,020		)	(114		)	(1,032		)	(9,513		)
Property additions	(1,488		)	(1,872		)	(5,242		)	(5,252		)
Investment in restricted cash	(13		)	(289		)	(16		)	(750		)
Distribution of restricted cash	26			292			33			746
Nuclear decommissioning trust fund purchases	(224		)	(316		)	(585		)	(838		)
Nuclear decommissioning trust fund sales	218			311			580			832
Cost of removal, net of salvage	(61		)	(52		)	(208		)	(155		)
Change in construction payables, net	(170		)	(94		)	120			(259		)
Investment in unconsolidated subsidiaries	(81		)	—			(134		)	(1,421		)
Payments pursuant to LTSAs	(55		)	(49		)	(189		)	(125		)
Other investing activities	65			(14		)	(14		)	95
Net cash used for investing activities	(2,803		)	(2,197		)	(6,687		)	(16,640		)
Financing Activities:
Increase in notes payable, net	573			294
Increase (decrease) in notes payable, net							(515		)	655
Proceeds —
Long-term debt	1,409			1,997			4,068			14,091
Common stock	186			270			613			3,265
Preferred stock							250			—
Short-term borrowings	4			—			1,263			—
Redemptions and repurchases —
Long-term debt	(608		)	(888		)	(1,981		)	(2,405		)
Preferred and preference stock							(150		)	—
Short-term borrowings	—			(475		)	(409		)	(475		)
Distributions to noncontrolling interests	(18		)	(4		)	(89		)	(22		)
Capital contributions from noncontrolling interests	71			131			79			367
Purchase of membership interests from noncontrolling interests	—			(129		)	—			(129		)
Payment of common stock dividends	(556		)	(497		)	(1,716		)	(1,553		)
Other financing activities	(36		)	(30		)	(113		)	(185		)
Net cash provided from financing activities	1,025			669			1,300			13,609
Net Change in Cash and Cash Equivalents	(881		)	(650		)	(134		)	1,265
Cash and Cash Equivalents at Beginning of Period	1,975			1,404			1,975			1,404
Cash and Cash Equivalents at End of Period	$	1,094		$	754		$	1,841		$	2,669
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $25 and $30 capitalized for 2017 and 2016, respectively)	$	461		$	224
Interest (net of $72 and $94 capitalized for 2017 and 2016, respectively)							$	1,286		$	766
Income taxes, net	(6		)	(141		)	(187		)	(151		)
Noncash transactions — Accrued property additions at end of period	578			731			805			578

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

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


Assets	At March 31, 2017			At December 31, 2016			At September 30, 2017			At December 31, 2016
	(in millions)						(in millions)
Current Assets:
Cash and cash equivalents	$	1,094		$	1,975		$	1,841		$	1,975
Receivables —
Customer accounts receivable	1,560			1,565			1,744			1,583
Energy marketing receivable	493			623
Energy marketing receivables							427			623
Unbilled revenues	589			706			595			706
Under recovered regulatory clause revenues	47			18
Under recovered fuel clause revenues							62			—
Income taxes receivable, current	544			544			138			544
Other accounts and notes receivable	433			377			578			377
Accumulated provision for uncollectible accounts	(53		)	(43		)	(43		)	(43		)
Materials and supplies	1,477			1,462			1,499			1,462
Fossil fuel for generation	687			689			571			689
Natural gas for sale	346			631			631			631
Prepaid expenses	401			364			365			364
Other regulatory assets, current	560			581			585			581
Other current assets	249			230			209			230
Total current assets	8,427			9,722			9,202			9,722
Property, Plant, and Equipment:
In service	99,774			98,416			102,014			98,416
Less: Accumulated depreciation	30,330			29,852			31,164			29,852
Plant in service, net of depreciation	69,444			68,564			70,850			68,564
Nuclear fuel, at amortized cost	902			905			865			905
Construction work in progress	9,465			8,977			8,026			8,977
Total property, plant, and equipment	79,811			78,446			79,741			78,446
Other Property and Investments:
Goodwill	6,251			6,251			6,267			6,251
Equity investments in unconsolidated subsidiaries	1,615			1,549			1,637			1,549
Other intangible assets, net of amortization of $97 and $62 at March 31, 2017 and December 31, 2016, respectively	935			970
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	1,678			1,606			1,783			1,606
Leveraged leases	780			774			788			774
Miscellaneous property and investments	293			270			236			270
Total other property and investments	11,552			11,420			11,613			11,420
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,647			1,629			1,318			1,629
Unamortized loss on reacquired debt	218			223			210			223
Other regulatory assets, deferred	6,748			6,851			6,718			6,851
Other deferred charges and assets	1,357			1,406			1,513			1,406
Total deferred charges and other assets	9,970			10,109			9,759			10,109
Total Assets	$	109,760		$	109,697		$	110,315		$	109,697

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

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


Liabilities and Stockholders' Equity	At March 31, 2017			At December 31, 2016			At September 30, 2017			At December 31, 2016
	(in millions)						(in millions)
Current Liabilities:
Securities due within one year	$	3,269		$	2,587		$	3,505		$	2,587
Notes payable	2,818			2,241			2,579			2,241
Energy marketing trade payables	471			597			451			597
Accounts payable	1,750			2,228			2,353			2,228
Customer deposits	541			558			550			558
Accrued taxes —
Accrued income taxes	258			193			176			193
Unrecognized tax benefits	400			385			17			385
Other accrued taxes	326			667			690			667
Accrued interest	453			518			443			518
Accrued compensation	461			915			703			915
Asset retirement obligations, current	386			378			245			378
Liabilities from risk management activities, net of collateral	63			107
Acquisitions payable	—			489			—			489
Other regulatory liabilities, current	221			236			139			236
Other current liabilities	867			818			752			925
Total current liabilities	12,284			12,917			12,603			12,917
Long-term Debt	42,786			42,629			44,042			42,629
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	14,307			14,092			14,321			14,092
Deferred credits related to income taxes	215			219
Accumulated deferred investment tax credits	2,264			2,228
Accumulated deferred ITCs							2,290			2,228
Employee benefit obligations	2,234			2,299			2,139			2,299
Asset retirement obligations, deferred	4,170			4,136			4,356			4,136
Accrued environmental remediation	388			397
Other cost of removal obligations	2,724			2,748			2,708			2,748
Other regulatory liabilities, deferred	237			258			449			476
Other deferred credits and liabilities	873			880			1,048			1,278
Total deferred credits and other liabilities	27,412			27,257			27,311			27,257
Total Liabilities	82,482			82,803			83,956			82,803
Redeemable Preferred Stock of Subsidiaries	118			118			361			118
Redeemable Noncontrolling Interests	164			164			59			164
Stockholders' Equity:
Common Stockholders' Equity:
Common stock, par value $5 per share —
Authorized — 1.5 billion shares
Issued — March 31, 2017: 995 million shares
Issued — September 30, 2017: 1.0 billion shares
— December 31, 2016: 991 million shares
Treasury — March 31, 2017: 0.9 million shares
Treasury — September 30, 2017: 0.9 million shares
— December 31, 2016: 0.8 million shares
Par value	4,973			4,952			5,018			4,952
Paid-in capital	9,884			9,661			10,300			9,661
Treasury, at cost	(33		)	(31		)	(35		)	(31		)
Retained earnings	10,459			10,356			8,981			10,356
Accumulated other comprehensive loss	(189		)	(180		)	(182		)	(180		)
Total Common Stockholders' Equity	25,094			24,758			24,082			24,758
Preferred and Preference Stock of Subsidiaries	609			609			462			609
Noncontrolling Interests	1,293			1,245			1,395			1,245
Total Stockholders' Equity	26,996			26,612			25,939			26,612
Total Liabilities and Stockholders' Equity	$	109,760		$	109,697		$	110,315		$	109,697

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

Table of Contents

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~FIRST~~THIRD QUARTER 2017 vs. ~~FIRST~~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 of 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 ~~business~~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 ~~March 29,~~June 21, 2017, ~~Westinghouse~~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 ~~WECTEC each filed~~address all issues associated with the Kemper IGCC (Kemper Settlement Order). The Kemper Settlement Order established a new docket for ~~bankruptcy protection under Chapter 11~~the purposes of pursuing a global settlement of costs of the ~~U.S. Bankruptcy Code. Also~~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 ~~March 29, 2017, Georgia Power, acting for itself~~residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and ~~as agent~~related assets; and (iii) modification or amendment of the CPCN for the ~~Vogtle Owners, entered into an interim assessment agreement with~~Kemper IGCC to allow only for ownership and operation of a natural gas facility.

On June 28, 2017, Mississippi Power notified the ~~Contractor~~Mississippi PSC that it would begin a process to suspend operations and ~~WECTEC Staffing Services LLC (WECTEC Staffing) to provide for a continuation~~start-up activities on the gasifier portion of ~~work with respect to Plant Vogtle Units 3 and 4. In February 2017,~~ the Contractor provided Georgia Power with revised forecasted in-service dates of December 2019 and September 2020 for Plant Vogtle Units 3 and 4, respectively. However, based on information subsequently made available during Westinghouse and WECTEC's bankruptcy proceedings and pursuantKemper IGCC, given the uncertainty as to the interim assessment agreement, Georgia Power and the Vogtle Owners do not believe the revised in-service dates are achievable. Georgia Power, along with the other Vogtle Owners, is undertaking a comprehensive schedule and cost-to-complete assessment, as well as a cancellation cost assessment. It is reasonably possible these assessments result in estimated incremental costs to complete, including owners' costs, that materially exceed the value of the Toshiba Guarantee. Georgia Power intends to work with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4. Georgia Power, for itself and as agent for the other Vogtle Owners, is also negotiating a new service agreement which would, if necessary, engage the Contractor to provide design, engineering, and procurement services to Southern Nuclear, in the event Southern Nuclear assumes control over construction management. The Contractor's bankruptcy filing 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

Table of Contents

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Southern Company's financial statements.~~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).

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.

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.

Table of Contents

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 ~~Toshiba~~ 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 ~~also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and~~ 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.

Table of Contents

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Net Income

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$169 34.6

Consolidated net income attributable to Southern Company was ~~$658 million~~$1.07 billion ($~~0.66~~1.07 per share) for the ~~first~~third quarter 2017 compared to ~~$489 million~~$1.14 billion ($~~0.53~~1.18 per share) for the corresponding period in 2016. ~~Consolidated net income increased~~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 $239 million as a result of earnings from Southern Company Gas, which was acquired on July 1, 2016, and decreased $12 million as a result of a loss at PowerSecure, which was acquired on May 9, 2016. Also contributing to the increase were higher retail electric revenues resulting from increases in ~~non-fuel retail~~ 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 ~~and income tax benefits~~ at Southern Power, ~~and a decrease in non-fuel operations and maintenance expenses. These increases were~~ partially offset by a decrease in retail electric revenues ~~resulting from~~due to milder weather and lower customer usage, higher interest expense, ~~higher~~and an increase in depreciation and amortization, and higher charges related to revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC in the first quarter 2017 compared to the corresponding period in 2016.amortization.

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

Retail Electric Revenues

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$17 0.5

In the ~~first~~third quarter 2017, retail electric revenues were ~~$3.39~~$4.6 billioncompared to ~~$3.38~~$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:


	First Quarter 2017					Third Quarter 2017					Year-to-Date 2017
	(in millions)			(% change)		(in millions)			(% change)		(in millions)			(% change)
Retail electric – prior year	$	3,377				$	4,808				$	11,932
Estimated change resulting from –
Rates and pricing	118			3.5		138			2.9		338			2.8
Sales decline	(11		)	(0.3	)	(52		)	(1.1	)	(74		)	(0.6	)
Weather	(137		)	(4.1	)	(162		)	(3.4	)	(351		)	(2.9	)
Fuel and other cost recovery	47			1.4		(117		)	(2.4	)	(59		)	(0.5	)
Retail electric – current year	$	3,394		0.5	%	$	4,615		(4.0	)%	$	11,786		(1.2	)%

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~~rate pricing effect~~January 1, 2017, the recovery of ~~decreased customer usage~~Plant Vogtle Units 3 and ~~higher contributions from commercial and industrial customers~~4 construction financing costs under ~~a rate plan allowing for variable demand-driven pricing~~the NCCR tariff at Georgia Power, and an ~~ECO Plan rate~~ increase in retail base revenues effective July 2017 and in environmental cost recovery effective November 2016 at ~~Mississippi Power implemented in the third quarter 2016.~~Gulf Power.

See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama ~~Power" and~~Power," " – Georgia Power – Rate ~~Plans"~~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 ~~first~~third quarter and year-to-date 2017 ~~when~~when compared to the corresponding ~~period~~periods in 2016. ~~Industrial~~Weather-adjusted residential KWH sales decreased ~~2.2%~~2.0% and 0.6% in the ~~first~~third quarter and year-to-date 2017, primarily in the chemicals, stone, clay, and glass, and paper sectors. A strong dollar, low oil prices, weak global economic conditions, and economic policy uncertainty have constrained sales in the industrial sector. Weather-adjusted commercial KWH sales decreased 1.9% in the~~first quarter 2017~~respectively, primarily due to decreased customer usage resulting from an increase in ~~electronic commerce transactions and~~penetration of energy ~~saving initiatives,~~efficient residential appliances, partially offset by customer growth. Weather-adjusted ~~residential~~commercial KWH sales ~~increased 0.8%~~decreased 1.4% and 1.1% in the ~~first~~third quarter and year-to-date 2017, respectively, primarily due to decreased customer ~~growth,~~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 ~~primarily resulting from efficiency improvements in residential appliances and lighting.~~for all customer classes.

Fuel and other cost recovery revenues ~~increased $47~~decreased $117 million and $59 million in the ~~first~~third quarter and year-to-date 2017, respectively, when compared to the corresponding ~~period~~periods in 2016 primarily due to ~~an increase in fuel~~lower energy sales resulting from milder weather and lower coal prices. Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.

Wholesale Electric Revenues

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$135 34.1

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. ~~Electricity~~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 ~~for electricity.~~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.

In the first quarter 2017, wholesale electric revenues were $531 million compared to $396 million for the corresponding period in 2016. This increase was primarily related to a $118 million increase in energy revenues and a $17 million increase in capacity revenues. The increase in energy revenues primarily related to Southern Power increases in renewable energy sales arising from new solar and wind facilities, sales from new natural gas PPAs, and

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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 ~~increase~~increases in capacity revenues ~~was~~ primarily ~~due to~~resulted from PPAs related to new natural gas facilities and additional customer ~~load~~capacity requirements at Southern Power.

Other Electric Revenues

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

N/M - Not meaningful

Natural gas revenues represent sales from the natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. ~~Following~~In the ~~Merger, $1.5 billion of~~third quarter 2017, natural gas revenues ~~are included in the consolidated statements of income~~were $532 million compared to $518 million for the ~~first quarter 2017.~~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



~~First Quarter 2017 vs. First Quarter 2016~~
~~(change in millions)~~		~~(% change)~~
~~$103~~		~~N/M~~

~~N/M - Not meaningful~~

In the ~~first~~third quarter 2017, other revenues were ~~$141~~$168 million compared to ~~$38~~$144 million for the corresponding period in 2016. ~~The increase was~~For year-to-date 2017, other revenues were $494 million compared to $281 million for the corresponding

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period in 2016. These increases were primarily due to ~~$70~~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 ~~$30~~$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


	First Quarter 2017 vs. First Quarter 2016			Third Quarter 2017 vs. Third Quarter 2016				Year-to-Date 2017 vs. Year-to-Date 2016
	(change in millions)		(% change)	(change in millions)			(% change)	(change in millions)		(% change)
Fuel	$	85	9.3	$	(115	)	(8.2)	$	38	1.1
Purchased power	14		8.5	29			12.8	65		11.2
Total fuel and purchased power expenses	$	99		$	(86	)		$	103

In the ~~first~~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 ~~$1.2~~$4.0 billion compared to ~~$1.1~~$3.9 billion for the corresponding period in 2016. The increase was primarily the result of a ~~$121~~$277 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset by a ~~$22~~$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.

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


	First Quarter 2017	First Quarter 2016	Third Quarter 2017	Third Quarter 2016	Year-to-Date 2017	Year-to-Date 2016
Total generation (in billions of KWHs)	44	44	54	56	147	145
Total purchased power (in billions of KWHs)	4	4	6	6	14	15
Sources of generation (percent) —
Coal	29	27	31	38	30	33
Nuclear	17	17	15	15	16	16
Gas	46	47	47	44	46	46
Hydro	2	7	2	1	2	3
Other	6	2	5	2	6	2
Cost of fuel, generated (in cents per net KWH) —
Coal	2.88	3.24	2.82	2.97	2.82	3.10
Nuclear	0.79	0.82	0.80	0.81	0.80	0.82
Gas	2.92	2.16	2.92	2.74	2.93	2.40
Average cost of fuel, generated (in cents per net KWH)	2.50	2.23	2.54	2.54	2.51	2.38
Average cost of purchased power (in cents per net KWH)^(*)	6.11	5.27	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 ~~first~~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 ~~$996~~$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 ~~$911~~$227 million for the corresponding period in 2016. The increase was primarily due to a ~~35.2% increase in the average cost of natural gas per KWH generated and a 5.5%~~10.1% increase in the volume of KWHs ~~generated by coal,~~purchased, partially offset by ~~an 11.1%~~a 0.4% decrease in the average cost ~~of coal~~ per KWH ~~generated and an 8.4% decrease in the volume of KWHs generated by natural gas.~~purchased.

~~Purchased Power~~

~~In the first quarter~~For year-to-date 2017, purchased power expense was ~~$179~~$646 million compared to ~~$165~~$581 million for the corresponding period in 2016. The increase was primarily due to a ~~15.9%~~12.0% increase in the average cost per KWH purchased, primarily as a result of higher natural gas prices, partially offset by a ~~3.6%~~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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Cost of Natural Gas

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. ~~Following~~In the ~~Merger, $719 million~~third quarter 2017, cost of natural gas ~~costs were included in the consolidated statements of income~~was $134 million compared to $133 million for the ~~first quarter 2017.~~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.

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~~SOUTHERN COMPANY AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

Cost of Other Sales



~~First Quarter 2017 vs. First Quarter 2016~~
~~(change in millions)~~		~~(% change)~~
~~$69~~		~~N/M~~

~~N/M - Not meaningful~~

In the ~~first~~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 ~~were $88~~was $293 million compared to ~~$19~~$161 million for the corresponding period in 2016. The year-to-date increase ~~was~~ primarily ~~due to~~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 – ~~Acquisition of PowerSecure~~" herein for additional information.

Other Operations and Maintenance Expenses

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$222 20.1

In the ~~first~~third quarter 2017, other operations and maintenance expenses were $1.3 billion compared to ~~$1.1~~$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 ~~$253~~increases of $420 million and $32 million in operations and maintenance expenses atas a result of the inclusion of Southern Company Gas ~~following~~and PowerSecure results for the ~~Merger,~~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 ~~$21~~modernization activities implemented at Georgia Power in the third quarter 2016 that contributed to decreases of $79 million in ~~operations~~maintenance costs and ~~maintenance expenses at PowerSecure, which was acquired on May 9, 2016, partially offset by a decrease of $38~~$34 million in ~~scheduled outage~~other employee compensation and ~~maintenance~~benefits. Other factors

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

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$175 32.3

In the ~~first~~third quarter 2017, depreciation and amortization was ~~$716~~$767 million compared to ~~$541~~$695 million for the corresponding period in 2016. ~~Following~~The increase is primarily related to additional plant in service at the ~~Merger, $120 million in~~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 ~~is included in the consolidated statements of income~~ for the ~~first quarter 2017.~~nine-month period in 2017 compared to the three-month period subsequent to the Merger closing on July 1, 2016. Additionally, the increase reflects ~~$60~~$170 million related to additional plant in service at the traditional electric operating companies and Southern ~~Power,~~Power. The increase was partially offset by ~~$20~~a $34 million ~~more of a reduction~~increase in the reductions in depreciation ~~in the first quarter 2017 compared to the corresponding period in 2016 at Gulf Power, as~~ authorized in ~~its~~Gulf Power's 2013 rate case settlement approved by the Florida ~~PSC.~~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 ~~Note~~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. ~~Also, see~~

Taxes Other Than Income Taxes

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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~~Taxes Other Than Income Taxes~~

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$74 28.9

In the first quarter 2017, taxes other than income taxes were $330 million compared to $256 million for the corresponding period in 2016. The increase primarily related to $70 million in taxes other than income taxes associated with Southern Company Gas following the Merger.

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

Estimated Loss on Kemper IGCC



~~First Quarter 2017 vs. First Quarter 2016~~
~~(change in millions)~~		~~(% change)~~
~~$55~~		~~N/M~~

N/M - Not meaningful

~~In the first quarter 2017 and 2016, estimated~~Estimated probable losses on the Kemper IGCC of ~~$108~~$34 million and ~~$53 million, respectively,~~$3.2 billion were recorded at ~~Southern Company. These~~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 ~~reflect~~for revisions of estimated costs expected to be incurred on ~~Mississippi Power's~~ 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 ~~(which exists when Mississippi Power demonstrates that the purpose and effect of the construction~~(construction cost increase isdemonstrated to produce efficiencies that ~~will~~ 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

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.

Earnings from Equity Method Investments



~~First Quarter 2017 vs. First Quarter 2016~~
~~(change in millions)~~		~~(% change)~~
~~$39~~		~~N/M~~

N/M - Not meaningful

In the ~~first~~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 ~~$39~~$100 million ~~primarily related to earnings from Southern Company Gas' equity method investment in SNG effective September 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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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

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$170 69.1

In the ~~first~~third quarter 2017, interest expense, net of amounts capitalized was ~~$416~~$407 million compared to ~~$246~~$374 million in the corresponding period in 2016. The increase was primarily due to an increase in average outstanding long-term debt ~~primarily~~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 ~~financing~~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 ~~Merger and the funding of Southern Power's growth strategy and continuous construction program.~~IRS related to R&E deductions. In addition, ~~following~~year-to-date 2017 includes an additional $106 million reflecting the ~~Merger, $46 million in~~nine-month period of interest expense offor Southern Company Gas ~~is included in~~compared to the ~~consolidated statements of income for~~three-month period subsequent to the ~~first quarter 2017.~~Merger closing on July 1, 2016.

See ~~Note~~FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Section 174 Research and Experimental Deduction" and Notes (E) and (G) to the Condensed Financial Statements herein ~~and Note (I) to the Condensed Financial Statements under "Southern Company~~ – ~~Merger with Southern Company Gas" herein~~ for additional information.

Other Income (Expense), Net

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$23 79.3

N/M - Not meaningful

In the ~~first~~third quarter 2017, other income (expense), net was ~~$(6)~~$11 million compared to ~~$(29)~~$(8) million for the corresponding period in 2016. ~~The change~~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 ~~parent company~~$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. ~~The change~~These changes also ~~includes a~~include increases of $36 million and $152 million in currency ~~loss of $17 million at Southern Power~~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 ~~a gain of $17 million~~an equal change in gains on the ~~related~~ foreign currency ~~hedge~~hedges that ~~was~~were reclassified from accumulated OCI into ~~earnings.~~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

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$98 45.2

In the ~~first~~third quarter 2017, income taxes were ~~$315~~$590 million compared to ~~$217~~$439 million for the corresponding period in 2016. The increase was primarily due to ~~$150~~a $61 million ~~in taxes at Southern Company Gas following the Merger and a $12 million increase related to a~~ decrease in income tax benefits from solar ITCs at Southern Power, ~~partially offset by increases~~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 ~~of $30 million from wind PTCs at Southern Power, $21 million~~ related to ~~the~~ estimated ~~probable~~ losses on ~~construction of~~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 $9a $44 million net decrease in tax benefits from ~~state apportionment rate changes~~renewable tax credits at Southern Power.

See ~~Note~~Notes (B), (G) ~~to the Condensed Financial Statements herein~~, and ~~Note~~ (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. ~~The completion of construction and resolution of cost recovery relating~~Matters related to ~~the Kemper IGCC and the~~

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~~SOUTHERN COMPANY AND SUBSIDIARY COMPANIES~~

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~impact of the Contractor's bankruptcy on the construction cost and schedule of, as well as the cost recovery for,~~ 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 ~~other~~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 ~~economic growth. The~~the pace of economic growth ~~and electricity and natural gasdemand~~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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~~statements~~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 ~~under "Environmental Matters"~~ in Item 87 of the Form 10-K for additional ~~information.~~information regarding the EPA's eight-hour ozone National Ambient Air Quality Standard (NAAQS).

~~Environmental Statutes~~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 ~~Regulations~~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 and~~programs.

On April 25, 2017, the ~~final~~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 ~~March 1,~~June 27, 2017, the EPA and the U.S. Army Corps of Engineers ~~released a notice of intent~~proposed to ~~review and~~ rescind ~~or further revise~~ 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.

On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. As part of its planned reconsideration, the EPA also announced it is administratively staying the compliance deadlines under the rule and will conduct additional rulemaking to that effect.

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

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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.

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OfOn May 16, 2017, the ~~three Mississippi Power~~Georgia PSC approved Georgia Power's request to build, own, and operate a 139-MW solar ~~projects~~generation facility at a U.S. Air Force base that is expected to be ~~in service in 2017, one was~~ placed in service inby the ~~first quarter~~end of 2019.

During the nine months ended September 30, 2017, ~~while the remaining two are~~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 ~~July~~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 ~~incurred through March 31, 2017~~ 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 million annually 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 ~~of the~~ intervenors ~~to Gulf Power's retail base rate case,~~ with respect to Gulf Power's request to increase retail base rates. ~~Under~~Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power ~~will, among other things, increase~~increased rates effective with the first billing cycle in July 1, 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact ~~consists~~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, which is estimated to be approximately $7.7 million for 2017.~~clause. In addition, Gulf Power ~~also will (1) continue~~continued its ~~current~~ authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%)~~; (2) be~~ and is deemed to have an equity ratio of

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52.5% for all retail regulatory ~~purposes; (3)~~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;~~2018 and ~~(4)~~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. ~~Accordingly, changes~~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 ana ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase ~~within the 11-month statutory time limit,~~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.

The two largest construction projects currently underway in the Southern Company system are Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs) and Mississippi Power's 582-MW Kemper IGCC. SeeFor 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 " – ~~Nuclear Construction~~Southern Company Gas–Regulatory Infrastructure Programs" and "Integrated Coal Gasification Combined Cycle" ~~herein for additional information. For additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy facilities,~~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. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "~~Regulatory Matters~~–~~Southern Company Gas~~–

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~~Regulatory Infrastructure Programs" herein for information regarding infrastructure improvement programs at the natural gas distribution utilities.~~

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

~~Mississippi Power continues to progress toward completing the construction and start-up of the~~The Kemper IGCC ~~which~~ 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 current cost estimate for the Kemper IGCC in total is approximately $7.16 billion, which includes approximately $5.75 billion of costs subject to the construction cost cap and is net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts to customers. Mississippi Power does not intend to seek any rate recovery for any related costs that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Southern Company recorded pre-tax charges to income for revisions to the cost estimate subject to the construction cost cap totaling $108 million ($67 million after tax) in the first quarter 2017. Since 2013, in the aggregate, Southern Company has incurred charges of $2.87 billion ($1.77 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2017. The current cost estimate includes costs through May 31, 2017, as well as identified costs to be incurred beyond May 31, 2017, expected to be subject to the $2.88 billion cost cap. Additional improvement projects to enhance plant performance, safety, and/or operations ultimately may be completed after the remainder of the Kemper IGCC is placed in service. These projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap.

~~The expected completion date of the Kemper IGCC at the time of the Mississippi PSC's approval in 2010 was May 2014. The~~ combined cycle and ~~the~~ associated common facilities portion of the Kemper IGCC were placed in service in August 2014. The remainder of the plant, including the gasifiers and the gas clean-up facilities, represents first-of-a-kind technology. Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. Mississippi Power continues to work toward achieving sustained operation sufficient to place the remainder of the plant in service. The plant has, however, produced and captured CO₂, and has produced sulfuric acid and ammonia, all of acceptable quality under the related off-take agreements. As a result of ongoing challenges associated with the ash removal and gas cleanup sour water systems, efforts to improve reliability and reach sustained operation of both gasifiers and production of electricity from syngas in both combustion turbines remain in process. Mississippi Power currently expects the remainder of the Kemper IGCC, including both gasifiers, will be placed in service by the end of May 2017.

In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation between Mississippi Power and the ~~Mississippi Public Utilities Staff (MPUS),~~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. ~~Upon placing~~As required by the ~~remainder~~In-Service Asset Rate Order, on June 5, 2017, Mississippi Power made a rate filing requesting to adjust the amortization schedules of the ~~plant~~regulatory assets reviewed and determined prudent in ~~service, Mississippi Power will be focused primarily on completing the regulatory cost recovery process.~~

~~Mississippi Power is required to file~~ a ~~rate case to address Kemper IGCC cost recovery by~~manner that would not change customer rates or annual revenues. On June 3,28, 2017, (2017 Rate Case). Costs incurred through March 31, 2017 totaled $6.93 billion, net of the Initial and Additional DOE Grants. Of this total, $2.87 billion of costs has been recognized through income as a result of the $2.88 billion cost cap, $0.83 billion is included in retail and wholesale rates for the assets in service, and the remainder will be the subject of the 2017 Rate Case to be filed with the Mississippi PSC ~~and expected subsequent wholesale Municipal and Rural Associations rate filing with~~suspended this filing. On July 6, 2017, the ~~FERC.~~Mississippi PSC issued an order requiring Mississippi Power ~~continues~~ to ~~believe that all costs~~establish a regulatory liability account to maintain current rates related to the Kemper IGCC ~~that remain subject to recovery have been prudently incurred in accordance with~~following the ~~requirements~~July 2017 completion of the ~~2012 MPSC CPCN Order.~~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 ~~recognizes~~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 ~~areas~~lead time and significant cost. In addition, the long-term natural gas price forecast has decreased significantly and the estimated cost of ~~potential challenge~~operating and maintaining the facility during ~~future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further herein, these challenges include, but are not limited~~the first five full years of operations has increased significantly since certification.

On June 21, 2017, the Mississippi PSC stated its intent to ~~prudence~~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 ~~capital~~the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket for the purposes of pursuing a global settlement of costs ~~financing~~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 ~~(AFUDC)~~subject to the construction cost cap, and was net of the $137 million in Additional DOE Grants.

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~~operating~~which includes estimated gasifier-related costs ~~net~~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 ~~chemical revenues; potential operating parameters;~~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 ~~tax issues;~~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.

~~In connection~~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, ~~Rate Case,~~noting Mississippi Power ~~expects~~and the MPUS had failed to ~~request authority from the~~reach a joint stipulation and ordering a full hearing. The Mississippi PSC ~~and separately from~~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 ~~FERC, to defer all~~combined cycle portion of the Kemper IGCC ~~costs incurred after the in-service date that cannot be capitalized, are~~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 ~~are not required~~expects them to be ~~charged against earnings as a result of~~recovered through rates consistent with the ~~$2.88 billion cost cap until such time as~~Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC ~~completes its review and includes the resulting allowable costs~~ in rates. In the event that the Mississippi PSC does not grant Mississippi Power's request for an accounting order, monthly expenses in the amount of $25 million per month will be charged to income as incurred and will not be recoverable through rates. In addition, after the remainder of the plant is placed in service, AFUDC equity of approximately $12 million per month will no longer be recorded in income.

~~Although the 2017 Rate Case has not yet been filed and is subject to future developments with either~~ the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, Mississippi Power is developing both a traditional rate case requesting full cost recovery of the $3.37 billion (net of $137 million in Additional DOE Grants) not currently in rates and a rate mitigation plan that together represent Mississippi Power's probable filing strategy. Mississippi Power has evaluated various scenarios in connection with its processes to prepare the 2017 Rate Case and recognized an $80 million charge to income in 2016, which is the estimated minimum probable amount of the $3.37 billion of Kemper IGCC costs not currently in rates that would not be recovered under the probable rate mitigation plan to be filed by June 3, 2017. Mississippi Power expects that timely resolution of the 2017 Rate Case will likely require a settlement agreement between Mississippi Power and the MPUS (and other parties) that may include other operational or cost recovery alternatives and would be subject to the approval of the Mississippi PSC. While Mississippi Power intends to pursue any available settlement alternatives, the ability to achieve a negotiated settlement is uncertain. If a settlement is achieved, full regulatory recovery of the amounts not currently in rates is unlikely and could result in further material charges; however, the impact of such an agreement on Southern Company's financial statements would depend on the method, amount, and type of cost recovery ultimately excluded, none of which can be reasonably determined at this time. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, Mississippi Power intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges. 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 these matters cannot now be determined but could result in further charges that could have a material impact on Southern Company's results of operations, financial condition, and liquidity.Settlement Docket proceedings.

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. On August 12, 2016, Southern Company and Mississippi Power removed the case to the U.S. District Court for the Southern District of Mississippi. The plaintiffs filed a request to remand the case back to state court, which was granted on November 17, 2016. The individual plaintiff ~~John Carlton Dean,~~ 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

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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 ~~December 7, 2016,~~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 ~~motions to dismiss, which the Circuit Court is expected to address in the second quarter 2017.~~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 CO₂contract 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 ~~have~~ moved to compel arbitration pursuant to the terms of the CO₂ contract, which the court ~~is expected to address~~granted on May 4, 2017. On June 28, 2017, Treetop and other related parties filed a claim for arbitration requesting $500 million in ~~the second quarter 2017.~~damages.

Southern Company believes these legal challenges have no merit; however, an adverse outcome in these proceedings could have ana 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, ~~Vogtle Construction Monitoring (VCM)~~VCM reports, the NCCR tariff, ~~the Vogtle Construction Litigation (as defined below),~~ and the Contractor Settlement ~~Agreement (as defined below).~~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 ~~an agreement with~~ the ~~Contractor,~~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 (Vogtle 3 and 4 Agreement).~~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 ~~provides~~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. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions with maximum additional capital costs under this provision attributable to Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%. In the event of a credit rating downgrade below investment grade of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement.

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~~on its ownership interest, pay to the Contractor and capitalize to the project cost approximately $350~~ million in settlement of disputed claims. Further, as a consequence of the settlement and Westinghouse's acquisition of WECTEC, Westinghouse engaged Fluor Enterprises, Inc. (Fluor Enterprises), a subsidiary of Fluor Corporation (Fluor), as a new construction subcontractor.

Under the terms of the Vogtle 3 and 4 Agreement, the Contractor does not have a right to terminate the Vogtle 3 and 4 Agreement for convenience. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. In the event of an abandonment of work by the Contractor, the maximum liability of the Contractor under the Vogtle 3 and 4 Agreement is increased to 40% of the contract price (approximately ~~$1.7 billion~~$420 million based on Georgia Power's ownership interest). The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for convenience, provided that the Vogtle Owners will be required to pay certain termination costs. In addition, the Vogtle Owners may terminate the Vogtle 3 and 4 Agreement for certain Contractor breaches, including abandonment of work by the Contractor.

Under the Toshiba Guarantee, Toshiba ~~has~~ guaranteed certain payment obligations of the EPC Contractor, including any liability of the EPC Contractor for abandonment of work. ~~However, due to Toshiba's financial situation described below, substantial risk regarding the Vogtle Owners' ability to fully collect under the Toshiba Guarantee exists.~~ 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. ~~In the event of such notice, the Vogtle Owners would be able to draw on the entire balance of the Westinghouse Letters of Credit. The Westinghouse Letters of Credit remain in place in accordance with~~

Under the terms of the Vogtle 3 and 4 ~~Agreement.~~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, ~~Westinghouse and WECTEC each~~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 Contractor and WECTEC Staffing, as of March 29, 2017 (Interim Assessment Agreement), to provide for a continuation of work with respect to Plant Vogtle Units 3 and 4. Georgia Power's entry into the Interim Assessment Agreement, ~~was conditioned upon South Carolina Electric & Gas Company entering into a similar interim assessment agreement with~~which the ~~Contractor relating to V.C. Summer, which also occurred~~bankruptcy court approved on March ~~29,~~30, 2017.

The ~~provisions in the~~ Interim Assessment Agreement became effective upon approval of the Interim Assessment Agreement by the bankruptcy court on March 30, 2017. The term of the Interim Assessment Agreement was originally scheduled to expire on April 28, 2017. On April 28, 2017, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an amendment to the Interim Assessment Agreement with the Contractor and WECTEC Staffing solely to extendprovided, among other items, that during the term of the Interim Assessment Agreement ~~through the earlier of (i) May 12, 2017 and (ii) termination of the Interim Assessment Agreement by any party upon five business days' notice (Interim Assessment Period).~~

~~The Interim Assessment Agreement provides, among other items, that (i)~~ Georgia Power ~~will be~~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 during the~~provided. The Interim Assessment Period, with these amounts to be paid to the Contractor, except for amounts accrued for Fluor, which will be paid directly to Fluor; (ii) during the Interim Assessment Period, the Contractor shall provide certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extentAgreement, as ~~contemplated by the Vogtle 3 and 4 Agreement, and Georgia Power,~~amended, expired on behalf of the Vogtle Owners, will make payments of $5.4 million per week for these services; (iii) Georgia Power will have the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who have accounts past due with the Contractor; (iv) during the Interim Assessment Period, the Contractor will use its commercially reasonable efforts to provide information reasonably requested by Georgia Power as is necessary to continue construction and investigate the completion status of Plant Vogtle Units 3 and 4; (v) the Contractor will reject or accept the Vogtle 3 and 4 Agreement by the termination of the Interim AssessmentJuly 27, 2017.

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~~Agreement; and (vi) during~~Subsequent to the Interim Assessment Period, Georgia Power will not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserve all rights and remedies under the Vogtle 3 and 4 Agreement, all related security and collateral, under applicable law.

AEPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, ~~have~~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, ~~action~~actions to remove liens filed by these subcontractors through the posting of surety bonds.

~~In February 2017, the Contractor provided Georgia Power with revised forecasted in-service dates of December 2019 and September 2020 for~~whether Plant Vogtle Units 3 and 4 ~~respectively. However, based~~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 ~~information subsequently made available during~~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 ~~WECTEC's bankruptcy proceedings and pursuant to the Interim Assessment Agreement, Georgia Power~~payable, and the Vogtle Owners ~~do not believe the revised in-service dates are achievable. Georgia Power, along with the other Vogtle Owners, is undertaking a comprehensive schedule~~may exercise any and ~~cost-to-complete assessment, as well as a cancellation cost assessment. It is reasonably possible these assessments result in estimated incremental costs to complete,~~all rights and remedies, including owners' costs, that materially exceed the value of the Toshiba Guarantee. Georgia Power intends to work with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4. Georgia Power, for itself and as agent for the other Vogtle Owners, is also negotiating a new service agreement which would, if necessary, engage the Contractor to provide design, engineering, and procurement services to Southern Nuclear, in the event Southern Nuclear assumes control over construction management. In addition, Georgia Power,drawing on behalf of itself and the other Vogtle Owners, intends to take all actions available to it to enforce its rights related to the Vogtle 3 and 4 Agreement, including enforcing the Toshiba Guarantee, subject to the Interim Assessment Agreement, and accessing the Westinghouse Letters of ~~Credit.~~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 ~~April 11,~~August 10, 2017, Toshiba ~~filed~~released its ~~unaudited~~ financial ~~statements as of and~~results for the ~~nine months~~quarter ended ~~December 31, 2016,~~June 30, 2017, which reflected a negative shareholders' equity balance of ~~$1.9~~approximately $4.5 billion ~~with Japanese regulators.~~as of June 30, 2017. Toshiba ~~also~~previously announced ~~that further substantial charges may be required in~~ the ~~quarter ended March 31, 2017 in connection with the bankruptcy filing~~existence of ~~Westinghouse and WECTEC and that there are~~ material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern.

~~The Contractor's bankruptcy filing is expected~~ As a result, substantial risk regarding the Vogtle Owners' ability to ~~have a material impact on~~fully collect 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 Southern Company's financial statements. In addition, an~~Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the ~~Toshiba~~ 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 ~~also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and~~ 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.

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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.

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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.

Under the terms of the Vogtle Cost Settlement Agreement, Plant Vogtle Units 3 and 4 will be placed into retail rate base on December 31, 2020 or when placed in service, whichever is later. The Georgia PSC will determine for retail ratemaking purposes the process of transitioning Plant Vogtle Units 3 and 4 from a construction project to an operating plant no later than Georgia Power's base rate case required to be filed by July 1, 2019.

The Georgia PSC has approved ~~fifteen~~sixteen VCM reports covering the periods through ~~June 30,~~December 31, 2016, including construction capital costs incurred, which through that date totaled ~~$3.7~~$3.9 billion. Georgia Power filed its ~~sixteenth~~seventeenth VCM report, covering the period from ~~July~~January 1 through ~~December 31, 2016,~~June 30, 2017, requesting approval of ~~$222~~$542 million of construction capital costs incurred during that period, with the Georgia PSC on ~~February 27,~~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 ~~CWIP balance~~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, ~~was approximately $4.1 billion as~~or the failure of ~~March 31, 2017 and~~the DOE to extend the Loan Guarantee Agreement with Georgia Power ~~had incurred $1.3 billion in financing costs through March 31, 2017.~~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 ~~March 31,~~September 30, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through ~~a loan guarantee agreement between Georgia Power and~~ the ~~DOE~~Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the ~~FFB.~~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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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.

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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 aswhile 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.

AsWhile 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. Georgia Power's previously estimated owner's costs of approximately $10 million per month and financing costs of approximately $30 million per month for Plant Vogtle Units 3 and 4 are being evaluated as part of the comprehensive schedule and cost-to-complete analysis being performed as a result of the Contractor's bankruptcy.

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 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.

Theultimateoutcomeofsuchpendingorpotentiallitigation~~againstSouthernCompanyanditssubsidiaries~~ or regulatory matters cannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementsherein,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.

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under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. ~~Southern Company believes this legal challenge has no merit; however,~~On June 12, 2017, the plaintiffs filed an ~~adverse outcome in this proceeding could have~~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 ~~impact~~opposition on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in this matter, and the ultimate outcome of this matter cannot be determined at this time.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 offormer Mississippi ~~Power's former~~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.

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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 ~~that this~~these legal ~~challenge has~~challenges have no merit; however, an adverse outcome in ~~this proceeding~~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 ~~this matter, and~~these matters, the ultimate outcome of ~~this matter~~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 estimated construction costs and expected in-service date.~~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

~~During 2017,~~Recovery" of Southern Company in Item 7 of the Form 10-K for additional information. Mississippi Power further revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions.

~~As a result of revisions to the cost estimate, Southern Company~~ recorded total pre-tax charges to income ~~for the estimated probable losses on~~related to the Kemper IGCC ~~subject to the construction cost cap~~ of ~~$108~~$428 million ($67264 million after tax) in ~~the first quarter 2017, $127~~2016, $365 million ($78226 million after tax) in ~~the fourth quarter 2016, $88~~2015, $868 million ($54536 million after tax) in ~~the third quarter 2016, $81 million~~2014, and $1.2 billion ($50729 million after tax) in prior years.

As a result of the ~~second quarter 2016, $53~~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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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 ($3321 million after tax) infor ongoing project costs during suspension, which includes estimated gasifier-related costs through December 31, 2017 to reflect the first quarter 2016, $183 million ($113 million after tax) in the fourth quarter 2015, $150 million ($93 million after tax) in the third quarter 2015, $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, and $540 million ($333 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $2.87 billion ($1.77 billion after tax) as a result of changes in the cost estimate above the cost capMississippi PSC's schedule for the Kemper IGCC Settlement Docket, as well as mine-related costs and other suspension costs through ~~March 31,~~September 30, 2017.

Mississippi Power's revised cost estimate reflects an expected in-service date of May 31, 2017 and includes certain post-in-service costs which are expected to be subject to the cost cap. Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, sustaining nitrogen supply, continued issues with ash removal systems, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).

In addition to the current construction cost estimate, Mississippi Power is also identifying potential improvement projects to enhance plant performance, safety, and/or operations that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. Approximately $12 million of related potential costs was recorded in 2016 and included in the current construction cost estimate. Other projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap. In subsequent periods, any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and these changes could be material.

Any extension of the ~~in-service date~~suspension period beyond ~~the end of May~~December 31, 2017 is currently estimated to result in additional ~~base~~suspension costs of approximately ~~$25~~$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 ~~$35~~$200 million ~~per month,~~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 ~~maintaining necessary levels~~costs in excess of ~~start-up labor, materials, and fuel,~~the original 2010 estimate for the combined cycle portion of the facility, as well as ~~operational resources required~~the 15% that was previously contracted to ~~execute start-up~~Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and ~~commissioning activities. However, additional costs may~~expects them to be ~~required for remediation of any further equipment and/or design issues identified. Any extension of~~recovered through rates consistent with the ~~in-service date beyond the end of May 2017 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established~~Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi ~~PSC. These costs include AFUDC, which is currently estimated to total approximately $16 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed~~PSC in ~~service and consulting and legal fees of approximately $3 million per month.~~

~~Mississippi Power continues to believe that all costs related to~~ the Kemper IGCC ~~that remain subject to recovery have been prudently incurred in accordance with~~Settlement Docket proceedings.

In the requirements of the 2012 MPSC CPCN Order. Mississippi Power also recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further in Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs," " – Prudence," " – Lignite Mine and CO₂ Pipeline Facilities," " – Termination of Proposed Sale of Undivided Interest," and " – Income Tax Matters" herein, these challenges include, but are not limited to, prudence issues associated with capital costs, financing costs (AFUDC), and future operating costs, net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the 15% portion of the project previously contracted to SMEPA.

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~~represent Mississippi Power's probable filing strategy.~~project started, Mississippi Power has ~~evaluated various scenarios in connection with its processes to prepare the 2017 Rate Case and recognized an $80 million charge to income in 2016, which is the estimated minimum probable amount~~incurred charges of ~~the $3.37~~$6.00 billion ~~of Kemper IGCC costs not currently in rates that would not be recovered under the probable rate mitigation plan to be filed by June 3,~~($3.96 billion after tax) through September 30, 2017. Mississippi Power ~~expects that timely resolution~~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 ~~Rate Case will likely require a settlement agreement between Mississippi Power~~ and the ~~MPUS (and other parties) that may include other operational or cost recovery alternatives~~third quarter 2016, respectively, and ~~would be subject to the approval~~total pre-tax charges of the Mississippi PSC. While Mississippi Power intends to pursue any available settlement alternatives, the ability to achieve a negotiated settlement is uncertain. If a settlement is achieved, full regulatory recovery of the amounts not currently$3.2 billion ($2.2 billion after tax) and $222 million ($137 million after tax) year-to-date in ~~rates is unlikely~~2017 and could result in further material charges; however, the impact of such an agreement on Southern Company's financial statements would depend on the method, amount, and type of cost recovery ultimately excluded, none of which can be reasonably determined at this time. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, Mississippi Power intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges.2016, respectively.

Given the significant judgment involved in estimating the ~~future~~ costs to ~~complete construction and start-up,~~cancel the ~~project completion date,~~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 ~~potential~~ 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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contractual ~~term. For such arrangements,~~term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements. Southern Company expects ~~that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and~~ the adoption of ASC 606 will not result in a significant shift infrom the current timing of revenue recognition for such ~~sales.~~transactions.

Southern Company's ongoing evaluation of other revenue streams and related contracts includes ~~longer term contractual commitments and~~ 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 ~~is currently addressing~~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 ~~expect~~sexpects 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 ~~must select~~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 ~~transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect~~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 ~~date~~adoption of ~~initial adoption. As~~ASC 606, including the ~~ultimate~~cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of ~~the new standard has not yet been determined,~~revenues recognized in Southern Company's financial statements, Southern Company ~~has not elected its transition method.~~

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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~~(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. ~~Southern Company is currently evaluating the new standard.~~ 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.

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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 ~~March 31,~~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 ~~$897 million~~$5.3 billion for the first ~~three~~nine months of 2017, an increase of ~~$19 million~~$1.0 billion from the corresponding period in 2016. The increase in net cash provided from operating activities was primarily due to ~~$758 million~~an increase of $1.5 billion in net cash provided from operating activities of Southern Company Gas, which was acquired on July 1, 2016, ~~largely~~partially offset by the timing of vendor ~~payments and a decrease in fuel cost recovery.~~payments. Net cash used for investing activities totaled ~~$2.8~~$6.7 billion for the first ~~three~~nine months of 2017 primarily due to the ~~construction of~~traditional electric ~~generation, transmission, and distribution facilities,~~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 ~~acquisition and construction of~~ renewable ~~facilities.~~acquisitions. Net cash provided from financing activities totaled ~~$1.0~~$1.3 billion for the first ~~three~~nine months of 2017 primarily due to net issuances of long-term and short-term debt, partially offset by ~~redemptions of long-term debt and~~ common stock dividend payments. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first ~~three~~nine months of 2017 include an increase of ~~$1.4~~$1.3 billion in total property, plant, and equipment primarily related to ~~Southern Power's wind facility acquisition and~~ the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution ~~facilities;~~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 ~~$0.9~~$0.4 billion in ~~cash~~income taxes receivable, current and ~~cash equivalents~~unrecognized tax benefits primarily related to ~~acquisition payments at Southern Power; an increase of $0.6 billion in notes payable primarily~~

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~~related to an increase in commercial paper borrowings; and~~income tax refunds associated with deductible R&E expenditures; a decrease of $0.5 billion in ~~accounts~~acquisitions payable related to Southern Power; an increase of $2.3 billion in long-term debt (including amounts due within one year) primarily ~~due~~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 ~~timing~~estimated probable losses on the Kemper IGCC, partially offset by the issuance of ~~vendor payments.~~additional shares of common stock.

At the end of the ~~first~~third quarter 2017, the market price of Southern Company's common stock was ~~$49.78~~$49.14 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was ~~$25.23~~$23.99 per share, representing a market-to-book ratio of ~~197%~~205%, compared to $49.19, $25.00, and 197%, respectively, at the end of 2016. Southern Company's common stock dividend for the ~~first~~third quarter 2017 was ~~$0.56~~$0.58 per share compared to ~~$0.5425~~$0.56 per share in the ~~first~~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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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. ~~Approximately $3.3~~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 ~~March 31,~~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" ~~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 "Integrated Coal Gasification Combined Cycle~~" herein for information regarding additional factors that may impact construction ~~expenditures.~~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 –

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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 ~~has~~ entered into ~~a loan guarantee agreement (Loan~~the Loan Guarantee ~~Agreement)~~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)~~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. ~~Eligible Project Costs incurred through March 31,~~As of September 30, 2017, ~~would allow for borrowings of up to $2.8~~Georgia Power had borrowed $2.6 billion under the FFB Credit ~~Facility, of which~~Facility. On July 27, 2017, Georgia Power ~~has borrowed $2.6 billion. The Contractor's bankruptcy and failure~~entered into an amendment to ~~perform its obligations under~~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 ~~could impact~~and satisfaction of certain other conditions.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On September 28, 2017, the DOE issued a conditional commitment to Georgia ~~Power's ability~~Power for up to ~~make further borrowings~~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.

Mississippi Power received $245 million of Initial DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of grants from the DOE is expected to be received for commercial operation of the Kemper IGCC. In April 2016, Mississippi Power received approximately $137 million in Additional DOE Grants for the Kemper IGCC, which are expected to be used to reduce future rate impacts for customers. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.

As of ~~March 31,~~September 30, 2017, Southern Company's current liabilities exceeded current assets by ~~$3.9~~$3.4 billion ~~primarily~~ due to long-term debt that is due within one year of ~~$3.3~~$3.5 billion ~~including~~(comprised of approximately ~~$0.4~~$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 ~~Alabama Power, $0.5 billion at~~ Georgia Power, $0.1 billion at ~~Gulf Power, $1.3 billion at Mississippi~~Southern Power, and ~~$0.6~~$0.9 billion at Southern ~~Power.~~Company Gas). To meet short-term cash needs and contingencies, the Southern Company system has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional electric operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.

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~~SOUTHERN COMPANY AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

At ~~March 31,~~September 30, 2017, Southern Company and its subsidiaries had approximately ~~$1.1~~$1.8 billion of cash and cash equivalents. Committed credit arrangements with banks at ~~March 31,~~September 30, 2017 were as follows:


	Expires										Executable Term Loans				Expires Within One Year				Expires														Executable Term Loans				Expires Within One Year
Company	2017		2018		2020		Total		Unused		One Year		Two Years		Term Out		No Term Out		2017		2018		2019		2020		2022		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)																		(in millions)
Southern Company^(a)	$	—	$	1,000	$	1,250	$	2,250	$	2,250	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	2,000	$	2,000	$	2,000	$	—	$	—	$	—	$	—
Alabama Power	35		500		800		1,335		1,335		—		—		—		35		—		35		—		500		800		1,335		1,335		—		—		—		35
Georgia Power	—		—		1,750		1,750		1,732		—		—		—		—		—		—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	85		195		—		280		280		45		—		25		70		30		195		25		30		—		280		280		45		—		—		40
Mississippi Power	173		—		—		173		141		—		13		13		160		100		—		—		—		—		100		100		—		—		—		100
Southern Power Company(b)	—		—		600		600		524		—		—		—		—		—		—		—		—		750		750		728		—		—		—		—
Southern Company Gas^(b)(c)	75		1,925		—		2,000		1,949		—		—		—		75		—		—		—		—		1,900		1,900		1,861		—		—		—		—
Other	55		—		—		55		55		20		—		20		35		—		30		—		—		—		30		30		20		—		20		10
Southern Company Consolidated	$	423	$	3,620	$	4,400	$	8,443	$	8,266	$	65	$	13	$	58	$	375	$	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 $~~1.3~~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.

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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, ~~Gulf~~Georgia Power, Mississippi Power, and Southern Power Company, contain covenants that limit debt levels and contain ~~cross acceleration~~cross-acceleration or ~~cross default~~cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such ~~cross default~~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~~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 ~~March 31,~~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 ~~March 31,~~September 30, 2017 was approximately $1.5 billion as compared to $1.9 ~~billion.~~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 ~~March 31,~~September 30, 2017, the traditional electric operating companies had approximately ~~$386~~$699 million of ~~fixed rate~~ 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.

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~~programs that have the liquidity support of the committed bank credit arrangements described above. Short-term borrowings are included in notes payable in the balance sheets.~~

Details of short-term borrowings were as follows:


	Short-term Debt at March 31, 2017				Short-term Debt During the Period^(*)						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		Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)		(in millions)				(in millions)				(in millions)
Commercial paper	$	2,682	1.2	%	$	2,355	1.1	%	$	2,885	$	1,725	1.5	%	$	1,895	1.5	%	$	2,284
Short-term bank debt	136		2.2	%	125		1.8	%	349		854		2.0	%	938		2.1	%	1,017
Total	$	2,818	1.3	%	$	2,480	1.1	%			$	2,579	1.7	%	$	2,833	1.7	%


(*)	Average and maximum amounts are based upon daily balances during the three-month period ended ~~March 31,~~September 30, 2017.

~~In addition, in connection with the construction of the Roserock solar facility, RE Roserock LLC, an~~ ~~indirect subsidiary of Southern Power, previously entered into a credit agreement that was fully repaid on January 31, 2017.~~ For the three-month period ended March 31, 2017, this credit agreement had a maximum amount outstanding of $209 million and an average amount outstanding of $70 million at a weighted average interest rate of 2.1%.

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 ~~March 31,~~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, foreign currency risk management, and construction of new generation at Plant Vogtle Units 3 and 4.~~management.

The maximum potential collateral requirements under these contracts at ~~March 31,~~September 30, 2017 were as follows:


Credit Ratings	Maximum Potential Collateral Requirements		Maximum Potential Collateral Requirements
	(in millions)		(in millions)
At BBB and/or Baa2	$	39	$	38
At BBB- and/or Baa3	$	659	$	647
At BB+ and/or Ba1^(*)	$	2,649	$	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.

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~~SOUTHERN COMPANY AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities

During the first ~~three~~nine months of 2017, Southern Company issued approximately ~~4.2~~10.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately ~~$186~~$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 ~~three~~nine months of 2017:


Company^(a)	Senior Note Issuances		Senior Note Maturities and Redemptions		Other Long-Term Debt Issuances		Other Long-Term Debt Redemptions and Maturities^(b)		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)								(in millions)
Southern Company^(c)(b)	$	—	$	—	$	—	$	400	$	300	$	400	$	—	$	500		$	400
Alabama Power	550		200		—		—		550		200		36		—			—
Georgia Power	850		—		—		2		1,350		450		65		370			13
Gulf Power	—		—		6		—		300		85		—		6			—
Mississippi Power									—		—		—		40			893
Southern Power	—		—		3		2		—		—		—		43			4
Southern Company Gas^(c)									450		—		—		200			22
Other	—		—		—		4		—		—		—		—			12
Elimination^(d)									—		—		—		(40		)	(599		)
Southern Company Consolidated	$	1,400	$	200	$	9	$	408	$	2,950	$	1,135	$	101	$	1,119		$	745


(a)	~~Mississippi Power and Southern Company Gas did not issue or redeem any long-term debt during the first three months of 2017.~~


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


~~(c)~~(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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

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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.

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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.

PART I

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

During the ~~three~~nine months ended ~~March 31,~~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 ~~first~~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.

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months Ended March 31,						For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016			2017			2016
	(in millions)						(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,227		$	1,193		$	1,595		$	1,629		$	4,155		$	4,139
Wholesale revenues, non-affiliates	66			63			77			82			210			211
Wholesale revenues, affiliates	33			22			18			18			83			49
Other revenues	56			53			50			56			158			162
Total operating revenues	1,382			1,331			1,740			1,785			4,606			4,561
Operating Expenses:
Fuel	298			268			343			410			944			973
Purchased power, non-affiliates	34			36			57			63			132			139
Purchased power, affiliates	28			33			55			41			117			129
Other operations and maintenance	369			392			391			348			1,134			1,097
Depreciation and amortization	181			172			185			177			549			524
Taxes other than income taxes	96			97			93			96			284			286
Total operating expenses	1,006			998			1,124			1,135			3,160			3,148
Operating Income	376			333			616			650			1,446			1,413
Other Income and (Expense):
Allowance for equity funds used during construction	8			10			11			7			27			23
Interest expense, net of amounts capitalized	(75		)	(73		)	(76		)	(77		)	(229		)	(224		)
Other income (expense), net	(5		)	(8		)	(5		)	(5		)	(8		)	(16		)
Total other income and (expense)	(72		)	(71		)	(70		)	(75		)	(210		)	(217		)
Earnings Before Income Taxes	304			262			546			575			1,236			1,196
Income taxes	126			102			216			219			493			462
Net Income	178			160			330			356			743			734
Dividends on Preferred and Preference Stock	4			4			5			4			14			13
Net Income After Dividends on Preferred and Preference Stock	$	174		$	156		$	325		$	352		$	729		$	721

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months Ended March 31,					For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2017		2016			2017		2016		2017		2016
	(in millions)					(in millions)				(in millions)
Net Income	$	178	$	160		$	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 and $1, respectively	1		1
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		)	1		1		3		1
Comprehensive Income	$	179	$	159		$	331	$	357	$	746	$	735

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

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Three Months Ended March 31,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Operating Activities:
Net income	$	178		$	160		$	743		$	734
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	219			211			666			634
Deferred income taxes	59			68			260			267
Allowance for equity funds used during construction							(27		)	(23		)
Pension, postretirement, and other employee benefits							(4		)	(14		)
Other, net	(3		)	(14		)	43			(12		)
Changes in certain current assets and liabilities —
-Receivables	30			191			(163		)	(4		)
-Fossil fuel stock	10			(27		)	34			18
-Other current assets	(87		)	(87		)	(58		)	(46		)
-Accounts payable	(214		)	(143		)	(125		)	(113		)
-Accrued taxes	77			66			159			207
-Accrued compensation	(96		)	(75		)	(48		)	(22		)
-Retail fuel cost over recovery	(36		)	(1		)	(76		)	(104		)
-Other current liabilities	(9		)	(8		)	7			19
Net cash provided from operating activities	128			341			1,411			1,541
Investing Activities:
Property additions	(306		)	(313		)	(1,211		)	(947		)
Nuclear decommissioning trust fund purchases	(63		)	(105		)	(174		)	(275		)
Nuclear decommissioning trust fund sales	63			105			174			275
Cost of removal, net of salvage	(26		)	(31		)	(82		)	(70		)
Change in construction payables	5			(15		)	105			(37		)
Other investing activities	(2		)	(9		)	(29		)	(28		)
Net cash used for investing activities	(329		)	(368		)	(1,217		)	(1,082		)
Financing Activities:
Proceeds —
Senior notes	550			400			550			400
Capital contributions from parent company	314			236			337			253
Preferred stock							250			—
Other long-term debt	—			45			—			45
Redemptions and repurchases — Senior notes	(200		)	(200		)
Redemptions —
Pollution control revenue bonds							(36		)	—
Senior notes							(200		)	(200		)
Payment of common stock dividends	(179		)	(191		)	(536		)	(574		)
Other financing activities	(8		)	(13		)	(26		)	(21		)
Net cash provided from financing activities	477			277
Net cash provided from (used for) financing activities							339			(97		)
Net Change in Cash and Cash Equivalents	276			250			533			362
Cash and Cash Equivalents at Beginning of Period	420			194			420			194
Cash and Cash Equivalents at End of Period	$	696		$	444		$	953		$	556
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $3 and $4 capitalized for 2017 and 2016, respectively)	$	84		$	76
Interest (net of $10 and $8 capitalized for 2017 and 2016, respectively)							$	217		$	215
Income taxes, net	—			(162		)	146			(70		)
Noncash transactions — Accrued property additions at end of period	90			106			189			84

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

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


Assets	At March 31, 2017			At December 31, 2016			At September 30, 2017			At December 31, 2016
	(in millions)						(in millions)
Current Assets:
Cash and cash equivalents	$	696		$	420		$	953		$	420
Receivables —
Customer accounts receivable	326			348			428			348
Unbilled revenues	127			146			149			146
Other accounts and notes receivable	31			27			47			27
Affiliated	35			40			45			40
Accumulated provision for uncollectible accounts	(10		)	(10		)	(8		)	(10		)
Fossil fuel stock	195			205			171			205
Materials and supplies	444			435			455			435
Prepaid expenses	106			34			58			34
Other regulatory assets, current	141			149			122			149
Other current assets	8			11			5			11
Total current assets	2,099			1,805			2,425			1,805
Property, Plant, and Equipment:
In service	26,134			26,031			26,619			26,031
Less: Accumulated provision for depreciation	9,241			9,112			9,463			9,112
Plant in service, net of depreciation	16,893			16,919			17,156			16,919
Nuclear fuel, at amortized cost	332			336			314			336
Construction work in progress	642			491			928			491
Total property, plant, and equipment	17,867			17,746			18,398			17,746
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	65			66			65			66
Nuclear decommissioning trusts, at fair value	825			792			869			792
Miscellaneous property and investments	113			112			121			112
Total other property and investments	1,003			970			1,055			970
Deferred Charges and Other Assets:
Deferred charges related to income taxes	526			525			525			525
Deferred under recovered regulatory clause revenues	—			150			17			150
Other regulatory assets, deferred	1,218			1,157			1,191			1,157
Other deferred charges and assets	156			163			178			163
Total deferred charges and other assets	1,900			1,995			1,911			1,995
Total Assets	$	22,869		$	22,516		$	23,789		$	22,516

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

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


Liabilities and Stockholder's Equity	At March 31, 2017			At December 31, 2016			At September 30, 2017			At December 31, 2016
	(in millions)						(in millions)
Current Liabilities:
Securities due within one year	$	361		$	561		$	325		$	561
Accounts payable —
Affiliated	224			297			275			297
Other	232			433			376			433
Customer deposits	90			88			92			88
Accrued taxes —
Accrued income taxes	95			45			115			45
Other accrued taxes	65			42			128			42
Accrued interest	65			78			75			78
Accrued compensation	95			193			151			193
Other regulatory liabilities, current	45			85			4			85
Other current liabilities	71			76			50			76
Total current liabilities	1,343			1,898			1,591			1,898
Long-term Debt	7,081			6,535			7,083			6,535
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,714			4,654			4,919			4,654
Deferred credits related to income taxes	65			65			60			65
Accumulated deferred investment tax credits	108			110
Accumulated deferred ITCs							118			110
Employee benefit obligations	288			300			289			300
Asset retirement obligations	1,523			1,503			1,564			1,503
Other cost of removal obligations	667			684			630			684
Other regulatory liabilities, deferred	88			100			93			100
Other deferred credits and liabilities	70			63			51			63
Total deferred credits and other liabilities	7,523			7,479			7,724			7,479
Total Liabilities	15,947			15,912			16,398			15,912
Redeemable Preferred Stock	85			85			329			85
Preference Stock	196			196			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			1,222			1,222
Paid-in capital	2,936			2,613			2,961			2,613
Retained earnings	2,513			2,518			2,711			2,518
Accumulated other comprehensive loss	(30		)	(30		)	(28		)	(30		)
Total common stockholder's equity	6,641			6,323			6,866			6,323
Total Liabilities and Stockholder's Equity	$	22,869		$	22,516		$	23,789		$	22,516

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

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~FIRST~~THIRD QUARTER 2017 vs. ~~FIRST~~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

First Quarter 2017 vs. First Quarter 2016
(change in millions)
(% change)
$18 11.5

Alabama Power's net income after dividends on preferred and preference stock for the ~~first~~third quarter 2017 was ~~$174~~$325 million compared to ~~$156~~$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, ~~and a decrease in non-fuel operations and maintenance expenses. The increase to net income was~~ partially offset by a decrease in ~~weather-related~~retail revenues associated with milder weather ~~in the first quarter~~and lower customer usage for year-to-date 2017 compared to the corresponding period in ~~2016.~~2016, and an increase in non-fuel operations and maintenance expenses.

Retail Revenues

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$34 2.8

In the ~~first~~third quarter 2017, retail revenues were ~~$1.23~~$1.60 billion compared to ~~$1.19~~$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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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:


	First Quarter 2017					Third Quarter 2017					Year-to-Date 2017
	(in millions)			(% change)		(in millions)			(% change)		(in millions)				(% change)
Retail – prior year	$	1,193				$	1,629				$	4,139
Estimated change resulting from –
Rates and pricing	80			6.7		85			5.2		240				5.8
Sales growth (decline)	(1		)	(0.1	)
Sales decline						(18		)	(1.1	)	(31		)		(0.7	)
Weather	(55		)	(4.6	)	(50		)	(3.1	)	(116		)		(2.8	)
Fuel and other cost recovery	10			0.8		(51		)	(3.1	)	(77		)		(1.9	)
Retail – current year	$	1,227		2.8	%	$	1,595		(2.1	)%	$	4,155		��	0.4	%

Revenues attributable to changes in sales ~~remained essentially flat~~decreased in the ~~first~~third quarter and year-to-date 2017 when compared to the corresponding ~~period~~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 ~~decreased 1.2%~~increased 1.8% and 0.6% for the ~~first~~third quarter and year-to-date 2017, ~~when compared to the corresponding period in 2016~~respectively, as a result of ~~a decrease~~an increase in demand resulting from changes in production levels primarily in the ~~pipeline sector,~~primary metals, chemicals, and mining sectors, partially offset by ~~an increase~~a decrease in demand from the chemicals and paper sectors. Weather-adjusted commercial KWH sales decreased 1.2% for the first quarter 2017 due to lower customer usage. Weather-adjusted residential KWH sales increased 0.6% for the first quarter 2017 primarily due to customer growth.pipeline sector.

Revenues resulting from changes in weather decreased in the ~~first~~third quarter and year-to-date 2017 due to milder weather experienced in Alabama Power's service territory compared to the corresponding ~~period~~periods in 2016. For the ~~first~~third quarter 2017, the resulting decreases were ~~9.0%~~5.1% and ~~2.1%~~2.4% for residential and commercial sales ~~revenue,~~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 ~~increased~~decreased in the ~~first~~third quarter and year-to-date 2017 when compared to the corresponding ~~period~~periods in 2016 primarily due to ~~an increase~~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

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$11 50.0

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

In the first quarter 2017, wholesale revenues from sales to affiliates were $33 million compared to $22 million for the corresponding period in 2016. The increase was primarily due to a 41.3% increase in KWH sales as a result of lower cost Alabama Power-owned generation as compared to the market cost of available energy and a 7.9% increase in the price of energy due to an increase in natural gas prices.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

First Quarter 2017
vs.
First Quarter 2016
(change in millions) (% change)
Fuel $ 30
11.2
Purchased power – non-affiliates (2 ) (5.6 )
Purchased power – affiliates (5 ) (15.2 )
Total fuel and purchased power expenses $ 23

~~In the first quarter~~For year-to-date 2017, ~~fuel and purchased power expenses~~wholesale revenues from sales to affiliates were ~~$360~~$83 million compared to ~~$337~~$49 million for the corresponding period in 2016. The increase was primarily due to a ~~$41~~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

In the third quarter 2017, other revenues were $50 million ~~increase~~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 $4$16 million ~~net increase~~decrease related to the average cost of fuel.

For year-to-date 2017, fuel and purchased power ~~and fuel. These increases~~expenses were ~~partially offset by~~$1.19 billion compared to $1.24 billion for the corresponding period in 2016. The decrease was primarily due to a ~~$22~~$53 million decrease in the volume of KWHs ~~purchased.~~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.

Table of Contents

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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


	First Quarter 2017	First Quarter 2016	Third Quarter 2017	Third Quarter 2016	Year-to-Date 2017	Year-to-Date 2016
Total generation (in billions of KWHs)	15	15	16	18	46	46
Total purchased power (in billions of KWHs)	1	1	2	2	5	6
Sources of generation (percent) —
Coal	49	40	52	59	49	51
Nuclear	26	27	24	22	25	24
Gas	20	19	19	18	20	19
Hydro	5	14	5	1	6	6
Cost of fuel, generated (in cents per net KWH) —
Coal	2.60	2.86	2.61	2.73	2.61	2.80
Nuclear	0.74	0.77	0.75	0.77	0.75	0.78
Gas	2.77	2.46	2.72	2.85	2.74	2.62
Average cost of fuel, generated (in cents per net KWH)^(a)	2.13	2.12	2.17	2.32	2.15	2.25
Average cost of purchased power (in cents per net KWH)^(b)	6.70	5.16	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 ~~first~~third quarter 2017, fuel expense was ~~$298~~$343 million compared to ~~$268~~$410 million for the corresponding period in 2016. The ~~increase~~decrease was primarily due to an 18.4% decrease in the volume of KWHs generated by coal, a ~~23.1%~~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 ~~12.6%~~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,~~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 ~~9.1%~~14.5% decrease in the average cost ~~of coal~~ per KWH ~~generated.~~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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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Purchased Power – Affiliates~~

In the first quarter 2017, purchased power expense from affiliates was $28 million compared to $33 million for the corresponding period in 2016. The decrease was primarily related to a 43.6% decrease in the amount of energy purchased as a result of decreased demand in 2017, partially offset by a 47.6% increase in the average cost of purchased power per KWH as a result of fixed natural gas transportation costs for Plant Gaston.

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

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$(23) (5.9)

In the ~~first~~third quarter 2017, other operations and maintenance expenses were ~~$369~~$391 million compared to ~~$392~~$348 million for the corresponding period in 2016. The ~~decrease~~increase was primarily due to ~~decreases~~increases of ~~$23~~$26 million in scheduled ~~steam and other power~~ generation outage ~~and labor~~costs, $11 million in vegetation management costs, and $3 million in ~~nuclear generation~~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 ~~lower~~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

In the third quarter 2017, depreciation and amortization ~~of prior outage costs. In addition, bad debt expense decreased $2 million.~~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 ~~decreases~~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 ~~$6 million increase~~decrease in ~~vegetation management costs.~~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

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$24 23.5

~~In the first quarter~~For year-to-date 2017, income taxes were ~~$126~~$493 million compared to ~~$102~~$462 million for the corresponding period in 2016. The increase was primarily due to higher pre-tax earnings, ~~and~~ unrecognized tax benefits related to certain state deductions for federal income ~~taxes.~~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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ALABAMA POWER COMPANY

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 ~~economic growth. The~~the pace of economic growth ~~and electricity demand~~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

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~~ALABAMA POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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 and~~programs.

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.

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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 ~~matter~~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

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~~ALABAMA POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Theultimateoutcomeofsuchpendingorpotentiallitigation~~againstAlabama Power~~ or regulatory matters cannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementsherein,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.

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. For such arrangements,~~term, as well as longer-term contractual commitments, including PPAs. Alabama Power expects that the revenue from contracts with these customers ~~will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606~~ 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 ~~longer term contractual commitments and~~ unregulated sales to customers. Some revenue arrangements, such as ~~certain PPAs and~~ alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

disclosed or presented separately from revenues under ASC 606 on Alabama Power's financial ~~statements.~~statements, if material. In addition, the power and utilities industry ~~is currently addressing~~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 ~~must select~~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 ~~transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect~~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 ~~date~~adoption of ~~initial adoption. As~~ASC 606, including the ~~ultimate~~cumulative-

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

effect adjustment, is not expected to have a material impact on either the timing or amount of ~~the new standard has not yet been determined,~~revenues recognized in Alabama Power's financial statements, Alabama Power ~~has not elected its transition method.~~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~~(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. ~~Alabama Power is currently evaluating the new standard.~~ 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 ~~March 31,~~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 ~~$128 million~~$1.4 billion for the first ~~three~~nine months of 2017, a decrease of ~~$213~~$130 million as compared to the first ~~three~~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 and the timing of vendor payments.~~depreciation. Net cash used for investing activities totaled ~~$329 million~~$1.2 billion for the first ~~three~~nine months of 2017 primarily due to gross property additions related to distribution, environmental, transmission, ~~environmental,~~ and steam generation. Net cash provided from financing activities totaled ~~$477~~$339 million for the first ~~three~~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 ~~three~~nine months of 2017 include increases of ~~$546~~$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, ~~$323~~$533 million in cash and cash equivalents, $348 million in additional paid-in capital due to capital contributions from Southern Company, ~~$276~~$265 million in cash and cash equivalents, and $121 million in property, plant, and equipment, primarily due to additions to environmental, transmission, steam generation, and distribution. Other significant changes include decreases of $201 million in other accounts payable primarily due to

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accumulated deferred income taxes primarily due to bonus depreciation, and $244 million in redeemable preferred stock primarily due to the ~~timing~~September 2017 issuance, as well as a decrease of ~~vendor payments, $200~~$236 million in securities due within one year, and $150 million in deferred under recovered regulatory clause revenues primarily due to the application of the Rate RSE refund liability and establishment of a separate regulatory asset to eliminate the under-recovered balance in Rate CNP PPA in accordance with the accounting order issued by the Alabama PSC. 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 regarding Alabama Power's rate mechanisms.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. ~~Approximately $361~~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 ~~March 31,~~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.

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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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 ~~March 31,~~September 30, 2017, Alabama Power had approximately ~~$696~~$953 million of cash and cash equivalents. Committed credit arrangements with banks at ~~March 31,~~September 30, 2017 were as follows:


Expires	Expires									Expires Within One Year				Expires									Expires Within One Year
2017		2018		2020		Total		Unused		Term Out		No Term Out
2018														2018	2020		2022		Total		Unused		Term Out		No Term Out
(in millions)
$	35	$	500	$	800	$	1,335	$	1,335	$	—	$	35	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.

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~~ALABAMA POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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~~cross-acceleration provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such ~~cross acceleration~~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 ~~March 31,~~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 ~~$890~~$854 million as of ~~March 31,~~September 30, 2017. At ~~March 31,~~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.

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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
0.9 % $ 200



	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 ~~March 31,~~September 30, 2017. No short-term debt was outstanding at ~~March 31,~~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 ~~March 31,~~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.

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~~ALABAMA POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

The maximum potential collateral requirements under these contracts at ~~March 31,~~September 30, 2017 were as follows:


Credit Ratings	Maximum Potential Collateral Requirements		Maximum Potential Collateral Requirements
	(in millions)		(in millions)
At BBB and/or Baa2	$	1	$	1
At BBB- and/or Baa3	$	2	$	2
Below BBB- and/or Baa3	$	316	$	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).

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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.

~~GEORGIA~~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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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

Income Tax Matters

Bonus Depreciation

Section 174 Research and Experimental Deduction

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Power

Other 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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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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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.

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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.

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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

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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

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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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.

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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.

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.

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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.

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.

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 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.

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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.

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.

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

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.


(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.

ALABAMA POWER COMPANY

~~GEORGIA~~ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months Ended March 31,						For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016			2017			2016
	(in millions)						(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,689		$	1,717		$	1,595		$	1,629		$	4,155		$	4,139
Wholesale revenues, non-affiliates	39			41			77			82			210			211
Wholesale revenues, affiliates	8			5			18			18			83			49
Other revenues	96			109			50			56			158			162
Total operating revenues	1,832			1,872			1,740			1,785			4,606			4,561
Operating Expenses:
Fuel	371			376			343			410			944			973
Purchased power, non-affiliates	88			83			57			63			132			139
Purchased power, affiliates	172			139			55			41			117			129
Other operations and maintenance	381			457			391			348			1,134			1,097
Depreciation and amortization	221			211			185			177			549			524
Taxes other than income taxes	98			97			93			96			284			286
Total operating expenses	1,331			1,363			1,124			1,135			3,160			3,148
Operating Income	501			509			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	(101		)	(94		)	(76		)	(77		)	(229		)	(224		)
Other income (expense), net	20			17			(5		)	(5		)	(8		)	(16		)
Total other income and (expense)	(81		)	(77		)	(70		)	(75		)	(210		)	(217		)
Earnings Before Income Taxes	420			432			546			575			1,236			1,196
Income taxes	156			159			216			219			493			462
Net Income	264			273			330			356			743			734
Dividends on Preferred and Preference Stock	4			4			5			4			14			13
Net Income After Dividends on Preferred and Preference Stock	$	260		$	269		$	325		$	352		$	729		$	721

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months Ended March 31,				For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2017		2016		2017		2016		2017		2016
	(in millions)				(in millions)				(in millions)
Net Income	$	264	$	273	$	330	$	356	$	743	$	734
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $- and $-, respectively	—		—
Reclassification adjustment for amounts included in net income, net of tax of $- and $-, respectively	1		1
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		1		1		3		1
Comprehensive Income	$	265	$	274	$	331	$	357	$	746	$	735

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

~~GEORGIA~~ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Three Months Ended March 31,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Operating Activities:
Net income	$	264		$	273		$	743		$	734
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	271			261			666			634
Deferred income taxes	71			55			260			267
Allowance for equity funds used during construction	(13		)	(14		)	(27		)	(23		)
Deferred expenses	38			38
Pension, postretirement, and other employee benefits	(21		)	(10		)	(4		)	(14		)
Settlement of asset retirement obligations	(22		)	(24		)
Other, net	(29		)	27			43			(12		)
Changes in certain current assets and liabilities —
-Receivables	142			155			(163		)	(4		)
-Fossil fuel stock	(38		)	36			34			18
-Prepaid income taxes	5			38
-Other current assets	(16		)	12			(58		)	(46		)
-Accounts payable	(155		)	4			(125		)	(113		)
-Accrued taxes	(235		)	(235		)	159			207
-Accrued compensation	(87		)	(66		)	(48		)	(22		)
-Retail fuel cost over recovery	(66		)	14			(76		)	(104		)
-Other current liabilities	2			2			7			19
Net cash provided from operating activities	111			566			1,411			1,541
Investing Activities:
Property additions	(556		)	(553		)	(1,211		)	(947		)
Nuclear decommissioning trust fund purchases	(161		)	(211		)	(174		)	(275		)
Nuclear decommissioning trust fund sales	155			206			174			275
Cost of removal, net of salvage	(17		)	(15		)	(82		)	(70		)
Change in construction payables, net of joint owner portion	(36		)	(101		)
Payments pursuant to LTSAs	(22		)	(11		)
Sale of property	63			—
Change in construction payables							105			(37		)
Other investing activities	8			(4		)	(29		)	(28		)
Net cash used for investing activities	(566		)	(689		)	(1,217		)	(1,082		)
Financing Activities:
Decrease in notes payable, net	(391		)	(158		)
Proceeds —
Senior notes							550			400
Capital contributions from parent company	345			218			337			253
Senior notes	850			650
Redemptions and repurchases —
Preferred stock							250			—
Other long-term debt							—			45
Redemptions —
Pollution control revenue bonds	—			(4		)	(36		)	—
Senior notes	—			(250		)	(200		)	(200		)
Payment of common stock dividends	(320		)	(326		)	(536		)	(574		)
Other financing activities	(11		)	(14		)	(26		)	(21		)
Net cash provided from financing activities	473			116
Net cash provided from (used for) financing activities							339			(97		)
Net Change in Cash and Cash Equivalents	18			(7		)	533			362
Cash and Cash Equivalents at Beginning of Period	3			67			420			194
Cash and Cash Equivalents at End of Period	$	21		$	60		$	953		$	556
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $5 and $5 capitalized for 2017 and 2016, respectively)	$	88		$	86
Interest (net of $10 and $8 capitalized for 2017 and 2016, respectively)							$	217		$	215
Income taxes, net	(5		)	(88		)	146			(70		)
Noncash transactions — Accrued property additions at end of period	320			290			189			84

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

~~GEORGIA~~ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


Assets	At March 31, 2017			At December 31, 2016			At September 30, 2017			At December 31, 2016
	(in millions)						(in millions)
Current Assets:
Cash and cash equivalents	$	21		$	3		$	953		$	420
Receivables —
Customer accounts receivable	470			523			428			348
Unbilled revenues	200			224			149			146
Joint owner accounts receivable	146			57
Other accounts and notes receivable	57			81			47			27
Affiliated	12			18			45			40
Accumulated provision for uncollectible accounts	(3		)	(3		)	(8		)	(10		)
Fossil fuel stock	336			298			171			205
Materials and supplies	474			479			455			435
Prepaid expenses	35			105			58			34
Other regulatory assets, current	195			193			122			149
Other current assets	38			38			5			11
Total current assets	1,981			2,016			2,425			1,805
Property, Plant, and Equipment:
In service	34,059			33,841			26,619			26,031
Less: Accumulated provision for depreciation	11,443			11,317			9,463			9,112
Plant in service, net of depreciation	22,616			22,524			17,156			16,919
Nuclear fuel, at amortized cost	570			569			314			336
Construction work in progress	5,183			4,939			928			491
Total property, plant, and equipment	28,369			28,032			18,398			17,746
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	58			60			65			66
Nuclear decommissioning trusts, at fair value	853			814			869			792
Miscellaneous property and investments	46			46			121			112
Total other property and investments	957			920			1,055			970
Deferred Charges and Other Assets:
Deferred charges related to income taxes	676			676			525			525
Deferred under recovered regulatory clause revenues							17			150
Other regulatory assets, deferred	2,792			2,774			1,191			1,157
Other deferred charges and assets	473			417			178			163
Total deferred charges and other assets	3,941			3,867			1,911			1,995
Total Assets	$	35,248		$	34,835		$	23,789		$	22,516

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

~~GEORGIA~~ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


Liabilities and Stockholder's Equity	At March 31, 2017			At December 31, 2016			At September 30, 2017			At December 31, 2016
	(in millions)						(in millions)
Current Liabilities:
Securities due within one year	$	488		$	460		$	325		$	561
Notes payable	—			391
Accounts payable —
Affiliated	347			438			275			297
Other	657			589			376			433
Customer deposits	268			265			92			88
Accrued taxes —
Accrued income taxes	56			17			115			45
Other accrued taxes	115			390			128			42
Accrued interest	115			106			75			78
Accrued compensation	110			224			151			193
Asset retirement obligations, current	305			299
Other regulatory liabilities, current							4			85
Other current liabilities	241			297			50			76
Total current liabilities	2,702			3,476			1,591			1,898
Long-term Debt	11,042			10,225			7,083			6,535
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	6,073			6,000			4,919			4,654
Deferred credits related to income taxes	119			121			60			65
Accumulated deferred investment tax credits	253			256
Accumulated deferred ITCs							118			110
Employee benefit obligations	673			703			289			300
Asset retirement obligations, deferred	2,256			2,233
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	214			199			51			63
Total deferred credits and other liabilities	9,588			9,512			7,724			7,479
Total Liabilities	23,332			23,213			16,398			15,912
Preferred Stock	45			45
Redeemable Preferred Stock							329			85
Preference Stock	221			221			196			196
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — 9,261,500 shares	398			398
Common stock, par value $40 per share —
Authorized — 40,000,000 shares
Outstanding — 30,537,500 shares							1,222			1,222
Paid-in capital	7,238			6,885			2,961			2,613
Retained earnings	4,026			4,086			2,711			2,518
Accumulated other comprehensive loss	(12		)	(13		)	(28		)	(30		)
Total common stockholder's equity	11,650			11,356			6,866			6,323
Total Liabilities and Stockholder's Equity	$	35,248		$	34,835		$	23,789		$	22,516

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

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~~GEORGIA~~ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~FIRST~~THIRD QUARTER 2017 vs. ~~FIRST~~THIRD QUARTER 2016

AND

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

OVERVIEW

~~Georgia~~Alabama Power operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located ~~within~~in the State of ~~Georgia and~~Alabama in addition to wholesale customers in the Southeast.

Many factors affect the opportunities, challenges, and risks of ~~Georgia~~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. ~~Georgia~~Alabama Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms andappropriately balancing required costs and capital expenditures with customer prices will continue to challenge ~~Georgia~~Alabama Power for the foreseeable future.

On March 29, 2017, Westinghouse and WECTEC each filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. Also on March 29, 2017, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the Contractor and WECTEC Staffing Services LLC (WECTEC Staffing) to provide for a continuation of work with respect to Plant Vogtle Units 3 and 4. In February 2017, the Contractor provided Georgia Power with revised forecasted in-service dates of December 2019 and September 2020 for Plant Vogtle Units 3 and 4, respectively. However, based on information subsequently made available during Westinghouse and WECTEC's bankruptcy proceedings and pursuant to the interim assessment agreement, Georgia Power and the Vogtle Owners do not believe the revised in-service dates are achievable. Georgia Power, along with the other Vogtle Owners, is undertaking a comprehensive schedule and cost-to-complete assessment, as well as a cancellation cost assessment. It is reasonably possible these assessments result in estimated incremental costs to complete, including owners' costs, that materially exceed the value of the Toshiba Guarantee. Georgia Power intends to work with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4. Georgia Power, for itself and as agent for the other Vogtle Owners, is also negotiating a new service agreement which would, if necessary, engage the Contractor to provide design, engineering, and procurement services to Southern Nuclear, in the event Southern Nuclear assumes control over construction management. The Contractor's bankruptcy filing 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 Georgia Power's financial statements. In addition, an inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee 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 also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and 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.~~

~~Georgia~~Alabama 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.

RESULTS OF OPERATIONS

Net Income

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

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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~~GEORGIA~~ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~RESULTS OF OPERATIONS~~

~~Net Income~~

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$(9) (3.3)

Georgia Power's net income after dividends on preferred and preference stock for the first quarter 2017 was $260 million compared to $269 million for the corresponding period in 2016. The decrease was primarily due to milder weather as compared to the corresponding period in 2016, partially offset by lower non-fuel operations and maintenance expenses.

~~Retail Revenues~~

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$(28) (1.6)

~~In the first quarter 2017, retail revenues were $1.69 billion compared to $1.72 billion for the corresponding period in 2016.~~

Details of the changes in retail revenues were as follows:


	First Quarter 2017					Third Quarter 2017					Year-to-Date 2017
	(in millions)			(% change)		(in millions)			(% change)		(in millions)				(% change)
Retail – prior year	$	1,717				$	1,629				$	4,139
Estimated change resulting from –
Rates and pricing	26			1.5		85			5.2		240				5.8
Sales decline	(12		)	(0.7	)	(18		)	(1.1	)	(31		)		(0.7	)
Weather	(72		)	(4.2	)	(50		)	(3.1	)	(116		)		(2.8	)
Fuel cost recovery	30			1.8
Fuel and other cost recovery						(51		)	(3.1	)	(77		)		(1.9	)
Retail – current year	$	1,689		(1.6	)%	$	1,595		(2.1	)%	$	4,155		��	0.4	%

Revenues associated with changes in rates and pricing increased in the ~~first~~third quarter and year-to-date 2017 when compared to the corresponding ~~period~~periods in 2016 primarily due to an increase in rates under Rate RSE effective January 1, 2017. See Note 3 to the ~~rate pricing effect~~financial statements of ~~decreased customer usage and higher contributions from commercial and industrial customers~~Alabama Power under ~~a rate plan allowing~~"Retail Regulatory Matters" in Item 8 of the Form 10-K for ~~variable demand-driven pricing.~~additional information.

Revenues attributable to changes in sales decreased in the ~~first~~third quarter and year-to-date 2017 when compared to the corresponding ~~period~~periods in 2016. Weather-adjusted residential KWH sales ~~increased 1.3%, weather-adjusted commercial KWH sales~~ decreased ~~2.5%,~~2.4% and ~~weather-adjusted industrial KWH sales decreased 3.2% in~~1.1% for the ~~first~~third quarter and year-to-date 2017, ~~when compared~~respectively, primarily due to the corresponding period in 2016. An increase of approximately 29,000 residential customers since March 31, 2016 contributed to the increase in weather-adjusted residential KWH sales. A decline in averagelower customer usage resulting from an increase in penetration of energy ~~saving initiatives and electronic commerce transactions contributed to the decrease in weather-adjusted~~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 ~~of approximately 1,400 commercial customers since March 31, 2016. Decreased~~in demand resulting from changes in production levels primarily in the primary metals, chemicals, ~~paper, transportation,~~ and ~~stone, clay, and glass~~mining sectors, ~~was the main contributor to the decrease in weather-adjusted industrial KWH sales,~~ partially offset by ~~increased~~a decrease in demand from the pipeline sector.

Revenues resulting from changes in weather decreased in the ~~lumber~~third quarter and ~~rubber sectors. A strong dollar, low oil prices, weak global economic conditions,~~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 ~~economic policy uncertainty have constrained~~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 ~~industrial sector.~~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

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~~GEORGIA~~ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Fuel~~marginal cost and energy purchases are generally offset by energy revenues ~~and costs are allocated between retail and wholesale jurisdictions. Retail fuel~~through Alabama Power's energy cost recovery clauses.

For year-to-date 2017, wholesale revenues ~~increased $30~~from sales to affiliates were $83 million ~~in the first quarter 2017 when~~ compared to the corresponding period in 2016 primarily due to higher natural gas prices and less available hydro generation, partially offset by lower energy sales resulting from milder weather in the first quarter 2017 as compared to$49 million for the corresponding period in 2016. ~~Electric rates include provisions~~The increase was primarily due to ~~adjust billings for fluctuations~~a 52% increase in ~~fuel costs, including~~KWH sales as a result of supporting Southern Company system transmission reliability and an 11% increase in the price of 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"due to an increase in ~~Item 7 of the Form 10-K for additional information.~~natural gas prices.

Other Revenues

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$(13) (11.9)

In the ~~first~~third quarter 2017, other revenues were ~~$96~~$50 million compared to ~~$109~~$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 ~~$14~~$43 million ~~adjustment for customer temporary facilities services revenues in 2016, partially offset by a $4 million increase in outdoor lighting sales revenues primarily attributable to LED conversions.~~

~~Fuel and Purchased Power Expenses~~

First Quarter 2017
vs.
First Quarter 2016
(change in millions) (% change)
Fuel $ (5 ) (1.3 )
Purchased power – non-affiliates 5
6.0
Purchased power – affiliates 33
23.7
Total fuel and purchased power expenses $ 33

In the first quarter 2017, total fuel and purchased power expenses were $631 million compared to $598 million in the corresponding period in 2016. The increase in the first quarter 2017 was primarily due to a $45 million increase in the average cost of fuel and purchased power primarily related to higher natural gas prices and less rainfall for hydro generation, partially offset by a net decrease ~~of $12 million~~ related to the volume of KWHs generated and purchased ~~due~~and a $16 million decrease related to ~~milder weather as~~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 resulting~~2016. The decrease was primarily due to a $53 million decrease in ~~lower customer demand.~~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 ~~these fuel~~energy expenses are generally offset by ~~fuel~~energy revenues through ~~Georgia~~Alabama Power's ~~fuel~~energy cost recovery ~~mechanism.~~clause. See ~~MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL –~~Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – ~~Fuel Cost Recovery"~~Rate ECR" in Item 78 of the Form 10-K for additional information.

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~~GEORGIA~~ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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


	First Quarter 2017	First Quarter 2016	Third Quarter 2017	Third Quarter 2016	Year-to-Date 2017	Year-to-Date 2016
Total generation (in billions of KWHs)	14	16	16	18	46	46
Total purchased power (in billions of KWHs)	7	6	2	2	5	6
Sources of generation (percent) —
Coal	27	30	52	59	49	51
Nuclear	26	23	24	22	25	24
Gas	45	42	19	18	20	19
Hydro	2	5	5	1	6	6
Cost of fuel, generated (in cents per net KWH) —
Coal	3.26	3.56	2.61	2.73	2.61	2.80
Nuclear	0.85	0.86	0.75	0.77	0.75	0.78
Gas	2.77	2.01	2.72	2.85	2.74	2.62
Average cost of fuel, generated (in cents per net KWH)(a)	2.39	2.22	2.17	2.32	2.15	2.25
Average cost of purchased power (in cents per net KWH)^(*)	4.47	4.32
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 ~~Georgia~~Alabama Power for tolling agreements where power is generated by the provider.

Fuel

In the ~~first~~third quarter 2017, fuel expense was ~~$371~~$343 million compared to ~~$376~~$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 ~~21.1%~~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,~~coal. The decrease was partially offset by a ~~37.8%~~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.~~

~~Purchased Power – Non-Affiliates~~

In the first quarter 2017, purchased power expense from non-affiliates was $88 million compared to $83 million in the corresponding period in 2016. The increase was not material. 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.generated, which excludes fuel associated with tolling agreements.

Purchased Power – Affiliates

In the ~~first~~third quarter 2017, purchased power expense from affiliates was ~~$172~~$55 million compared to ~~$139~~$41 million infor the corresponding period in 2016. The increase was primarily ~~the result of~~related to a ~~13.8%~~55.2% increase in the ~~volume~~amount of ~~KWHs~~energy purchased due to ~~meet customer demand~~an increase in plant outages and increased purchases from Southern Electric Generating Company (SEGCO). The increase was partially offset by a ~~6.8% increase~~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 ~~resulting from~~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.

Table of Contents

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Table of Contents~~

~~GEORGIA POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

Other Operations and Maintenance Expenses

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$(76) (16.6)

In the ~~first~~third quarter 2017, other operations and maintenance expenses were ~~$381~~$391 million compared to ~~$457~~$348 million in the corresponding period in 2016. The decrease is primarily due to cost containment activities implemented in the third quarter 2016, a $19 million increase in gains from sales of integrated transmission system assets, and a $6 million decrease in demand-side management costs related to the timing of new programs. Cost containment activities contributed to decreases of $18 million in employee compensation and benefit costs, $14 million in generation maintenance costs, and $7 million in transmission and distribution overhead line maintenance.

~~Depreciation and Amortization~~

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$10 4.7

In the first quarter 2017, depreciation and amortization was $221 million compared to $211 million in the corresponding period in 2016. The increase was primarily related to additional plant in service.

~~Interest Expense, Net of Amounts Capitalized~~

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$7 7.4

~~In the first quarter 2017, interest expense, net of amounts capitalized was $101 million compared to $94 million in~~for the corresponding period in 2016. The increase was primarily due to ~~a $6~~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

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 ~~interest~~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

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 ~~senior note issuances~~higher pre-tax earnings, unrecognized tax benefits related to certain state deductions for federal income taxes, and ~~additional long-term borrowings from the FFB.~~

~~See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" herein for additional information on borrowings from the FFB.~~prior year tax return actualization.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of ~~Georgia~~Alabama Power's future earnings potential. The level of ~~Georgia~~Alabama Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of ~~Georgia~~Alabama Power's primary business of providing electric service. These factors include ~~Georgia~~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. ~~The impact of the Contractor's bankruptcy on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 is also a major factor.~~ Future earnings will be driven primarily by customer growth. Earnings will also depend upon

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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, and higher multi-family home construction.~~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 ~~Georgia~~Alabama Power's service territory. Demand for electricity is primarily driven by ~~economic growth. The~~the pace of economic growth ~~and electricity demand~~that may be affected by changes in regional and global economic conditions, which may impact future earnings.

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~~GEORGIA POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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~~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 ~~Georgia~~Alabama Power in Item 7 of the Form ~~10-K and RISK FACTORS in Item 1A herein.~~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. 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. 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 ~~Georgia~~Alabama Power in Item 7 and Note 3 to the financial statements of ~~Georgia~~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 ~~Georgia~~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 and~~programs.

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

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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 ~~this matter~~these matters cannot be determined at this time.

FERC Matters

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~~GEORGIA POWER COMPANY~~

See MANAGEMENT'S DISCUSSION AND ANALYSIS OF– 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.

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~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.

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

Retail Regulatory Matters

~~Georgia~~Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the ~~Georgia~~Alabama PSC. ~~Georgia~~Alabama Power currently recovers its costs from the regulated retail business primarily through ~~the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, ECCR tariffs,~~Rate RSE, Rate CNP, Rate ECR, and ~~Municipal Franchise Fee tariffs.~~Rate NDR. In addition, ~~financing costs related~~the Alabama PSC issues accounting orders to ~~the construction of Plant Vogtle Units 3~~address current events impacting Alabama Power. See Notes 1 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~~Alabama Power under "Nuclear Outage Accounting Order" and "Retail Regulatory Matters, ~~– Nuclear Construction"~~" respectively, in Item 8 of the Form 10-K for additional information regarding ~~the NCCR tariff. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery"~~Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in ~~Item 7 of the Form 10-K for additional information regarding fuel cost recovery.~~

~~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 of approximately $50 million incurred through March 31, 2017 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.

~~Nuclear Construction~~

~~See~~ Note 3(B) to the ~~financial statements of Georgia~~Condensed Financial Statements herein.

Other Matters

Alabama Power ~~under "Retail Regulatory Matters – Nuclear Construction"~~is involved in ~~Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3~~various other matters being litigated and ~~4, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, the Vogtle Construction Litigation (as defined below), and the Contractor Settlement Agreement (as defined below).~~

~~Vogtle 3 and 4 Agreement and Contractor Bankruptcy~~

regulatory matters that could affect future earnings. In ~~2008, Georgia~~addition, Alabama Power acting for itself and as agent for the Vogtle Owners, entered into an agreement with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 (Vogtle 3 and 4 Agreement). Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase priceis subject to certain ~~price escalations~~claims 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. The Vogtle 3 and 4 Agreement also provides for liquidated damages uponlegal actions arising in the ~~Contractor's failure to fulfill the schedule and certain performance guarantees, each~~ordinary course of business. Alabama Power's business activities are subject to an aggregate cap of 10% of the contract price, or approximately $920 million. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions with maximum additional capital costs under this provision attributableextensive governmental regulation related to Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%. In the event of a credit rating downgrade below investment grade of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement.

~~On December 31, 2015, Westinghouse~~public health and the ~~Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners~~environment, such as regulation of air emissions and ~~the Contractor under the Vogtle 3~~water discharges. Litigation over environmental issues and ~~4 Agreement,~~claims of various types, including ~~litigation that was pending in~~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. ~~District Court~~This litigation has included claims for ~~the Southern District of Georgia (Vogtle Construction Litigation). Among~~damages alleged to have been caused by CO₂ and other ~~things, the Contractor Settlement Agreement~~emissions, CCR, and ~~the related amendment~~alleged exposure to ~~the Vogtle 3 and 4 Agreement (i) revised the guaranteed substantial completion dates to June 30, 2019~~hazardous materials, and/or requests for Unit 3 and June 30, 2020 for Unit 4; (ii) provided that delay liquidated damages will commence if the nuclear fuel loading date for each unit does not occur by December 31, 2018 for Unit 3 and December 31, 2019 forinjunctive relief in connection with such matters.

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~~Unit 4; and (iii) provided that, pursuant~~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 ~~amendment~~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 ~~Vogtle 3~~Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and ~~4 Agreement, Georgia~~other matters being litigated which may affect future earnings potential.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Alabama Power ~~based on~~prepares its ~~ownership interest, pay~~financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the ~~Contractor and capitalize to the project cost approximately $350 million~~financial statements of Alabama Power in ~~settlement of disputed claims. Further, as a consequence~~Item 8 of the ~~settlement~~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 ~~Westinghouse's acquisition~~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 ~~WECTEC, Westinghouse engaged Fluor Enterprises, Inc. (Fluor Enterprises), a subsidiary~~Critical Accounting Policies and Estimates" of ~~Fluor Corporation (Fluor), as a new construction subcontractor.~~

~~Under the terms~~Alabama Power in Item 7 of the ~~Vogtle 3~~Form 10-K for a complete discussion of Alabama Power's critical accounting policies and ~~4 Agreement, the Contractor does not have a right~~estimates related to ~~terminate the Vogtle 3~~Utility Regulation, Asset Retirement Obligations, Pension and ~~4 Agreement for convenience. The Contractor may terminate the Vogtle 3~~Other Postretirement Benefits, and ~~4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays~~Contingent Obligations.

Recently Issued Accounting Standards

See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of ~~work, action by a governmental authority to permanently stop work, certain breaches~~Alabama Power in Item 7 of the ~~Vogtle 3~~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 ~~4 Agreement by the Vogtle Owners, Vogtle Owner insolvency,~~industry specific guidance for revenue recognition with a five-step model for recognizing and ~~certain other events. In the event of an abandonment of work by the Contractor, the maximum liability~~measuring revenue from contracts with customers. The underlying principle of the ~~Contractor under~~standard is to recognize revenue to depict the ~~Vogtle 3~~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 ~~4 Agreement~~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 increased to 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest). The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for convenience, providedfrom tariff offerings that provide electricity without a defined contractual term, as well as longer-term contractual commitments, including PPAs. Alabama Power expects that the ~~Vogtle Owners~~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 ~~required to pay certain termination costs.~~accounted for and disclosed or presented separately from revenues under ASC 606 on Alabama Power's financial statements, if material. In addition, the ~~Vogtle Owners may terminate~~power and utilities industry continues to evaluate other specific industry issues, including the ~~Vogtle 3~~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 ~~4 Agreement~~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 ~~certain Contractor breaches, including abandonment of work by~~contracts modified before the ~~Contractor.~~

effective date. Under the ~~Toshiba Guarantee, Toshiba has guaranteed certain payment obligations~~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 ~~Contractor,~~adoption of ASC 606, including ~~any liability of~~ the Contractor for abandonment of work. However, due to Toshiba's financial situation described below, substantial risk regarding the Vogtle Owners' ability to fully collect under the Toshiba Guarantee exists. 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 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. In the event of such notice, the Vogtle Owners would be able to draw on the entire balance of the Westinghouse Letters of Credit. The Westinghouse Letters of Credit remain in place in accordance with the terms of the Vogtle 3 and 4 Agreement.

On March 29, 2017, Westinghouse and WECTEC each filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the Contractor and WECTEC Staffing, as of March 29, 2017 (Interim Assessment Agreement), to provide for a continuation of work with respect to Plant Vogtle Units 3 and 4. Georgia Power's entry into the Interim Assessment Agreement was conditioned upon South Carolina Electric & Gas Company entering into a similar interim assessment agreement with the Contractor relating to V.C. Summer, which also occurred on March 29, 2017. The provisions in the Interim Assessment Agreement became effective upon approval of the Interim Assessment Agreement by the bankruptcy court on March 30, 2017. The term of the Interim Assessment Agreement was originally scheduled to expire on April 28, 2017. On April 28, 2017, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an amendment to the Interim Assessment Agreement with the Contractor and WECTEC Staffing solely to extend the term of the Interim Assessment Agreement through the earlier of (i) May 12, 2017 and (ii) termination of the Interim Assessment Agreement by any party upon five business days' notice (Interim Assessment Period).

The Interim Assessment Agreement provides, among other items, that (i) Georgia Power will be obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the Contractor for subcontractors and vendors for services performed or goods provided during the Interim Assessment Period, with these amounts to be paid to the Contractor, except for amounts accrued for Fluor, which will be paid directly to Fluor; (ii) during the Interim Assessment Period, the Contractor shall provide certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extent as contemplated by the Vogtle 3 and 4 Agreement, and Georgia Power, on behalf of the Vogtle Owners, will make payments of $5.4 million per week for these services; (iii) Georgia Power will have the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who have accounts past due with the Contractor; (iv) during the Interim Assessment Period, the Contractor will use its commercially reasonable efforts to provide information reasonably requested by Georgia Power as is necessary to continue construction and investigate the completion status of Plant Vogtle Units 3 and 4; (v) thecumulative-

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~~Contractor will reject or accept the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) during the Interim Assessment Period, Georgia Power will~~effect adjustment, is not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserve all rights and remedies under the Vogtle 3 and 4 Agreement, all related security and collateral, under applicable law.

A number of subcontractors to the Contractor, including Fluor Enterprises, have alleged non-payment by the 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, action to remove liens filed by these subcontractors through the posting of surety bonds.

Georgia Power estimates the aggregate liability for the Vogtle Owners under the Interim Assessment Agreement and the removal of subcontractor liens to be approximately $470 million, of which Georgia Power's proportionate share would total approximately $215 million. As of March 31, 2017, $245 million of this aggregate liability had been paid or accrued. Georgia Power is evaluating remedies available to the Vogtle Owners for these payments, including draws under the Westinghouse Letters of Credit and enforcement of the Toshiba Guarantee.

In February 2017, the Contractor provided Georgia Power with revised forecasted in-service dates of December 2019 and September 2020 for Plant Vogtle Units 3 and 4, respectively. However, based on information subsequently made available during Westinghouse and WECTEC's bankruptcy proceedings and pursuant to the Interim Assessment Agreement, Georgia Power and the Vogtle Owners do not believe the revised in-service dates are achievable. Georgia Power, along with the other Vogtle Owners, is undertaking a comprehensive schedule and cost-to-complete assessment, as well as a cancellation cost assessment. It is reasonably possible these assessments result in estimated incremental costs to complete, including owners' costs, that materially exceed the value of the Toshiba Guarantee. Georgia Power intends to work with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4. Georgia Power, for itself and as agent for the other Vogtle Owners, is also negotiating a new service agreement which would, if necessary, engage the Contractor to provide design, engineering, and procurement services to Southern Nuclear, in the event Southern Nuclear assumes control over construction management. In addition, Georgia Power, on behalf of itself and the other Vogtle Owners, intends to take all actions available to it to enforce its rights related to the Vogtle 3 and 4 Agreement, including enforcing the Toshiba Guarantee, subject to the Interim Assessment Agreement, and accessing the Westinghouse Letters of Credit.

On April 11, 2017, Toshiba filed its unaudited financial statements as of and for the nine months ended December 31, 2016, which reflected a negative shareholders' equity balance of $1.9 billion, with Japanese regulators. Toshiba also announced that further substantial charges may be required in the quarter ended March 31, 2017 in connection with the bankruptcy filing of Westinghouse and WECTEC and that there are material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern.

~~The Contractor's bankruptcy filing is~~ expected to have a material impact on either the ~~construction cost and schedule~~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 ~~recovery~~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 ~~Plant Vogtle Units 3~~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 4the other components of net periodic pension and ~~could~~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 ~~Georgia~~Alabama Power's financial statements. ~~In addition, an inability or other failure by Toshiba~~

On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to ~~perform its obligations under~~Accounting for Hedging Activities (ASU 2017-12), amending the ~~Toshiba Guarantee could~~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 ~~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~~Alabama Power's financial statements.

~~The ultimate outcome~~

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of ~~these matters also is dependent on the results~~Alabama Power in Item 7 of the ~~assessments currently underway,~~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.

~~Regulatory Matters~~

~~In 2009,~~steam generation. Net cash provided from financing activities totaled $339 million for the ~~Georgia PSC voted~~first nine months of 2017 primarily due to ~~certify construction~~an issuance of ~~Plant Vogtle Units 3~~long-term debt and ~~4 with~~preferred stock and additional capital contributions from Southern Company, partially offset by common stock dividend payments and a ~~certified~~redemption of long-term debt. Fluctuations in cash flows from financing activities vary from period to period based on 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,~~needs and the ~~State~~maturity or redemption of ~~Georgia enacted~~securities.

Significant balance sheet changes for the ~~Georgia Nuclear Energy Financing Act, which allows Georgia Power~~first nine months of 2017 include increases of $652 million in property, plant, and equipment primarily due 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~~additions to distribution, transmission, and steam generation, $548 million in long-term debt primarily due to the ~~NCCR tariff by including the related CWIP accounts~~issuance of additional senior notes, $533 million in ~~rate base during the construction period.~~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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~~On December 20, 2016,~~accumulated deferred income taxes primarily due to bonus depreciation, and $244 million in redeemable preferred stock primarily due to the ~~Georgia PSC voted to approve~~September 2017 issuance, as well as a ~~settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none~~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 ~~$3.3~~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.

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, ~~incurred~~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 ~~December 31, 2015~~Rate CNP Compliance.

Sources of Capital

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ALABAMA POWER COMPANY

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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

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 ~~basis~~payment of ~~imprudence; (ii) the Contractor Settlement Agreement is reasonable and prudent and none~~which was then accelerated. At September 30, 2017, Alabama Power was in compliance with all such covenants. None of the ~~amounts paid~~bank credit arrangements contain material adverse change clauses at the time of borrowings.

A portion of the unused credit with banks is allocated to provide liquidity support to 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 ~~paid pursuant~~reoffered within the next 12 months.

Alabama Power also has substantial cash flow from operating activities and access to ~~the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified~~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 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,sell commercial paper at the ~~Georgia PSC's discretion, be accrued to be used~~request and for the benefit of ~~customers, until~~Alabama Power and the other traditional electric operating companies. Proceeds from such ~~time~~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.

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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 ~~units~~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 ~~placed~~certain contracts that could require collateral, but not accelerated payment, in ~~service~~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 ~~(ii)~~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 ~~ROE~~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 ~~calculate AFUDC will be Georgia~~repay Alabama Power's ~~average cost~~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 ~~long-term debt.~~

~~Under the terms~~Series 1993-A, 1993-B, and 1993-C Industrial Development Board of the ~~Vogtle Cost Settlement Agreement, Plant Vogtle Units 3~~City of Mobile, Alabama Pollution Control Revenue Refunding Bonds (Alabama Power Company Project).

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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 ~~4 will~~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 ~~placed into retail rate base on December 31, 2020 or~~necessary to meet capital requirements and contractual obligations, Alabama Power plans to continue, when ~~placed in service, whichever is later. The Georgia PSC will determine for retail ratemaking purposes the process of transitioning Plant Vogtle Units 3~~economically feasible, a program to retire higher-cost securities and ~~4 from a construction project to an operating plant no later than Georgia Power's base rate case required to be filed by July 1, 2019.~~replace these obligations with lower-cost capital if market conditions permit.

The Georgia PSC has approved fifteen VCM reports covering the periods through June 30, 2016, including construction capital costs incurred, which through that date totaled $3.7 billion. Georgia Power filed its sixteenth VCM report, covering the period from July 1 through December 31, 2016, requesting approval of $222 million of construction capital costs incurred during that period, with the Georgia PSC on February 27, 2017. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $4.1 billion as of March 31, 2017 and Georgia Power had incurred $1.3 billion in financing costs through March 31, 2017.

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

Other Matters

As of ~~March 31,~~September 30, 2017, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through ~~a loan guarantee agreement between Georgia Power and~~ the ~~DOE~~Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the ~~FFB.~~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~~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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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Table of Contents~~

~~GEORGIA POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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

See RISK FACTORS of ~~Georgia Power~~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

Bonus Depreciation

Section 174 Research and Experimental Deduction

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Power

Other Matters

~~Georgia Power is~~Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, ~~Georgia Power is~~Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. ~~Georgia Power's~~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 Georgia Power~~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~~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 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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

~~Georgia Power~~Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of ~~Georgia Power~~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 ~~Georgia Power's~~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 ~~Georgia Power~~Southern Company in Item 7 of the Form 10-K for a complete discussion of ~~Georgia Power's~~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

7544

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~~GEORGIA POWER~~SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

While ~~Georgia Power~~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 ~~Georgia Power's~~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. For such arrangements, Georgia Power~~term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements. Southern Company expects ~~that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and~~ the adoption of ASC 606 will not result in a significant shift infrom the current timing of revenue recognition for such ~~sales.~~transactions.

~~Georgia Power's~~Southern Company's ongoing evaluation of other revenue streams and related contracts includes ~~longer term contractual commitments and~~ 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 ~~Georgia Power's~~Southern Company's financial statements. In addition, the power and utilities industry ~~is currently addressing~~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~~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. ~~Georgia Power must select~~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 ~~transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect~~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 ~~date~~adoption of ~~initial adoption. As~~ASC 606, including the ~~ultimate~~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, ~~has~~the goodwill impairment loss will be measured as the excess of a reporting unit's carrying amount over its fair value, not ~~yet been determined, Georgia Power has~~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 ~~elected its transition method.~~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~~(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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

Capital Requirements and Contractual Obligations

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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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS



	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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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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

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.

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 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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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

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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.

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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

PART I

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Item 4. Controls and Procedures.


(a)	Evaluation of disclosure controls and procedures.


(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.

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.

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.

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.

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.

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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

RESULTS OF OPERATIONS

Net Income

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:



	Third Quarter 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

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

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

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

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

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

Sources of Capital

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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

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.

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.

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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.

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

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.

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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.

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.

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.

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.

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.

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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

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

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.

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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

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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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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

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

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

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

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.

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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 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

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

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 ~~currently evaluating~~accruing $30 million annually 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.

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

Regulatory Matters

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.

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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 ~~standard.~~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.



	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.

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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 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 ~~March 31,~~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

~~Table of Contents~~

~~GEORGIA POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

"Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled ~~$111 million~~$1.48 billion for the first ~~three~~nine months of 2017 compared to ~~$566 million~~$2.27 billion for the corresponding period in 2016. The decrease was primarily due to the timing of vendor ~~payments.~~payments and fossil fuel stock purchases and an increase in under-recovered fuel costs. Net cash used for investing activities totaled ~~$566 million~~$1.83 billion for the first ~~three~~nine months of 2017 compared to ~~$689 million~~$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 ~~$473~~$617 million for the first ~~three~~nine months of 2017 compared to ~~$116~~$528 million used for financing activities in the

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 ~~higher capital contributions received from Southern Company,~~and junior subordinated notes, and a ~~maturity~~decrease in maturities of senior notes, ~~in 2016,~~ partially offset by a ~~reduction~~decrease in borrowings from the FFB for construction of Plant Vogtle Units 3 and 4 and an increase in redemptions of short-term ~~debt.~~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 ~~three~~nine months of 2017 include ~~an increase~~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 ~~of $845 million~~primarily due to issuances of senior notes ~~a decrease~~and junior subordinated notes, $423 million in ~~notes~~accounts payable, ~~of $391 million~~other primarily due to ~~changes in short-term liquidity needs, an increase~~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 ~~of $353 million~~ primarily due to capital contributions received from Southern ~~Company,~~Company. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Storm Damage Recovery" and ~~an increase in property, plant,~~" – Nuclear Construction" for additional information regarding Hurricane Irma and ~~equipment of $337 million to comply with environmental standards and construction of generation, transmission, and distribution facilities.~~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 ~~$488~~$261 million will be required through ~~March 31,~~September 30, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information. Also see FUTURE EARNINGS POTENTIAL – ~~"Retail~~"Retail Regulatory Matters – Nuclear ~~Construction"~~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.~~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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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Georgia Power has entered into a loan guarantee agreement (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)~~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. ~~Eligible Project Costs incurred through March 31,~~As of September 30, 2017, ~~would allow for borrowings of up to $2.8~~Georgia Power had borrowed $2.6 billion under the FFB Credit ~~Facility, of which~~Facility. On July 27, 2017, Georgia Power ~~has borrowed $2.6 billion. The Contractor's bankruptcy and failure~~entered into an amendment to ~~perform its obligations under~~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 ~~could impact~~and satisfaction of certain other conditions.

On September 28, 2017, the DOE issued a conditional commitment to Georgia ~~Power's ability~~Power for up to ~~make further borrowings~~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 ~~March 31,~~September 30, 2017, Georgia Power's current liabilities exceeded current assets by ~~$721~~$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 ~~March 31,~~September 30, 2017, Georgia Power had approximately ~~$21~~$266 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks at ~~March 31,~~September 30, 2017 was $1.75 billion of which $1.73 billion was unused. ~~This~~In May 2017, Georgia Power amended its multi-year credit arrangement, ~~expires in 2020.~~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~~cross-acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such ~~cross acceleration~~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 ~~March 31,~~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 ~~March 31,~~September 30, 2017 was approximately $550 million as compared to $868 ~~million.~~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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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

credit arrangement. In addition, at ~~March 31,~~September 30, 2017, Georgia Power had ~~$250~~$509 million of ~~fixed rate~~ pollution control revenue bonds outstanding that were required to be ~~reoffered~~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.

~~Table of Contents~~

~~GEORGIA POWER COMPANY~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

Details of short-term borrowings were as follows:

Short-term Debt During the Period ^(*)
Average Amount Outstanding Weighted Average Interest Rate
Maximum
Amount
Outstanding
(in millions) (in millions)
Commercial paper $ 152
1.0 % $ 415



	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 ~~March 31, 2017. No short-term debt was outstanding at March 31,~~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 ~~March 31,~~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, ~~transmission,~~ and ~~construction of new generation at Plant Vogtle Units 3 and 4.~~transmission.

The maximum potential collateral requirements under these contracts at ~~March 31,~~September 30, 2017 were as follows:


Credit Ratings	Maximum Potential Collateral Requirements		Maximum Potential Collateral Requirements
	(in millions)		(in millions)
At BBB- and/or Baa3	$	87	$	87
Below BBB- and/or Baa3	$	1,224	$	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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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

~~Subsequent to March 31,~~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 ~~may reoffer~~remarketed these bonds to the ~~public~~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 ~~later date.~~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.

~~Table~~Also in August 2017, Georgia Power issued $500 million aggregate principal amount of ~~Contents~~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.

~~GEORGIA POWER COMPANY~~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.

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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.

GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months Ended March 31,						For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016			2017			2016
	(in millions)						(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	279		$	283		$	375		$	377		$	972		$	978
Wholesale revenues, non-affiliates	17			16			14			17			44			48
Wholesale revenues, affiliates	37			21			28			23			75			59
Other revenues	17			15			20			19			53			51
Total operating revenues	350			335			437			436			1,144			1,136
Operating Expenses:
Fuel	108			94			127			141			323			342
Purchased power, non-affiliates	32			30			37			33			104			95
Purchased power, affiliates	2			2			2			3			13			9
Other operations and maintenance	84			77			81			86			252			239
Depreciation and amortization	18			38			42			49			95			129
Taxes other than income taxes	27			29			33			34			88			93
Loss on Plant Scherer Unit 3	33			—			—			—			33			—
Total operating expenses	304			270			322			346			908			907
Operating Income	46			65			115			90			236			229
Other Income and (Expense):
Interest expense, net of amounts capitalized	(12		)	(13		)	(13		)	(11		)	(37		)	(36		)
Other income (expense), net	—			(1		)	1			(2		)	—			(4		)
Total other income and (expense)	(12		)	(14		)	(12		)	(13		)	(37		)	(40		)
Earnings Before Income Taxes	34			51			103			77			199			189
Income taxes	14			20			40			30			78			74
Net Income	20			31			63			47			121			115
Dividends on Preference Stock	2			2			—			2			4			7
Net Income After Dividends on Preference Stock	$	18		$	29		$	63		$	45		$	117		$	108

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months Ended March 31,						For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2017			2016			2017		2016		2017			2016
	(in millions)						(in millions)				(in millions)
Net Income	$	20		$	31		$	63	$	47	$	121		$	115
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $- and $(2), respectively	(1		)	(3		)
Changes in fair value, net of tax of $-, $-, $(1), and $(3), respectively							—		—		(1		)	(4		)
Total other comprehensive income (loss)	(1		)	(3		)	—		—		(1		)	(4		)
Comprehensive Income	$	19		$	28		$	63	$	47	$	120		$	111

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

GULF POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Three Months Ended March 31,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Operating Activities:
Net income	$	20		$	31		$	121		$	115
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	20			40			100			134
Deferred income taxes	5			9			57			15
Loss on Plant Scherer Unit 3	33			—			33			—
Other, net	(2		)	(1		)	(5		)	(2		)
Changes in certain current assets and liabilities —
-Receivables	(1		)	35			(65		)	(9		)
-Fossil fuel stock	12			15			7			49
-Other current assets	6			2			11			3
-Accrued taxes	(4		)	13			21			40
-Accrued compensation	(23		)	(18		)	(10		)	(5		)
-Over recovered regulatory clause revenues	(18		)	1			(8		)	26
-Other current liabilities	2			5			10			8
Net cash provided from operating activities	50			132			272			374
Investing Activities:
Property additions	(46		)	(32		)	(142		)	(106		)
Cost of removal, net of salvage	(2		)	(2		)	(16		)	(8		)
Change in construction payables	(7		)	(6		)	(9		)	(7		)
Other investing activities	(2		)	(2		)	(6		)	(6		)
Net cash used for investing activities	(57		)	(42		)	(173		)	(127		)
Financing Activities:
Decrease in notes payable, net	(168		)	(85		)	(268		)	(42		)
Proceeds —
Common stock issued to parent	175			—			175			—
Capital contributions from parent company	4			1			7			10
Senior notes							300			—
Redemptions —
Preference stock							(150		)	—
Senior notes							(85		)	(125		)
Payment of common stock dividends	(31		)	(30		)	(94		)	(90		)
Other financing activities	3			(2		)	(3		)	(5		)
Net cash used for financing activities	(17		)	(116		)	(118		)	(252		)
Net Change in Cash and Cash Equivalents	(24		)	(26		)	(19		)	(5		)
Cash and Cash Equivalents at Beginning of Period	56			74			56			74
Cash and Cash Equivalents at End of Period	$	32		$	48		$	37		$	69
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Cash paid during the period for —
Interest (net of $- and $- capitalized for 2017 and 2016, respectively)	$	2		$	3		$	24		$	29
Income taxes, net	—			(25		)	19			14
Noncash transactions — Accrued property additions at end of period	26			15			25			13

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

GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


Assets	At March 31, 2017			At December 31, 2016			At September 30, 2017			At December 31, 2016
	(in millions)						(in millions)
Current Assets:
Cash and cash equivalents	$	32		$	56		$	37		$	56
Receivables —
Customer accounts receivable	58			72			96			72
Unbilled revenues	52			55			68			55
Under recovered regulatory clause revenues	47			17			15			17
Income taxes receivable, current							15			—
Other accounts and notes receivable	9			6			12			6
Affiliated	28			17			13			17
Accumulated provision for uncollectible accounts	(1		)	(1		)	(1		)	(1		)
Fossil fuel stock	59			71			64			71
Materials and supplies	56			55			58			55
Other regulatory assets, current	50			44			55			44
Other current assets	22			30			15			30
Total current assets	412			422			447			422
Property, Plant, and Equipment:
In service	5,110			5,140			5,181			5,140
Less: Accumulated provision for depreciation	1,401			1,382			1,457			1,382
Plant in service, net of depreciation	3,709			3,758			3,724			3,758
Construction work in progress	67			51			75			51
Total property, plant, and equipment	3,776			3,809			3,799			3,809
Deferred Charges and Other Assets:
Deferred charges related to income taxes	57			58			56			58
Other regulatory assets, deferred	501			512			499			512
Other deferred charges and assets	21			21			22			21
Total deferred charges and other assets	579			591			577			591
Total Assets	$	4,767		$	4,822		$	4,823		$	4,822

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

GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


Liabilities and Stockholder's Equity	At March 31, 2017		At December 31, 2016		At September 30, 2017			At December 31, 2016
	(in millions)				(in millions)
Current Liabilities:
Securities due within one year	$	92	$	87	$	7		$	87
Notes payable	100		268		—			268
Accounts payable —
Affiliated	47		59		46			59
Other	47		54		55			54
Customer deposits	35		35		35			35
Accrued taxes	16		20		41			20
Accrued interest	18		8		20			8
Accrued compensation	17		40		30			40
Deferred capacity expense, current	22		22		22			22
Asset retirement obligations, current	32		16
Other regulatory liabilities, current	5		16		1			16
Other current liabilities	30		24		37			40
Total current liabilities	461		649		294			649
Long-term Debt	987		987		1,285			987
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	952		948		1,003			948
Employee benefit obligations	94		96		90			96
Deferred capacity expense	114		119		103			119
Asset retirement obligations	106		120
Asset retirement obligations, deferred					125			120
Other cost of removal obligations	226		249		218			249
Other regulatory liabilities, deferred	48		47		45			47
Other deferred credits and liabilities	78		71		71			71
Total deferred credits and other liabilities	1,618		1,650		1,655			1,650
Total Liabilities	3,066		3,286		3,234			3,286
Preference Stock	147		147		—			147
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — March 31, 2017: 7,392,717 shares
Outstanding — September 30, 2017: 7,392,717 shares
— December 31, 2016: 5,642,717 shares	678		503		678			503
Paid-in capital	594		589		600			589
Retained earnings	282		296		312			296
Accumulated other comprehensive income	—		1
Accumulated other comprehensive income (loss)					(1		)	1
Total common stockholder's equity	1,554		1,389		1,589			1,389
Total Liabilities and Stockholder's Equity	$	4,767	$	4,822	$	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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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~FIRST~~THIRD QUARTER 2017 vs. ~~FIRST~~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 ~~of the~~ intervenors ~~to Gulf Power's retail base rate case,~~ with respect to Gulf Power's request to increase retail base rates. ~~Under~~Among the terms of the 2017 Rate Case Settlement Agreement, Gulf Power ~~will, among other things, increase~~increased rates effective with the first billing cycle in July 1, 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact ~~consists~~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, which is estimated to be approximately $7.7 million for 2017.~~clause. In addition, Gulf Power ~~also will (1) continue~~continued its ~~current~~ authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%)~~; (2) be~~, is deemed to have an equity ratio of 52.5% for all retail regulatory ~~purposes; (3)~~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;~~2018 and ~~(4)~~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

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$(11) (37.9)

Gulf Power's net income after dividends on preference stock for the ~~first~~third quarter 2017 was ~~$18~~$63 million compared to ~~$29~~$45 million for the corresponding period in 2016. The ~~decrease~~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 ~~partially offset by a decrease in depreciation.~~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.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

Retail Revenues

First Quarter 2017 vs. First Quarter 2016

Third Quarter 2017 vs. Third Quarter 2016

Year-to-Date 2017 vs. Year-to-Date 2016

(change in millions)

(% change)

(change in millions)

(% change)

$~~(4)~~(2)

(1.4)

(0.5)

$(6)

(0.6)

In the ~~first~~third quarter 2017, retail revenues were ~~$279~~$375 million compared to ~~$283~~$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:


	First Quarter 2017					Third Quarter 2017					Year-to-Date 2017
	(in millions)			(% change)		(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	283				$	377				$	978
Estimated change resulting from –
Rates and pricing	1			0.4		21			5.6		28			2.9
Sales decline	(2		)	(0.7	)
Sales growth						3			0.8		1			0.1
Weather	(5		)	(1.8	)	(9		)	(2.4	)	(14		)	(1.4	)
Fuel and other cost recovery	2			0.7		(17		)	(4.5	)	(21		)	(2.2	)
Retail – current year	$	279		(1.4	)%	$	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 ~~first~~third quarter and year-to-date 2017 when compared to the corresponding ~~period~~periods in 2016 primarily due to an increase in ~~the~~retail base revenues effective July 2017, as well as an increase in environmental cost recovery ~~clause~~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 ~~decreased~~increased slightly in the ~~first~~third quarter and year-to-date 2017 when compared to the corresponding ~~period~~periods in 2016. For the ~~first~~third quarter 2017, weather-adjusted KWH sales to residential and commercial customers ~~decreased~~increased 5.2% and 1.5% ~~and 0.7%~~, ~~respectively,~~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, ~~partially~~mostly offset by customer growth. KWH sales to industrial customers decreased ~~8.8%~~7.1% and 6.1% for the ~~first~~third quarter and year-to-date 2017, respectively, primarily due to ~~increased customer co-generation.~~changes in customers' operations and energy efficiency improvements.

Fuel and other cost recovery revenues ~~increased~~decreased in the ~~first~~third quarter and year-to-date 2017 when compared to the corresponding ~~period~~periods in 2016, primarily due to ~~higher~~lower fuel, purchased power capacity, and energy conservation recoverable costs, ~~under Gulf Power's environmental cost recovery clause,~~ partially offset by ~~lower~~higher environmental recoverable ~~costs under Gulf Power's fuel cost recovery and purchased power capacity cost recovery clauses.~~costs. Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and the difference between projected and actual costs and revenues related to energy conservation and environmental compliance. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.

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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

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

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$16 76.2

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

In the ~~first~~third quarter 2017, wholesale revenues from sales to affiliates were ~~$37~~$28 million compared to ~~$21~~$23 million for the corresponding period in 2016. The increase was primarily due to a ~~55.4%~~24.1% increase in KWH sales resulting from ~~increased~~outages of affiliate generation ~~as a result of system reliability requirements.~~resources.

~~Fuel and Purchased Power Expenses~~

First Quarter 2017
vs.
First Quarter 2016
(change in millions) (% change)
Fuel $ 14
14.9
Purchased power – non-affiliates 2
6.7
Total fuel and purchased power expenses $ 16

~~In the first quarter~~For year-to-date 2017, ~~total fuel and purchased power expenses~~wholesale revenues from sales to affiliates were ~~$142~~$75 million compared to ~~$126~~$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 ~~$10~~$7 million net ~~increase~~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 ~~higher generation from Gulf Power's coal-fired units~~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 $6$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 ~~due~~related to the higher average cost of fuel and purchased ~~power for Gulf Power's gas-fired PPA resource.~~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.

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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


	First Quarter 2017	First Quarter 2016	Third Quarter 2017	Third Quarter 2016	Year-to-Date 2017	Year-to-Date 2016
Total generation (in millions of KWHs)	2,322	1,816	2,780	2,775	7,000	6,654
Total purchased power (in millions of KWHs)	1,459	1,760	1,686	1,906	4,362	5,295
Sources of generation (percent) –
Coal	53	42	59	68	55	57
Gas	47	58	41	32	45	43
Cost of fuel, generated (in cents per net KWH) –
Coal	3.27	3.92	3.04	3.55	3.15	3.80
Gas	3.24	3.75	3.71	4.38	3.60	4.06
Average cost of fuel, generated (in cents per net KWH)	3.26	3.82	3.31	3.81	3.35	3.91
Average cost of purchased power (in cents per net KWH)^(*)	4.57	3.22	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 ~~first~~third quarter 2017, fuel expense was ~~$108~~$127 million compared to ~~$94~~$141 million for the corresponding period in 2016. The ~~increase~~decrease was primarily due to a ~~60.9% increase in the volume of KWHs generated by Gulf Power's coal-fired generation resources due to system reliability requirements, partially offset by a 14.7%~~13.1% decrease in the average cost of fuel resulting from lower coal and natural gas ~~prices.~~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 ~~first~~third quarter 2017, purchased power expense from non-affiliates was ~~$32~~$37 million compared to ~~$30~~$33 million for the corresponding period in 2016. ~~The increase~~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 ~~a 39.0% increase~~increases of 16.3% and 35.9% for the third quarter and year-to-date 2017, respectively, in the average cost per KWH purchased, ~~primarily resulting from higher fuel costs associated with external purchases,~~ partially offset by ~~a 14.8% decrease~~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 ~~increased Gulf Power generation.~~lower territorial load.

~~Other Operations and Maintenance Expenses~~

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$7 9.1
Purchased Power – Affiliates

In the ~~first~~third quarter 2017, ~~other operations and maintenance expenses were $84~~purchased power expense from affiliates was $2 million compared to ~~$77~~$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.

Other Operations and Maintenance Expenses

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 ~~generating~~generation facilities associated with ~~environmental compliance and~~ routine and planned maintenance.

~~Environmental compliance expenses did not have a significant impact on earnings since they were offset by environmental revenues through~~See Note (A) to the Condensed Financial Statements under "Property Damage Reserve" herein for additional information regarding Gulf Power's ~~environmental cost recovery clause. See~~property damage reserve accrual suspension and Note 3(B) to the ~~financial statements of~~ Condensed Financial Statements under "Regulatory Matters – Gulf Power ~~under "Retail Regulatory Matters~~ – ~~Cost Recovery Clauses – Environmental Cost Recovery" in Item 8 of the Form 10-K~~Retail Base Rate Cases" herein for additional ~~information.~~information regarding the 2017 Rate Case Settlement Agreement.

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Depreciation and Amortization

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$(20) (52.6)

In the ~~first~~third quarter 2017, depreciation and amortization was ~~$18~~$42 million compared to ~~$38~~$49 million for the corresponding period in 2016. ~~The decrease~~For year-to-date 2017, depreciation and amortization was ~~primarily due~~$95 million compared to ~~$20~~$129 million ~~more of a reduction in depreciation in the first quarter 2017 compared to~~for the corresponding period in ~~2016,~~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

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$(6) (30.0)

In the ~~first~~third quarter 2017,, income taxes were ~~$14~~$40 million compared to ~~$20~~$30 million for the corresponding period in 2016. ~~This change was~~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 the income tax benefit associated with the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with the 2017 Rate Case Settlement Agreement. This decrease was partially offset by higher pre-tax ~~earnings, excluding~~earnings.

Dividends on Preference Stock

N/M - Not meaningful

In the ~~write-down.~~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 ~~Note (B) to the Condensed Financial Statements under~~FINANCIAL CONDITION AND LIQUIDITY – "~~Regulatory Matters~~ – ~~Gulf Power~~ – ~~Retail Base Rate Cases~~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 ~~economic growth. The~~the pace of economic growth ~~and electricity demand~~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

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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 and~~programs.

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.

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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 ~~matter~~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.

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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 ~~may~~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. ~~In the first quarter~~Through June 2017, Gulf Power recognized the remaining allowable reductions in depreciation totaling ~~$25.5~~$34.0 million. ~~The 2013 Rate Case Settlement Agreement remains in effect through June 30, 2017.~~

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certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery ~~clause, which is estimated to be approximately $7.7 million for 2017.~~clause. In addition, Gulf Power ~~also will (1) continue~~continued its ~~current~~ authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%)~~; (2) be~~, is deemed to have an equity ratio of 52.5% for all retail regulatory ~~purposes; (3)~~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;~~2018 and ~~(4)~~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.

Theultimateoutcomeofsuchpendingorpotentiallitigation~~againstGulf Power~~ or regulatory matters cannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementsherein,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would

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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.

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. For such arrangements,~~term, as well as longer-term contractual commitments, including PPAs. Gulf Power expects that the revenue from contracts with these customers ~~will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606~~ 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 ~~longer term contractual commitments and~~ unregulated sales to customers. Some revenue arrangements ~~such as certain PPAs 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 Gulf Power's financial ~~statements.~~statements, if material. In addition, the power and utilities industry ~~is currently addressing~~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 ~~must select~~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 ~~transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect~~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 ~~date~~adoption of ~~initial adoption. As~~ASC 606, including the ~~ultimate~~cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of ~~the new standard has not yet been determined,~~revenues recognized in Gulf Power's financial statements, Gulf Power ~~has not elected its transition method.~~will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.

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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

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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. ~~Gulf Power is currently evaluating the new standard.~~ 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 ~~March 31,~~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 ~~$50~~$272 million for the first ~~three~~nine months of 2017 compared to ~~$132~~$374 million for the corresponding period in 2016. The ~~$82~~$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, as well as decreases in cash flows associated with accrued taxes, cost recovery clauses as a result of decreased revenue collection, and changes in accounts receivable in 2017 compared to~~ 2016. Net cash used for investing activities totaled ~~$57~~$173 million in the first ~~three~~nine months of 2017 primarily due to property additions to utility plant. Net cash used for financing activities totaled ~~$17~~$118 million for the first ~~three~~nine months of 2017 primarily due to ~~a decrease in notes payable and~~ the payment of short-term debt, redemptions of preference stock and long-term debt, and common stock ~~dividends,~~dividend payments, partially offset by proceeds from ~~the issuance~~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 ~~three~~nine months of 2017 primarily reflect the financing activities described above. Other significant changes include an increase in ~~common stock of $175 million, a decrease in notes payable of $168 million, primarily funded with the common stock issuance,~~accumulated deferred income taxes due to accelerated depreciation and repair deductions and a decrease in ~~property, plant,~~other cost of removal obligations, as authorized in the 2013 Rate Case Settlement Agreement. See "Financing Activities" herein and ~~equipment primarily due to the write-down of Gulf Power's ownership of Plant Scherer Unit 3. See~~ 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, ~~preference stock dividends,~~ purchase commitments, and trust funding requirements. Approximately ~~$92~~$7 million will be required through ~~March 31,~~September 30, 2018 to fund maturities of long-term debt. See "Financing Activities" herein for additional information.

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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 ~~March 31,~~September 30, 2017, Gulf Power had approximately ~~$32~~$37 million of cash and cash equivalents. Committed credit arrangements with banks at ~~March 31,~~September 30, 2017 were as follows:


Expires	Expires							Executable Term Loans				Expires Within One Year				Expires											Executable Term Loans				Expires Within One Year
2017	2017	2018		Total		Unused		One Year		Two Years		Term Out		No Term Out		2017	2018		2019		2020		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)
$	85	$	195	$	280	$	280	$	45	$	—	$	25	$	70	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~~cross-acceleration provisions to other indebtedness (including guarantee obligations) of Gulf Power. Such ~~cross acceleration~~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 ~~March 31,~~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 ~~March 31,~~September 30, 2017 was approximately $82 million. In addition, at ~~March 31,~~September 30, 2017, Gulf Power had approximately ~~$86~~$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.

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Details of short-term borrowings were as follows:

Short-term Debt at
March 31, 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 $ —
— % $ 29
1.1 % $ 168
Short-term bank debt 100
1.7 % 100
1.5 % 100
Total $ 100
1.7 % $ 129
1.4 %



	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 ~~March 31,~~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 ~~March 31,~~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, ~~transmission,~~ and energy price risk management.

The maximum potential collateral requirements under these contracts at ~~March 31,~~September 30, 2017 were as follows:


Credit Ratings	Maximum Potential Collateral Requirements		Maximum Potential Collateral Requirements
	(in millions)		(in millions)
At BBB- and/or Baa3	$	167	$	167
Below BBB- and/or Baa3	$	564	$	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 ~~first~~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 ~~had been~~is limited because its long-term sales ~~agreements shifted~~agreement shifts substantially all fuel cost responsibility to the purchaser. ~~However, Gulf Power is exposed to market volatility in energy-related commodity prices to the extent any wholesale generating capacity is uncontracted.~~

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

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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 ~~resolves~~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 ~~through~~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 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. ~~In particular, Gulf Power may, subject to applicable market conditions, call for redemption and refinance all or a portion of its $150 million aggregate outstanding preference stock during 2017.~~

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months Ended March 31,						For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016			2017			2016
	(in millions)						(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	200		$	183		$	243		$	263		$	665		$	652
Wholesale revenues, non-affiliates	62			60			72			78			196			198
Wholesale revenues, affiliates	5			9			21			7			40			23
Other revenues	5			5			5			4			14			12
Total operating revenues	272			257			341			352			915			885
Operating Expenses:
Fuel	78			76			120			112			301			268
Purchased power, non-affiliates	1			—			4			3			7			4
Purchased power, affiliates	7			5			2			5			13			14
Other operations and maintenance	74			69			66			74			206			211
Depreciation and amortization	40			38			39			30			120			114
Taxes other than income taxes	26			26			25			31			77			81
Estimated loss on Kemper IGCC	108			53			34			88			3,155			222
Total operating expenses	334			267			290			343			3,879			914
Operating Loss	(62		)	(10		)
Operating Income (Loss)							51			9			(2,964		)	(29		)
Other Income and (Expense):
Allowance for equity funds used during construction	35			29			1			31			72			90
Interest expense, net of amounts capitalized	(19		)	(16		)	13			(15		)	(23		)	(46		)
Other income (expense), net	(1		)	(2		)	(1		)	(1		)	(3		)	(4		)
Total other income and (expense)	15			11			13			15			46			40
Earnings (Loss) Before Income Taxes	(47		)	1			64			24			(2,918		)	11
Income taxes (benefit)	(27		)	(10		)	24			(2		)	(885		)	(29		)
Net Income (Loss)	(20		)	11			40			26			(2,033		)	40
Dividends on Preferred Stock	—			—			—			—			1			1
Net Income (Loss) After Dividends on Preferred Stock	$	(20	)	$	11		$	40		$	26		$	(2,034	)	$	39

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months Ended March 31,					For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2017			2016		2017			2016		2017			2016
	(in millions)					(in millions)					(in millions)
Net Income (Loss)	$	(20	)	$	11	$	40		$	26	$	(2,033	)	$	40
Other comprehensive income (loss)
Qualifying hedges:
Changes in fair value, net of tax of $- and $-, respectively	1			—
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		)	—		1			—
Comprehensive Income (Loss)	$	(19	)	$	11	$	39		$	26	$	(2,032	)	$	40

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

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Three Months Ended March 31,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Operating Activities:
Net income (loss)	$	(20	)	$	11		$	(2,033	)	$	40
Adjustments to reconcile net income to net cash used for operating activities —
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	49			39			144			115
Deferred income taxes	(47		)	(4		)	(1,159		)	34
Allowance for equity funds used during construction	(35		)	(29		)	(72		)	(90		)
Estimated loss on Kemper IGCC	108			53			3,148			222
Other, net	(3		)	(4		)	(26		)	(1		)
Changes in certain current assets and liabilities —
-Receivables							438			3
-Fossil fuel stock							21			8
-Other current assets	18			43			(9		)	34
-Accounts payable	(35		)	(22		)	(21		)	5
-Accrued taxes	(46		)	(60		)	20			96
-Accrued compensation	(22		)	(16		)	(12		)	(5		)
-Over recovered regulatory clause revenues	(12		)	9			(47		)	(20		)
-Customer liability associated with Kemper refunds	—			(51		)	—			(73		)
-Other current liabilities	5			8			(31		)	5
Net cash used for operating activities	(40		)	(23		)
Net cash provided from operating activities							361			373
Investing Activities:
Property additions	(186		)	(197		)	(411		)	(592		)
Construction payables	—			(7		)	(47		)	(25		)
Payments pursuant to LTSAs	1			(5		)
Government grant proceeds							—			137
Other investing activities	(5		)	(5		)	(25		)	(29		)
Net cash used for investing activities	(190		)	(214		)	(483		)	(509		)
Financing Activities:
Increase in notes payable, net	9			—
Decrease in notes payable, net							(23		)	—
Proceeds —
Capital contributions from parent company							1,002			227
Long-term debt to parent company	—			200			40			200
Other long-term debt	—			900			—			900
Short-term borrowings	4			—			113			—
Redemptions —
Short-term borrowings	—			(475		)	(109		)	(475		)
Long-term debt to parent company							(591		)	(225		)
Other long-term debt	—			(425		)	(300		)	(425		)
Other financing activities	(1		)	(2		)	(3		)	(5		)
Net cash provided from financing activities	12			198			129			197
Net Change in Cash and Cash Equivalents	(218		)	(39		)	7			61
Cash and Cash Equivalents at Beginning of Period	224			98			224			98
Cash and Cash Equivalents at End of Period	$	6		$	59		$	231		$	159
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $25 and $22, net of $12 and $10 capitalized for 2017 and 2016, respectively)	$	13		$	12
Interest (paid $73 and $72, net of $28 and $36 capitalized for 2017 and 2016, respectively)							$	45		$	36
Income taxes, net	—			(24		)	(209		)	(231		)
Noncash transactions — Accrued property additions at end of period	78			97			32			80

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

MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


Assets	At March 31, 2017		At December 31, 2016		At September 30, 2017		At December 31, 2016
	(in millions)				(in millions)
Current Assets:
Cash and cash equivalents	$	6	$	224	$	231	$	224
Receivables —
Customer accounts receivable	26		29		38		29
Unbilled revenues	38		42		41		42
Income taxes receivable, current	544		544		102		544
Other accounts and notes receivable	17		14		15		14
Affiliated	14		15		15		15
Fossil fuel stock	83		100		20		100
Materials and supplies	78		76		45		76
Other regulatory assets, current	113		115		113		115
Other current assets	3		8		8		8
Total current assets	922		1,167		628		1,167
Property, Plant, and Equipment:
In service	4,963		4,865		4,836		4,865
Less: Accumulated provision for depreciation	1,303		1,289		1,312		1,289
Plant in service, net of depreciation	3,660		3,576		3,524		3,576
Construction work in progress	2,570		2,545		75		2,545
Total property, plant, and equipment	6,230		6,121		3,599		6,121
Other Property and Investments	12		12		28		12
Deferred Charges and Other Assets:
Deferred charges related to income taxes	382		361		62		361
Other regulatory assets, deferred	520		518		436		518
Accumulated deferred income taxes					279		—
Other deferred charges and assets	22		56		23		56
Total deferred charges and other assets	924		935		800		935
Total Assets	$	8,088	$	8,235	$	5,055	$	8,235

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

MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)


Liabilities and Stockholder's Equity	At March 31, 2017			At December 31, 2016			At September 30, 2017			At December 31, 2016
	(in millions)						(in millions)
Current Liabilities:
Securities due within one year —
Parent	$	—		$	551		$	—		$	551
Other	1,328			78			1,028			78
Notes payable	36			23			4			23
Accounts payable —
Affiliated	44			62			56			62
Other	112			135			82			135
Customer deposits	16			16			16			16
Accrued taxes	51			99			78			99
Unrecognized tax benefits	385			383			2			383
Accrued interest	50			46			16			46
Accrued compensation	20			42			29			42
Asset retirement obligations, current	27			32			15			32
Over recovered regulatory clause liabilities	39			51
Over recovered fuel clause liabilities							4			51
Other current liabilities	22			20			67			20
Total current liabilities	2,130			1,538			1,397			1,538
Long-term Debt:
Long-term debt to parent	551			—
Long-term debt, non-affiliated	1,172			2,424
Total Long-term Debt	1,723			2,424
Long-term Debt							1,167			2,424
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	729			756			—			756
Employee benefit obligations	113			115			109			115
Asset retirement obligations, deferred	148			146			150			146
Other cost of removal obligations	172			170			175			170
Other regulatory liabilities, deferred	78			84			87			84
Other deferred credits and liabilities	36			26			23			26
Total deferred credits and other liabilities	1,276			1,297			544			1,297
Total Liabilities	5,129			5,259			3,108			5,259
Redeemable Preferred Stock	33			33			33			33
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 1,130,000 shares
Outstanding — 1,121,000 shares	38			38			38			38
Paid-in capital	3,526			3,525			4,529			3,525
Accumulated deficit	(635		)	(616		)	(2,650		)	(616		)
Accumulated other comprehensive loss	(3		)	(4		)	(3		)	(4		)
Total common stockholder's equity	2,926			2,943			1,914			2,943
Total Liabilities and Stockholder's Equity	$	8,088		$	8,235		$	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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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~FIRST~~THIRD QUARTER 2017 vs. ~~FIRST~~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 ~~completion and operation of the~~ Kemper ~~IGCC,~~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 current cost estimate for the Kemper IGCC in total is approximately $7.16 billion, which includes approximately $5.75 billion of costs subject to the construction cost cap and is net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts to customers. Mississippi Power does not intend to seek any rate recovery for any related costs that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate subject to the construction cost cap totaling $108 million ($67 million after tax) in the first quarter 2017. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.87 billion ($1.77 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2017. The current cost estimate includes costs through May 31, 2017, as well as identified costs to be incurred beyond May 31, 2017, expected to be subject to the $2.88 billion cost cap. Additional improvement projects to enhance plant performance, safety, and/or operations ultimately may be completed after the remainder of the Kemper IGCC is placed in service. These projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap.

~~The expected completion date of the Kemper IGCC at the time of the Mississippi PSC's approval in 2010 was May 2014.~~ The combined cycle and ~~the~~ associated common facilities portion of the Kemper IGCC were placed in service in August 2014. The remainder of the plant, including the gasifiers and the gas clean-up facilities, represents first-of-a-kind technology. Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. Mississippi Power continues to work toward achieving sustained operation sufficient to place the remainder of the plant in service. The plant has, however, produced and captured CO₂, and has produced sulfuric acid and ammonia, all of acceptable quality under the related off-take agreements. As a result of ongoing challenges associated with the ash removal and gas cleanup sour water systems, efforts to improve reliability and reach sustained operation of both gasifiers and production of electricity from syngas in both combustion turbines remain in process. Mississippi Power currently expects the remainder of the Kemper IGCC, including both gasifiers, will be placed in service by the end of May 2017.

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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. ~~Upon placing~~As required by the ~~remainder~~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.

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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).

Total pre-tax charges to income for the estimated probable losses on ~~completing~~ the ~~regulatory cost recovery process.~~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 ~~is required~~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 ~~rate case~~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 ~~address~~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 ~~cost recovery by June 3, 2017 (2017 Rate Case). Costs incurred through March 31, 2017 totaled $6.93 billion, net~~including transmission and related regulatory assets, of ~~the Initial and Additional DOE Grants. Of this total, $2.87 billion of costs has been recognized through income as a result of the $2.88 billion cost cap, $0.83~~which $0.8 billion is included in retail and wholesale rates for the assets in service, and the remainder will be the subject of the 2017 Rate Case to be filed with the Mississippi PSC and expected subsequent wholesale MRA rate filing with the FERC. Mississippi Power continues to believe that all costs related to the Kemper IGCC that remain subject to recovery have been prudently incurred in accordance with the requirements of the 2012 MPSC CPCN Order. Mississippi Power recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further herein, these challenges include, but are not limited to, prudence issues associated with capital costs, financing costs (AFUDC), and future operating costs, net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the 15% portion of the project previously contracted to SMEPA.

In connection with the 2017 Rate Case, Mississippi Power expects to request authority from the Mississippi PSC, and separately from the FERC, to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, arerates. 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 ~~are not required~~expects them to be ~~charged against earnings as a result of~~recovered through rates consistent with the ~~$2.88 billion cost cap until such time as~~Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC ~~completes its review and includes the resulting allowable costs~~ in rates. In the event that the Mississippi PSC does not grant Mississippi Power's request for an accounting order, monthly expenses in the amount of $25 million per month will be charged to income as incurred and will not be recoverable through rates. In addition, after the remainder of the plant is placed in service, AFUDC equity of approximately $12 million per month will no longer be recorded in income.

~~Although the 2017 Rate Case has not yet been filed and is subject to future developments with either~~ the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, Mississippi Power is developing both a traditional rate case requesting full cost recovery of the $3.37 billion (net of $137 million in Additional DOE Grants) not currently in rates and a rate mitigation plan that together represent Mississippi Power's probable filing strategy. Mississippi Power has evaluated various scenarios in connection with its processes to prepare the 2017 Rate Case and recognized an $80 million charge to income in 2016, which is the estimated minimum probable amount of the $3.37 billion of Kemper IGCC costs not currently in rates that would not be recovered under the probable rate mitigation plan to be filed by June 3, 2017. Mississippi Power expects that timely resolution of the 2017 Rate Case will likely require a settlement agreement between Mississippi Power and the MPUS (and other parties) that may include other operational or cost recovery alternatives and would be subject to the approval of the Mississippi PSC. While Mississippi Power intends to pursue any available settlement alternatives, the ability to achieve a negotiated settlement is uncertain. If a settlement is achieved, full regulatory recovery of the amounts not currently in rates is unlikely and could result in further material charges; however, the impact of such an agreement on Mississippi Power's financial statements would depend on the method, amount, and type of cost recovery ultimately excluded, none of which can be reasonably determined at this time. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, Mississippi Power intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges. 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 these matters cannot now be determined but could result in further charges that could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity.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, consistent with GAAP.~~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"~~"Going Concern" herein.

In addition to the ~~construction, start-up, and~~ rate recovery of the Kemper ~~IGCC,~~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)



~~First Quarter 2017 vs. First Quarter 2016~~
~~(change in millions)~~		~~(% change)~~
~~$(31)~~		~~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 ~~the first quarter~~year-to-date 2017 was ~~$20 million~~$2.03 billion compared to net income of ~~$11~~$39 million for the corresponding period in 2016. The decrease in net income was ~~primarily~~ related to higher pre-tax charges of $108 million ($67 million after tax) in 2017 compared to pre-tax charges of $53 million ($33 million after tax) in 2016 for revisions of the estimated costs expected to be incurred on Mississippi Power's construction ofassociated with the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The decrease in net income was partially offset by an increase in operating revenues and AFUDC equity.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.

~~Retail Revenues~~

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$17 9.3

~~In the first quarter 2017, retail revenues were $200 million compared to $183 million for the corresponding period in 2016.~~

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Retail Revenues

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:


	First Quarter 2017					Third Quarter 2017					Year-to-Date 2017
	(in millions)			(% change)		(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	183				$	263				$	652
Estimated change resulting from –
Rates and pricing	12			6.6		(10		)	(3.8	)	9			1.4
Sales growth (decline)	4			2.1
Sales growth						1			0.4		4			0.6
Weather	(5		)	(2.7	)	(9		)	(3.4	)	(16		)	(2.5	)
Fuel and other cost recovery	6			3.3		(2		)	(0.8	)	16			2.5
Retail – current year	$	200		9.3	%	$	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 ~~the first quarter~~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.~~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 ~~first~~third quarter 2017 when compared to the corresponding period in 2016. Weather-adjusted KWH sales to residential customers increased ~~1.3%~~2.9% due to higher customer ~~usage offset by a decline in the number of customers.~~usage. Weather-adjusted KWH sales to commercial customers decreased ~~0.1%~~1.2% due to lower customer usage, partially offset by customer growth. KWH sales to industrial customers ~~increased 0.6%~~decreased 2.4% primarily due to an unplanned outage by a large customer in ~~2016.~~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 ~~in the first quarter~~

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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

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$(4) (44.4)

N/M - Not meaningful

In the ~~first~~third quarter 2017, wholesale revenues from sales to affiliates were $5$21 million compared to $9 million for the corresponding period in 2016. The decrease was due to a $5 million decrease in KWH sales primarily due to the availability of lower cost alternatives offset by a $1 million increase associated with higher natural gas prices.

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~~Fuel and Purchased Power Expenses~~

First Quarter 2017
vs.
First Quarter 2016
(change in millions) (% change)
Fuel $ 2
2.6
Purchased power – non-affiliates 1
N/M
Purchased power – affiliates 2
40.0
Total fuel and purchased power expenses $ 5

~~N/M - Not meaningful~~

~~In the first quarter 2017, total fuel and purchased power expenses were $86 million compared to $81~~$7 million for the corresponding period in 2016. The increase was due to a ~~$15~~$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~~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 ~~$10~~$4 million ~~net~~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.

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

First Quarter 2017 First Quarter 2016
Total generation (in millions of KWHs)
3,161 3,588
Total purchased power (in millions of KWHs)
242 261
Sources of generation (percent) –

Coal 9 11
Gas 91 89
Cost of fuel, generated (in cents per net KWH) –

Coal 3.33 3.55
Gas 2.65 2.15
Average cost of fuel, generated (in cents per net KWH)
2.71 2.32
Average cost of purchased power (in cents per net KWH)
3.33 2.17

~~Fuel~~

In the first quarter 2017, total fuel expense was $78 million compared to $76 million for the corresponding period in 2016. The increase was due to a 17% increase in the average cost of fuel per KWH generated primarily due to a 23% higher cost of natural gas offset by a 12% decrease in the volume of KWHs generated primarily as a result of lower sales.

~~Purchased Power - Affiliates~~

In the first quarter 2017, purchased power expense from affiliates was $7 million compared to $5 million for the corresponding period in 2016. The increase was primarily due to a 35% increase in the volume of KWHs purchased due to the availability of lower cost energy as compared to self-generation fuel cost, partially offset by a 6% decrease in the average cost per KWH purchased primarily as a result of lower fuel prices.

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~~Other Operations~~Details of Mississippi Power's generation and ~~Maintenance Expenses~~purchased power were as follows:

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$5 7.2



	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 ~~first~~third quarter 2017, ~~other operations and maintenance expenses were $74~~total fuel expense was $120 million compared to ~~$69~~$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 ~~$3 million~~4.5% higher cost of natural gas, and a 5.4% increase in ~~amortization~~the volume of ~~prior~~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

In the third quarter 2017, other operations and maintenance ~~expense deferrals~~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 and a $2 million increase in generation maintenance expenses, including scheduled outages.~~assets.

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

Depreciation and Amortization

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

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



~~First Quarter 2017 vs. First Quarter 2016~~
~~(change in millions)~~		~~(% change)~~
~~$55~~		~~N/M~~

N/M - Not meaningful

~~In the first quarters of 2017 and 2016, estimated~~Estimated probable losses on the Kemper IGCC of ~~$108~~$34 million and ~~$53 million, respectively,~~$3.2 billion were recorded atin 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 ~~Power. These~~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 ~~reflect~~for revisions of estimated costs expected to be incurred on ~~the~~ 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

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

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.

~~Allowance for Equity Funds Used During Construction~~Income Taxes (Benefit)

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$6 20.7

N/M - Not meaningful

In the ~~first~~third quarter 2017, ~~AFUDC equity was $35~~income taxes were $24 million compared to ~~$29~~an income tax benefit of $2 million for the corresponding period in 2016. ~~The increase resulted from a higher AFUDC rate and an increase in Kemper IGCC CWIP subject~~For year-to-date 2017, income tax benefit was $885 million compared to ~~AFUDC.~~

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 Note (B) to the Condensed Financial Statements under "~~FERC Matters" and "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.~~$29 million

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~~Interest Expense, Net of Amounts Capitalized~~

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$3 18.8

~~In the first quarter 2017, interest expense, net of amounts capitalized was $19 million compared to $16 million~~ for the corresponding period in 2016. The ~~increase was~~changes were primarily due to ~~amortization of $3 million in deferred interest associated with the Kemper IGCC in-service assets and $1 million related to uncertain tax positions.~~

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 Notes (B) and (G) to the Condensed Financial Statements under "~~Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax Benefits," respectively, herein for additional information.~~

~~Income Taxes (Benefit)~~



~~First Quarter 2017 vs. First Quarter 2016~~
~~(change in millions)~~		~~(% change)~~
~~$(17)~~		~~N/M~~

~~N/M - Not meaningful~~

~~In the first quarter 2017, income tax benefit was $27 million compared to $10 million for the corresponding period in 2016. The change was primarily due to the increase in~~ the estimated probable losses on ~~construction~~the Kemper IGCC, net of the ~~Kemper IGCC.~~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 ~~IGCC costs~~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 ~~IGCC, and the completion and subsequent operation of the Kemper IGCC in accordance with any operational parameters that may be adopted by the Mississippi PSC.~~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 ~~economic growth. The~~the pace of economic growth ~~and electricity demand~~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.

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

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 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 ~~this matter~~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)

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~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding ~~Mississippi Power's construction of~~ the Kemper IGCC.

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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 ~~estimated~~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 ~~$18 million until~~152 MWs, which became effective in 2011. Following certain plant retirements, the ~~end~~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 ~~May 2017 when~~ the ~~Kemper IGCC is projected~~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 ~~placed in service.~~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

~~Of the~~Mississippi Power placed in service three solar projects ~~expected to be~~ in ~~service in 2017, one was placed in service in the first quarter 2017, while the remaining two are expected to be placed in service in~~January, June, and ~~July~~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.

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 ~~this matter~~these matters cannot be determined at this time.

Energy Efficiency

~~In November 2016,~~On July 6, 2017, the Mississippi ~~Power submitted its~~PSC issued an order approving Mississippi Power's Energy Efficiency Cost Rider ~~(EECR) Compliance~~compliance filing, which ~~included an increase of $1 million in~~increased annual retail ~~revenues. On March 13, 2017, Mississippi Power amended and revised the EECR Compliance filing to request a~~revenues by approximately $2 million ~~annual increase in retail revenues. The ultimate outcome of this matter cannot be determined at this time.~~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 ~~March 31,~~September 30, 2017, the amount of over-recovered retail fuel costs included on the condensed balance sheet was ~~$27~~$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 ~~April 7,~~July 6, 2017, the Mississippi ~~Power submitted its~~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 ~~utilizes~~was designed to utilize IGCC technology with an expected output capacity of 582 ~~MWs. The Kemper IGCC is~~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 ~~and plans to operate~~ 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 remainder of the plant, including the gasifiers and the gas clean-up facilities, represents first-of-a-kind technology.~~

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. ~~Mississippi Power continues to work toward achieving sustained operation sufficient to place the remainder of~~During testing, the plant ~~in service. The plant has, however,~~ produced and captured CO₂, and has produced sulfuric acid and ammonia, all of acceptable quality under the related off-take agreements. As a result of ongoing challenges associated with the ash removal and gas cleanup sour water systems, efforts to improve reliability and reach sustained operation of both gasifiers and production of electricity from syngas in both combustion turbines remain in process. Mississippi Power currently expects the remainder of the Kemper IGCC, including both gasifiers, will be placed in service by the end of May 2017. The schedule reflects the expected time needed to repair a leak in one of the particulate control devices for gasifier "A," make other minor modifications to each gasifier's ash removal systems, repair the sour water system, and establish sustained operation of both gasifiers for the production of electricity from syngas.

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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.

Mississippi Power's Kemper IGCC 2010 project estimate ~~current~~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 ~~(which includes the impacts of the Mississippi Supreme Court's (Court) decision discussed herein under "Rate Recovery of Kemper IGCC Costs~~ – ~~2013 MPSC Rate Order"), and actual costs incurred as of March 31, 2017, all of which include 100% of the costs~~ for the Kemper IGCC ~~are as follows:~~

Cost Category
2010 Project Estimate^(a)

Current Cost Estimate^(b)
Actual Costs
(in billions)
Plant Subject to Cost Cap^(c)(e)
$ 2.40
$ 5.75
$ 5.57
Lignite Mine and Equipment 0.21
0.23
0.23
CO₂ Pipeline Facilities
0.14
0.12
0.12
AFUDC^(d)
0.17
0.83
0.80
Combined Cycle and Related Assets Placed in
Service – Incremental^(e)
—
0.05
0.04
General Exceptions 0.05
0.10
0.09
Deferred Costs^(e)
—
0.22
0.22
Additional DOE Grants —
(0.14 ) (0.14 )
Total Kemper IGCC^(f)
$ 2.97
$ 7.16
$ 6.93


~~(a)~~	~~The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO~~₂ ~~pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions.~~


~~(b)~~	~~Amounts in the Current Cost Estimate include certain estimated post-in-service~~was approximately $7.38 billion, including approximately $5.95 billion of costs ~~which are expected to be~~ subject to the ~~cost cap.~~

~~(c)~~

~~The 2012 MPSC CPCN Order approved a~~ construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap, and ~~exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs~~ – ~~2013 MPSC Rate Order" herein for additional information.~~

~~(d)~~

~~Mississippi Power's 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach~~ was not approved by the Mississippi PSC as described in "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order." The Current Cost Estimate also reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "~~FERC Matters" herein for additional information.~~

~~(e)~~

Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are now included in rates and are being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at March 31, 2017. The wholesale portion of debt carrying costs, whether deferred or recognized through income, is not included in the Current Cost Estimate and the Actual Costs at March 31, 2017. See "~~Rate Recovery of Kemper IGCC Costs~~ – ~~Regulatory Assets and Liabilities" herein for additional information.~~

~~(f)~~

The Current Cost Estimate and the Actual Costs include $2.87 billion that will not be recovered for costs above the cost cap, $0.83 billion of investment costs included in current rates for the combined cycle and related assets in service, and $0.09 billion of costs that were previously expensed for the combined cycle and related assets in service. The Current Cost Estimate and the Actual Costs exclude $0.23 billion of costs not included in current rates for post-June 2013 mine operations, the lignite fuel inventory, and the nitrogen plant capital lease, which will be included in the 2017 Rate Case to be filed by June 3, 2017. See Note 1 and Note 6 to the financial statements of Mississippi Power under "Fuel Inventory" and "Capital Leases," respectively, in Item 8 of the Form 10-K and "~~Rate Recovery of Kemper IGCC Costs~~ – ~~2017 Rate Case" herein for additional information.~~

~~Of the total costs, including post-in-service costs for the lignite mine, incurred as of March 31, 2017, $3.73 billion was included in property, plant, and equipment (which is~~ net of the ~~Initial DOE Grants, the~~$137 million in Additional DOE Grants, and estimated probable losses of $2.95 billion), $6 million in other property and investments, $64 million in fossil fuel stock, $48 million in materials and supplies, $24 million in other regulatory assets, current, $173 million in other regulatory assets, deferred, $1 million in other current assets, and $17 million in other deferred charges and assets in the balance sheet.Grants.

Mississippi Power does not intend to seek rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap for the Kemper IGCC of ~~$108~~$196 million ($67121 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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after tax) in the first quarter 2017. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.87 billion ($1.77 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2017. The increase to the cost estimate in the first quarter 2017 primarily reflects $67 million for the extension of the Kemper IGCC's projected in-service date from mid-March 2017 to the end of May 2017, $23 million related to start-up fuel, and $18 million primarily related to outage maintenance and operational improvements.

In addition to the current construction cost estimate, Mississippi Power is identifying potential improvement projects to enhance plant performance, safety, and/or operations that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. Approximately $12 million of related potential costs was recorded in 2016 and included in the current construction cost estimate. Other projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap.

Any extension of the in-service date beyond May 31, 2017 is currently estimated to result in additional base costs of approximately $25 million to $35 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date beyond May 31, 2017 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $16 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $3 million per month. For additional information, see "~~Rate Recovery of Kemper IGCC Costs~~ – ~~2015 Rate Case" herein.~~

Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, sustaining nitrogen supply, continued issues with ash removal systems, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). Any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of income and these changes could be material.

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 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.

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~~As of March 31, 2017,~~$0.8 billion is included in ~~addition to the $2.87~~retail and wholesale rates. The $0.5 billion of costs above the Mississippi PSC's $2.88 billion cost cap that have been recognized as a charge to income, Mississippi Power had incurred approximately $2.01 billion in costs subject to the cost cap and approximately $1.50 billion in Cost Cap Exceptions related to the construction and start-up of the Kemper IGCC that are not included in current ~~rates. These~~rates includes costs ~~primarily relate to~~in excess of the ~~following:~~

Cost Category Actual Costs
(in billions)
Gasifiers and Gas Clean-up Facilities $ 1.90
Lignite Mine Facility 0.31
CO₂ Pipeline Facilities
0.11
Combined Cycle and Common Facilities 0.17
AFUDC 0.73
General exceptions 0.07
Plant inventory 0.04
Lignite inventory 0.06
Regulatory and other deferred assets 0.12
Subtotal 3.51
Additional DOE Grants (0.14 )
Total $ 3.37

~~Of these amounts, approximately 29% is related to wholesale and approximately 71% is related to retail, including~~original 2010 estimate for the combined cycle portion of the facility, as well as the 15% ~~portion~~ that was previously contracted to ~~be sold to SMEPA.~~Cooperative Energy. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and ~~its wholesale customers have generally agreed~~expects them to ~~similar regulatory treatment for wholesale tariff purposes as approved~~be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC ~~for retail for~~in the Kemper ~~IGCC-related costs. See "FERC Matters~~ – ~~Municipal and Rural Associations Tariff" and "Termination of Proposed Sale of Undivided Interest" herein for further information.~~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 iswas 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 iswas 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 will not seek recovery of the $68 million in additional estimated costs from customers if incurred.~~

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 ~~address these matters~~utilize this information in connection with the ~~2017 Rate Case.~~

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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 ~~2017 Rate Case.~~

~~2017 Rate Case~~

~~Mississippi Power continues to believe that all costs related to the~~ Kemper IGCC that remain subject to recovery have been prudently incurred in accordance with the requirements of the 2012 MPSC CPCN Order. Mississippi Power recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further herein and under "Prudence," "Lignite Mine and CO₂ Pipeline Facilities," "Termination of Proposed Sale of Undivided Interest," and "Income Tax Matters," these challenges include, but are not limited to, prudence issues associated with capital costs, financing costs (AFUDC), and future operating costs net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the 15% portion of the project previously contracted to SMEPA.

Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power expects to utilize this legislation to securitize prudently-incurred qualifying facility costs in excess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order did not impact Mississippi Power's ability to utilize alternate financing through securitization or the February 2013 legislation.

After the remainder of the plant is placed in service, AFUDC equity of approximately $12 million per month will no longer be recorded in income, and Mississippi Power expects to incur approximately $25 million per month in depreciation, taxes, operations and maintenance expenses, interest expense, and regulatory costs in excess of current rates. In connection with the 2017 Rate Case, Mississippi Power expects to file a request for authority from the Mississippi PSC, and separately from the FERC, to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included in current rates, and are not required to be charged against earnings as a result of the $2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. In the event the Mississippi PSC does not grant Mississippi Power's request, these monthly expenses will be charged to income as incurred and will not be recoverable through rates.

Although the 2017 Rate Case has not yet been filed and is subject to future developments with either the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, Mississippi Power is developing both a traditional rate case requesting full cost recovery of the amounts not currently in rates and a rate mitigation plan that together represent Mississippi Power's probable filing strategy. Mississippi Power has evaluated various scenarios in connection with its processes to prepare the 2017 Rate Case and recognized an $80 million charge to income in 2016, which is the estimated minimum probable amount of the $3.37 billion of Kemper IGCC costs not currently in rates that would not be recovered under the probable rate mitigation plan to be filed by June 3, 2017. Mississippi

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Power expects that timely resolution of the 2017 Rate Case will likely require a settlement agreement between Mississippi Power and the MPUS (and other parties) that may include other operational or cost recovery alternatives and would be subject to the approval of the Mississippi PSC. While Mississippi Power intends to pursue any available settlement alternatives, the ability to achieve a negotiated settlement is uncertain. If a settlement is achieved, full regulatory recovery of the amounts not currently in rates is unlikely and could result in further material charges; however, the impact of such an agreement on Mississippi Power's financial statements would depend on the method, amount, and type of cost recovery ultimately excluded, none of which can be reasonably determined at this time. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, Mississippi Power intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges.Settlement Docket.

2015 Rate Case

On August 13, 2015, the Mississippi PSC approved Mississippi Power's request for interim rates, which presented an alternative rate proposal (In-Service Asset Proposal) designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. The interim rates were designed to collect approximately $159 million annually and became effective in September 2015, subject to refund and certain other conditions.

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 ~~In-Service Asset Proposal.~~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 ~~SMEPA~~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 ~~is required~~ to ~~file~~defer all non-capital Kemper IGCC-related costs to a regulatory asset through the ~~2017 Rate Case by June 3, 2017.~~

~~With~~in-service date. In connection with the implementation of the ~~new~~In-Service Asset Order and wholesale rates, ~~on December 17, 2015, the interim rates were terminated and, in March 2016,~~ Mississippi Power ~~completed customer refunds~~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 ~~approximately $11~~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 ~~difference between~~May 31, 2016 and 2017 calculations. At September 30, 2017, Mississippi Power's related regulatory liability totaled approximately $10 million.

As required by the ~~interim~~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 ~~collected~~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 ~~permanent rates.~~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 iswas 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 ~~based~~and, on among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public

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~~notice for the related proceedings. 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, ~~under the 2013 MPSC Rate Order,~~ along with associated carrying costs of $29 million. ~~The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation described above.~~

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 ~~continues~~continued to record AFUDC on the Kemper IGCC. ~~Through March 31, 2017, AFUDC recorded since~~Between the original May 2014 estimated in-service date ~~for~~and the June 2017 project suspension date, Mississippi Power recorded $494 million of AFUDC on the Kemper IGCC ~~has totaled $445 million, which will continue~~subject to ~~accrue at approximately $16 million per month until the remainder of the plant is placed in service. Mississippi Power has not recorded any AFUDC on Kemper IGCC costs in excess of~~ the $2.88 billion cost cap ~~except for~~and Cost Cap Exception ~~amounts.~~

~~2012 MPSC CPCN Order~~

~~The 2012 MPSC CPCN Order included provisions relating~~amounts, of which $460 million related to ~~both Mississippi Power's recovery of financing costs during~~ the ~~course of construction~~gasification portions of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters including availability factor, heat rate, lignite heat content, and chemical revenue based upon assumptions in Mississippi Power's petition for the CPCN. IGCC.

Mississippi Power expects the Mississippi PSC to ~~apply operational parameters~~address this matter in connection with the ~~2017 Rate Case and future proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the~~ Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Mississippi Power's financial statements. See "~~Prudence" herein for additional information.~~

~~Regulatory Assets and Liabilities~~

Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.

In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015 and the second quarter 2016, in connection with the implementation of retail and wholesale rates, respectively, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs (associated with assets placed in service and other non-CWIP accounts) that previously were deferred as regulatory assets 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 March 31, 2017, the balance associated with these regulatory assets was $86 million, of which $24 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $111 million as of March 31, 2017. The amortization period for these assets is expected to be determined by the Mississippi PSC in the 2017 Rate Case. See "~~FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.~~

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~~March 31, 2017, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $8 million. See "2015 Rate Case" herein for additional information.~~

~~See Note 1 to the financial statements of Mississippi Power under "Regulatory Assets and Liabilities" in Item 8 of the Form 10-K for additional information.~~

Lignite Mine and CO₂ Pipeline Facilities

In conjunction with the Kemper IGCC, Mississippi Power owns the lignite mine and equipment and ~~has acquired and will continue to acquire~~ 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 ~~operating and managing~~responsible for the mining ~~operations. The contract with Liberty Fuels is effective~~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 ~~currently~~ 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 ~~has~~ constructed ~~and will operate~~ 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, and termination rights if~~years. Denbury has the right to terminate the contract at any time because Mississippi Power ~~has~~did not ~~satisfied its contractual obligation to deliver captured CO~~₂place the Kemper IGCC in service by July 1, 2017, in addition to Denbury's existing termination rights in the event of a change in law, force majeure, or an event of default by Mississippi Power. Any termination or material modification of the agreement with Denbury could impact the operations of the Kemper IGCC and result in a material reduction in Mississippi Power's revenues to the extent Mississippi Power is not able to enter into other similar contractual arrangements or otherwise sequester the CO₂produced. Additionally, sustained oil price reductions could result in significantly lower revenues than Mississippi Power originally forecasted to be available to offset customer rate impacts, which could have a material impact on Mississippi Power's financial statements.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 ~~SMEPA~~Cooperative Energy (formerly known as SMEPA) entered into an agreement whereby ~~SMEPA~~Cooperative Energy agreed to purchase a 15% undivided interest in the Kemper ~~IGCC (15% Undivided Interest).~~IGCC. On May 20, 2015, ~~SMEPA~~Cooperative Energy notified Mississippi Power of its termination of the agreement. Mississippi Power previously received a total of $275 million of deposits from ~~SMEPA~~Cooperative Energy that were required to be returned to ~~SMEPA~~Cooperative Energy with interest. On June 3, 2015, Southern Company, pursuant to its guarantee obligation, returned approximately $301 million to ~~SMEPA.~~Cooperative Energy. Subsequently, Mississippi Power issued a promissory note in the aggregate principal amount of approximately $301 million to Southern Company, which ~~matures on July 31, 2018.~~was repaid in June 2017.

Litigation

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~~November 17, 2016.~~ The individual plaintiff ~~John Carlton Dean,~~ 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 ~~December 7, 2016,~~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 ~~motions to dismiss, which the Circuit Court is expected to address in the second quarter 2017.~~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 CO₂contract 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 ~~have~~ moved to compel arbitration pursuant to the terms of the CO₂ contract, which the court ~~is expected to address~~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 ~~the second quarter 2017.~~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. ~~See "Rate Recovery of Kemper IGCC Costs" herein for additional information.~~

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

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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 Mississippi Power~~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 estimated construction costs and expected in-service date.~~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

~~During 2017,~~Recovery" of Mississippi Power ~~further revised its cost estimate to complete construction and start-up~~in Item 7 of the ~~Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery~~Form 10-K for ~~any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions.~~

~~As a result of revisions to the cost estimate,~~additional information. Mississippi Power recorded total pre-tax charges to income ~~for the estimated probable losses on~~related to the Kemper IGCC ~~subject to the construction cost cap~~ of ~~$108~~$428 million ($67264 million after tax) in ~~the first quarter 2017, $127~~2016, $365 million ($78226 million after tax) in ~~the fourth quarter 2016, $88~~2015, $868 million ($54536 million after tax) in ~~the third quarter 2016, $81 million~~2014, and $1.2 billion ($50729 million after tax) in prior years.

As a result of the ~~second quarter 2016, $53 million ($33 million after tax) in~~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 ~~first quarter 2016, $183 million ($113 million after tax) in~~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 ~~fourth quarter 2015, $150 million ($93 million after tax) in~~operation and start-up of the ~~third quarter 2015, $23 million ($14 million after tax) in~~gasifier portion of the ~~second quarter 2015, $9 million ($6 million after tax) in~~Kemper IGCC, the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, $462 million ($285 million after tax) in the first quarter 2013,estimated construction costs and ~~$78 million ($48 million after tax) in the fourth quarter~~

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~~2012.~~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.

In addition to the current construction cost estimate, Mississippi Power is also identifying potential improvement projects to enhance plant performance, safety, and/or operations that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. Approximately $12 million of related potential costs was recorded in 2016 and included in the current construction cost estimate. Other projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap. In subsequent periods, any further changes in the estimated costs of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of income and these changes could be material.

~~Mississippi Power continues to believe that all costs related to~~ the Kemper IGCC ~~that remain subject to recovery have been prudently incurred in accordance with~~Settlement Docket proceedings.

~~Although the 2017 Rate Case has not yet been filed and is subject to future developments with either~~aggregate, since the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, Mississippi Power is developing both a traditional rate case requesting full cost recovery of the amounts not currently in rates and a rate mitigation plan that together represent Mississippi Power's probable filing strategy.project started, Mississippi Power has ~~evaluated various scenarios in connection with its processes to prepare the 2017 Rate Case and recognized an $80 million charge to income in 2016, which is the estimated minimum probable amount~~incurred charges of ~~the $3.37~~$6.00 billion ~~of Kemper IGCC costs not currently in rates that would not be recovered under the probable rate mitigation plan to be filed by June 3,~~($3.96 billion after tax) through September 30, 2017. Mississippi Power ~~expects that timely resolution~~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 ~~Rate Case will likely require a settlement agreement between Mississippi Power~~ and the ~~MPUS (and other parties) that may include other operational or cost recovery alternatives~~third quarter 2016, respectively, and ~~would be subject to the approval~~total pre-tax charges of ~~the Mississippi PSC. While Mississippi Power intends to pursue any~~

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~~available settlement alternatives, the ability to achieve a negotiated settlement is uncertain. If a settlement is achieved, full regulatory recovery of the amounts not currently~~$3.2 billion ($2.2 billion after tax) and $222 million ($137 million after tax) year-to-date in ~~rates is unlikely~~2017 and could result in further material charges; however, the impact of such an agreement on Mississippi Power's financial statements would depend on the method, amount, and type of cost recovery ultimately excluded, none of which can be reasonably determined at this time. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, Mississippi Power intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges.2016, respectively.

Given the significant judgment involved in estimating the ~~future~~ costs to ~~complete construction and start-up,~~cancel the ~~project completion date,~~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 ~~potential~~ 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.

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. For such arrangements,~~term, as well as longer-term contractual commitments, including PPAs. Mississippi Power expects that the revenue from contracts with these customers ~~will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606~~ 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 ~~longer term contractual commitments and~~ unregulated sales to customers. Some revenue arrangements, such as ~~certain PPAs 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 Mississippi Power's financial ~~statements.~~statements, if material. In addition, the power and utilities industry ~~is currently addressing~~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 ~~must select~~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 ~~transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect~~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 ~~date~~adoption of ~~initial adoption. As~~ASC 606, including the ~~ultimate~~cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of ~~the new standard has not yet been determined,~~revenues recognized in Mississippi Power's financial statements, Mississippi Power ~~has not elected its transition method.~~will continue to evaluate the requirements, as well as any additional clarifying guidance that may be issued.

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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. ~~Mississippi Power is currently evaluating the new standard.~~ 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 ~~three~~nine months ended ~~March 31,~~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. ~~In addition to the Kemper IGCC, projected~~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.

~~On February 28,~~In the second quarter 2017, ~~the maturity dates for $551~~Mississippi Power borrowed an additional $40 million inunder a promissory ~~notes~~note issued to Southern Company. In June 2017, Southern Company ~~were extended~~made equity contributions totaling $1.0 billion to ~~July 31, 2018. As~~Mississippi Power. Mississippi Power used a portion of ~~March 31, 2017,~~ the ~~amount~~proceeds to prepay $901 million of outstanding ~~promissory notes to Southern Company totaled $551 million.~~debt.

As of ~~March 31,~~September 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately ~~$1.2 billion~~$769 million primarily due to ~~a $1.2 billion unsecured term loan~~$935 million in long-term debt that matures ~~on March 30, 2018~~within the next 12 months and ~~$35 million in senior notes that mature on November 15, 2017, as well as $36~~$94 million of short-term notes payable, $40 million of tax-exempt variable rate demand obligations, and $50 million of pollution control bonds that are required to be remarketed over the next 12 months. Subsequent to March 31, 2017,debt. Mississippi Power ~~borrowed an additional $10 million under a promissory note~~intends to ~~Southern Company, which was amended and restated in February 2017. Mississippi Power expects the funds needed to satisfy maturing debt obligations will exceed amounts available from~~utilize operating cash flows, lines of credit, and ~~other external sources. Accordingly, Mississippi Power intends to satisfy these obligations through~~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. 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, consistent with GAAP. 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.short-term capital needs.

Net cash ~~used for~~provided from operating activities totaled ~~$40~~$361 million for the first ~~three~~nine months of 2017, ~~an increase~~a decrease of ~~$17~~$12 million as compared to the corresponding period in 2016. The ~~increase~~decrease in cash ~~used for~~provided from operating activities is primarily due to ~~lower~~deferred income ~~tax benefits~~taxes related to the Kemper IGCC, ~~and current assets, primarily due to receivables,~~ partially offset by the timing of payments received from affiliates and customers and the completion of Mirror CWIP ~~and subsequent~~ 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 ~~$190~~$483 million for the first ~~three~~nine months of 2017 primarily due to gross property additions related to the Kemper IGCC. Net cash provided from financing activities totaled ~~$12~~$129 million for the first ~~three~~nine months of 2017 primarily due to ~~an increase in notes~~

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~~payable~~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 ~~three~~nine months of 2017 include ~~a $218 million decrease in cash and cash equivalents and~~ an increase in ~~current liabilities and~~paid-in capital of $1.0 billion due to capital contributions from Southern Company, a ~~decrease in~~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 ~~resulting from~~due to the reclassification of $1.2 billion in unsecured term ~~loan agreement being reclassified from long-term debt~~loans to securities due within one year. These changes are partially offset by $551 million of promissory notes to Southern Company being reclassified from current to long-term debt as a result of the maturity dates being extended to July 31, 2018 and an increase in total property, plant, and equipment of $109 million primarily due to the Kemper IGCC. Other significant changes include ~~a decrease~~decreases of $2.5 billion in ~~accrued~~CWIP, $756 million in accumulated deferred income taxes, and $299 million in deferred charges related to income taxes. All of ~~$48 million~~these changes primarily resulted from the Kemper IGCC suspension and related estimated loss. Income taxes receivable and unrecognized tax benefits also decreased due to ~~ad valorem~~ tax ~~payments.~~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 ~~$1.2 billion~~$935 million will be required through ~~March 31,~~September 30, 2018 to fund maturities of long-term debt and ~~$36~~$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 ~~$659~~$582 million for 2017, ~~$241~~$203 million for 2018, ~~$274~~$177 million for 2019, ~~$305~~$204 million for 2020, ~~$230~~$199 million for 2021, and ~~$289~~$240 million for ~~2022, which includes completion of the Kemper IGCC and post-in-service costs. Expenditures related to the completion of the Kemper IGCC are currently estimated to be $395 million for 2017.~~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.

In addition, the construction program includes the development and construction of the Kemper IGCC, a first-of-a-kind technology, which may result in revised estimates during construction. The ability to control costs and avoid cost overruns during the development and construction of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, sustaining nitrogen supply, 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 the Mississippi PSC).

~~See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle~~ – ~~Kemper IGCC Schedule and Cost Estimate" herein for additional information and further risks related to the estimated schedule and costs and rate recovery for the Kemper IGCC.~~

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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 ~~IGCC~~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 ~~March 31,~~September 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately ~~$1.2 billion~~$769 million primarily due to ~~a $1.2 billion unsecured term loan~~$935 million in long-term debt that matures ~~on March 30, 2018~~within the next 12 months and ~~$35 million in senior notes that mature on November 15, 2017, as well as $36~~$94 million of short-term notes payable, $40 million of tax-exempt variable rate demand obligations, and $50 million of pollution control bonds that are required to be remarketed over the next 12 months. Subsequent to March 31, 2017,debt. Mississippi Power ~~borrowed an additional $10 million under a promissory note~~intends to ~~Southern Company. Mississippi Power expects the funds needed to satisfy maturing debt obligations will exceed amounts available from~~utilize operating cash flows, lines of credit, and ~~other external sources. Accordingly, Mississippi Power intends to satisfy these obligations through~~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.~~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, consistent with GAAP.~~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.~~

Mississippi Power received $245 million of Initial DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of grants from the DOE is expected to be received for commercial operation of the Kemper IGCC. In April 2016, Mississippi Power received approximately $137 million in Additional DOE Grants for the Kemper IGCC, which are expected to be used to reduce future rate impacts for customers. See Note (B) to the Condensed Financial Statements under "~~Integrated Coal Gasification Combined Cycle~~Going Concern ~~– Baseload Act" herein for additional information regarding legislation related to the securitization of certain costs of the Kemper IGCC.~~" herein.

At ~~March 31,~~September 30, 2017, Mississippi Power had approximately $6$231 million of cash and cash equivalents. Committed credit arrangements with banks at ~~March 31,~~September 30, 2017 were as follows:


Expires	Expires					Executable Term Loans				Expires Within One Year				Expires					Executable Term Loans				Expires Within One Year
2017	2017	Total		Unused		One Year		Two Years		Term Out		No Term Out		2017	Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)
$	173	$	173	$	141	$	—	$	13	$	13	$	160	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~~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 ~~March 31,~~September 30, 2017,

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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 ~~$141~~$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 ~~March 31,~~September 30, 2017 was approximately $40 million. In addition, at ~~March 31,~~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 ~~March 31,~~September 30, 2017.

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Credit Rating Risk

At ~~March 31,~~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 ~~March 31,~~September 30, 2017, the ~~maximum potential collateral requirements under these contracts at a rating of BBB and/or Baa2 or BBB- and/or Baa3 was not material. The~~ maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately ~~$233~~$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

OnIn 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 ~~28,~~ 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. ~~Subsequent to March 31,~~In the second quarter 2017, Mississippi Power borrowed an additional ~~$10~~$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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~On March 31, 2017,~~In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Mississippi Power ~~issued a $9 million short-term note bearing interest at 5% per annum, which was repaid on April 27, 2017.~~plans, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

SOUTHERN POWER COMPANY

AND SUBSIDIARY COMPANIES

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)


	For the Three Months Ended March 31,						For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2017			2016			2017			2016			2017			2016
	(in millions)						(in millions)						(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	347		$	215		$	510		$	387		$	1,293		$	866
Wholesale revenues, affiliates	100			97			105			110			295			313
Other revenues	3			3			3			3			9			10
Total operating revenues	450			315			618			500			1,597			1,189
Operating Expenses:
Fuel	132			91			189			154			460			341
Purchased power, non-affiliates	25			13			36			25			90			60
Purchased power, affiliates	5			6			7			8			23			16
Other operations and maintenance	92			79			83			81			272			246
Depreciation and amortization	119			73			131			93			379			247
Taxes other than income taxes	12			6			13			5			37			17
Total operating expenses	385			268			459			366			1,261			927
Operating Income	65			47			159			134			336			262
Other Income and (Expense):
Interest expense, net of amounts capitalized	(50		)	(21		)	(47		)	(35		)	(144		)	(78		)
Other income (expense), net	(1		)	2			3			2			3			3
Total other income and (expense)	(51		)	(19		)	(44		)	(33		)	(141		)	(75		)
Earnings Before Income Taxes	14			28			115			101			195			187
Income taxes (benefit)	(52		)	(23		)	(39		)	(102		)	(129		)	(167		)
Net Income	66			51			154			203			324			354
Less: Net income (loss) attributable to noncontrolling interests	(4		)	1
Less: Net income attributable to noncontrolling interests							30			27			48			39
Net Income Attributable to Southern Power	$	70		$	50		$	124		$	176		$	276		$	315

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)


	For the Three Months Ended March 31,					For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2017			2016		2017			2016			2017			2016
	(in millions)					(in millions)						(in millions)
Net Income	$	66		$	51	$	154		$	203		$	324		$	354
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(4) and $-, respectively	(8		)	—
Reclassification adjustment for amounts included in net income, net of tax of $(3) and $-, respectively	(4		)	1
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)	(12		)	1		5			22			(10		)	12
Less: Comprehensive income (loss) attributable to noncontrolling interests	(4		)	1
Comprehensive Income						159			225			314			366
Less: Comprehensive income attributable to noncontrolling interests						30			27			48			39
Comprehensive Income Attributable to Southern Power	$	58		$	51	$	129		$	198		$	266		$	327

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

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	For the Three Months Ended March 31,						For the Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Operating Activities:
Net income	$	66		$	51		$	324		$	354
Adjustments to reconcile net income to net cash provided from (used for) operating activities —
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	127			75			404			262
Deferred income taxes	36			(132		)	240			(668		)
Amortization of investment tax credits	(14		)	(7		)	(42		)	(25		)
Deferred revenues	(27		)	(26		)
Collateral deposits							(1		)	(80		)
Income taxes receivable, non-current							(42		)	—
Other, net	5			9			(2		)	19
Changes in certain current assets and liabilities —
-Receivables	(7		)	(3		)	(77		)	(82		)
-Prepaid income taxes	(21		)	(31		)
-Other current assets	(6		)	1			38			(15		)
-Accounts payable	(38		)	(12		)	(31		)	7
-Accrued taxes	(40		)	(37		)	79			483
-Other current liabilities	15			2			5			14
Net cash provided from (used for) operating activities	96			(110		)
Net cash provided from operating activities							895			269
Investing Activities:
Business acquisitions	(1,020		)	(114		)	(1,032		)	(1,134		)
Property additions	(69		)	(767		)	(218		)	(1,702		)
Change in construction payables	(125		)	31			(166		)	(69		)
Payments pursuant to LTSAs	(31		)	(25		)	(99		)	(58		)
Investment in restricted cash	(13		)	(289		)	(16		)	(750		)
Distribution of restricted cash	26			292			33			746
Other investing activities	(3		)	(1		)	7			(41		)
Net cash used for investing activities	(1,235		)	(873		)	(1,491		)	(3,008		)
Financing Activities:
Increase in notes payable, net	171			276
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	(18		)	(4		)	(89		)	(22		)
Capital contributions from noncontrolling interests	71			131			79			367
Purchase of membership interests from noncontrolling interests	—			(129		)	—			(129		)
Payment of common stock dividends	(79		)	(68		)	(238		)	(204		)
Other financing activities	(12		)	—			(27		)	(14		)
Net cash provided from financing activities	133			206
Net cash provided from (used for) financing activities							(325		)	3,000
Net Change in Cash and Cash Equivalents	(1,006		)	(777		)	(921		)	261
Cash and Cash Equivalents at Beginning of Period	1,099			830			1,099			830
Cash and Cash Equivalents at End of Period	$	93		$	53		$	178		$	1,091
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $2 and $10 capitalized for 2017 and 2016, respectively)	$	28		$	15
Interest (net of $7 and $32 capitalized for 2017 and 2016, respectively)							$	144		$	49
Income taxes, net	(1		)	188			(343		)	71
Noncash transactions — Accrued property additions at end of period	53			262			16			210

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

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


Assets	At March 31, 2017		At December 31, 2016		At September 30, 2017		At December 31, 2016
	(in millions)				(in millions)
Current Assets:
Cash and cash equivalents	$	93	$	1,099	$	178	$	1,099
Receivables —
Customer accounts receivable	111		102		148		102
Other accounts receivable	32		34
Other					61		34
Affiliated	62		57		74		57
Fossil fuel stock	14		15		15		15
Materials and supplies	343		337		351		337
Prepaid income taxes	95		74		51		74
Other current assets	31		39		26		39
Total current assets	781		1,757		904		1,757
Property, Plant, and Equipment:
In service	13,493		12,728		13,734		12,728
Less: Accumulated provision for depreciation	1,598		1,484		1,823		1,484
Plant in service, net of depreciation	11,895		11,244		11,911		11,244
Construction work in progress	328		398		425		398
Total property, plant, and equipment	12,223		11,642		12,336		11,642
Other Property and Investments:
Intangible assets, net of amortization of $28 and $22 at March 31, 2017 and December 31, 2016, respectively	430		436
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	430		436		417		436
Deferred Charges and Other Assets:
Prepaid LTSAs	120		101		77		101
Accumulated deferred income taxes	570		594		400		594
Income taxes receivable, non-current					53		11
Other deferred charges and assets — affiliated	26		13		6		13
Other deferred charges and assets — non-affiliated	531		626		455		615
Total deferred charges and other assets	1,247		1,334		991		1,334
Total Assets	$	14,681	$	15,169	$	14,648	$	15,169

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

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


Liabilities and Stockholders' Equity	At March 31, 2017		At December 31, 2016		At September 30, 2017		At December 31, 2016
	(in millions)				(in millions)
Current Liabilities:
Securities due within one year	$	560	$	560	$	864	$	560
Notes payable	380		209		120		209
Accounts payable —
Affiliated	76		88		93		88
Other	129		278		84		278
Accrued taxes —
Accrued income taxes	48		148		101		148
Other accrued taxes	13		7		30		7
Accrued interest	47		36		36		36
Acquisitions payable	—		461		—		461
Contingent consideration	14		46		15		46
Other current liabilities	69		70		58		70
Total current liabilities	1,336		1,903		1,401		1,903
Long-term Debt	5,088		5,068		4,946		5,068
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	157		152		191		152
Accumulated deferred investment tax credits	1,879		1,839
Accumulated deferred ITCs					1,900		1,839
Asset retirement obligations	67		64		76		64
Other deferred credits and liabilities	288		304		232		304
Total deferred credits and other liabilities	2,391		2,359		2,399		2,359
Total Liabilities	8,815		9,330		8,746		9,330
Redeemable Noncontrolling Interests	164		164		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	3,671		3,671		3,661		3,671
Retained earnings	714		724		762		724
Accumulated other comprehensive income	24		35		25		35
Total common stockholder's equity	4,409		4,430		4,448		4,430
Noncontrolling interests	1,293		1,245		1,395		1,245
Total stockholders' equity	5,702		5,675		5,843		5,675
Total Liabilities and Stockholders' Equity	$	14,681	$	15,169	$	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

~~FIRST~~THIRD QUARTER 2017 vs. ~~FIRST~~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.~~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 ~~three~~nine months ended ~~March 31,~~September 30, 2017, Southern Power acquired or completed the construction of, and placed in service, approximately ~~396~~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 ~~construction of approximately 447~~Mankato natural gas facility by 345 MWs of ~~additional solar and natural gas facilities, of which 102 MWs from a solar facility were placed in service subsequent to March 31, 2017.~~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 ~~March 31,~~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

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$20 40.0

Net income attributable to Southern Power for the ~~first~~third quarter 2017 was ~~$70~~$124 million compared to ~~$50~~$176 million for the corresponding period in 2016. The ~~increase~~decrease was primarily due to ~~increased federal~~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 ~~renewable energy sales, partially offset by increases in depreciation, operations and maintenance expenses, and~~ interest expense from debt issuances ~~primarily related~~ 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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

"Construction Projects" of Southern Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein.

Operating Revenues

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$135 42.9

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. To~~market and, to the extent ~~Southern Power (excluding its subsidiaries) has capacity not contracted under a PPA,~~the generation assets are part of the IIC, as approved by the FERC, it may sell power into the power pool.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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 ~~electricity~~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 ~~for electricity~~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~~"Power Sales ~~Agreements"~~Agreements" herein for additional information regarding Southern Power's PPAs.

Details of Southern Power's operating revenues were as follows:

First Quarter 2017 First Quarter 2016
(in millions)
PPA capacity revenues $ 148
$ 124
PPA energy revenues 198
117
Total PPA revenues 346
241
Non-PPA revenues 101
71
Other revenues 3
3
Total operating revenues $ 450
$ 315

In the first quarter 2017, total operating revenues were $450 million, reflecting a $135 million, or 43%, increase from the corresponding period in 2016. The increase in operating revenues was primarily due to the following:

~~PPA capacity revenues increased $24 million, or 19%, primarily due to new PPAs related to natural gas facilities and additional customer load requirements.~~

PPA energy revenues increased $81 million, or 69%, due to a $60 million increase in renewable energy sales primarily from new solar and wind facilities and a $21 million increase in energy sales primarily from new natural gas PPAs. Overall, total KWH sales under PPAs increased 32% in the first quarter 2017 when compared to the corresponding period in 2016.

~~Non-PPA revenues increased $30 million, or 42%, primarily due to a 62% increase in short-term KWH sales to the wholesale market from Southern Power's natural gas facilities.~~



	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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

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:


	First Quarter 2017	First Quarter 2016	Third Quarter 2017	Third Quarter 2016	Year-to-Date 2017	Year-to-Date 2016
	(in billions of KWHs)		(in billions of KWHs)
Generation	9.7	7.7	12.5	11.1	33.2	27.9
Purchased power	0.9	0.6	1.2	0.9	3.4	2.5
Total generation and purchased power	10.6	8.3	13.7	12.0	36.6	30.4
Total generation and purchased power excluding solar, wind, and tolling agreements	4.9	5.3

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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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:


	First Quarter 2017 vs. First Quarter 2016			Third Quarter 2017 vs. Third Quarter 2016			Year-to-Date 2017 vs. Year-to-Date 2016
	(change in millions)		(% change)	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	41	45.1	$	35	22.7	$	119	34.9
Purchased power	11		57.9	10		30.3	37		48.7
Total fuel and purchased power expenses	$	52		$	45		$	156

In the ~~first~~third quarter 2017, total fuel and purchased power expenses increased ~~$52~~$45 million, or ~~47%~~24.1%, compared to the corresponding period in 2016. Fuel expense increased ~~$41~~$35 million primarily due to a ~~$54~~$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 ~~$13~~$19 million decrease in the volume of KWHs ~~generated.~~generated, excluding solar, wind, and tolling agreements. Purchased power expense increased ~~$11~~$37 million due to a $9$28 million increase in the volume of KWHs purchased and a $2$9 million increase associated with the average cost of purchased power.

Other Operations and Maintenance Expenses

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$13 16.5

In the ~~first~~third quarter 2017, other operations and maintenance expenses were ~~$92~~$83 million compared to ~~$79~~$81 million for the corresponding period in 2016. The increase was primarily due to a ~~$16~~$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.

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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 ~~a $4~~an $8 million increase associated with employee compensation and expenses in support of Southern Power's overall growth strategy, partially offset by a $7$22 million decrease in scheduled outage ~~and~~ maintenance ~~expenses.~~

~~Depreciation~~expenses and ~~Amortization~~

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$46 63.0

In the first quarter 2017, depreciation and amortization was $119 million compared to $73 million for the corresponding period in 2016. The increase was primarily related to new solar, wind, and gas facilities placed in service.

~~Interest Expense, net of Amounts Capitalized~~

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$29 138.1

In the first quarter 2017, interest expense, net of amounts capitalized was $50 million compared to $21 million for the corresponding period in 2016. The increase was primarily due to an increase of $21 million in interest expense related to additional debt issued in 2016, primarily to fund Southern Power's growth strategy and continuous construction program, as well as an $8 million decrease in ~~capitalized interest associated with the construction of solar facilities which were placed in service.~~

~~Other Income (Expense), Net~~

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$(3) (150.0)

In the first quarter 2017, other income (expense), net was $(1) million compared to $2 million for the corresponding period in 2016. The change includes a $17 million currency loss arising from translation of €1.1 billion euro-denominated fixed-rate notes into U.S. dollars, fully offset by a $17 million gain on the foreign currency hedge that was reclassified from accumulated OCI into earnings. See Note (H) to the Condensed Financial Statements herein for additional information.

~~Income Taxes (Benefit)~~

First Quarter 2017 vs. First Quarter 2016
(change in millions) (% change)
$(29) 126.1

In the first quarter 2017, income tax benefit was $52 million compared to $23 million for the corresponding period in 2016. The change was primarily due to a $30 million increase in wind PTC benefits, a $9 million increase resulting from state apportionment rate changes,non-outage operations and a $4 million increase related to lower pre-tax earnings, partially offset by a $12 million decrease in ITC benefits. See Note (G) to the Condensed Financial Statements herein for additional information.maintenance expenses.

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Depreciation and Amortization

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

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

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

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)

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 ~~economic growth. The~~the pace of economic growth ~~and electricity demand~~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 ~~units~~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 ~~March 31,~~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. ~~As part of its planned reconsideration,~~On September 18, 2017, the EPA ~~also announced it is~~

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~~administratively staying~~ the compliance deadlines for certain effluent limitations and pretreatment standards under the ~~rule and will conduct additional rulemaking to that effect.~~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 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 ~~matter~~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.

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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 ~~three~~nine months ended ~~March 31,~~September 30, 2017, in accordance with Southern Power's overall growth strategy, ~~Southern Renewable Partnerships, LLC (SRP),~~ one of Southern Power's wholly-owned subsidiaries acquired the ~~Bethel wind facility.~~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 ~~amount~~amounts of revenue and net income recognized by Southern Power related to the Bethel facility included in ~~the~~Southern Power's condensed consolidated statements of income ~~during the first quarter~~for year-to-date 2017 is $4 million. The aggregate amount of net income, excluding impacts from PTCs, recognized by Southern Power during the three months ended March 31, 2017 included in the condensed consolidated statements of income waswere 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, representing 10% of the membership interests, in Southern Turner Renewable Energy, LLC and repaid $14 million of 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 ~~three~~nine months ended ~~March 31,~~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 ~~March 31,~~September 30, 2017, total costs of construction incurred for these ~~three~~ projects were ~~$401~~$494 million, of which ~~$203~~$122 million remained in ~~CWIP for the Lamesa and Mankato facilities acquired in 2016.~~CWIP. Total aggregate construction costs, excluding the acquisition costs, are expected to be ~~$530~~between $360 million ~~to $590~~and $415 million for ~~these two facilities that were under construction at March 31, 2017.~~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
~~Project~~Projects Completed During the ~~Three~~Nine Months Ended ~~March 31,~~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 ~~March 31,~~September 30, 2017
~~Lamesa~~ Cactus Flats^(*)	~~Solar~~Wind	~~102~~148	~~Dawson~~Concho County, TX	~~April 2017~~Third quarter 2018	~~City of Garland, Texas~~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, ~~SRP~~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.

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.

Theultimateoutcomeofsuchpendingorpotentiallitigation~~againstSouthern Power~~ or regulatory matters cannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatements

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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

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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.

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. Southern Power's ongoing evaluation of revenue streams and related contracts includes the evaluation of identified revenue streams tied to longer term contractual arrangements, such as certain capacity 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 Topic 840).

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Power must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. 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 ~~elected~~restated; however, a ~~transition method~~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 ~~ultimate~~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 ~~of the new standard has not yet been determined.~~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 ~~March 31,~~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 ~~$96~~$895 million for the first ~~three~~nine months of 2017 compared to ~~net cash used for operating activities of $110~~$269 million for the first ~~three~~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 ~~renewable~~ energy sales arising from new solar and wind facilities, ~~and a decrease in income taxes paid,~~ 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 ~~$1.2~~$1.5 billion for the first ~~three~~nine months of 2017 primarily due to payments for renewable acquisitions and the construction of ~~renewable~~generating facilities. ~~See FUTURE EARNINGS POTENTIAL~~ – "~~Acquisitions" and "Construction Projects" herein for additional information.~~ Net cash ~~provided from~~used for financing activities totaled ~~$133~~$325 million for the first ~~three~~nine months of 2017 primarily due to ~~an increase~~common stock dividend payments, a decrease in notes payable, and ~~contributions from~~distributions to noncontrolling interests, partially offset by ~~dividends to Southern Company and distributions to~~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 ~~three~~nine months of 2017 include a $1.0 billion ~~decrease in cash and cash equivalents and a $765 million~~ increase in property, plant, and equipment in-service primarily related to acquisitions, as well as a $70 million decrease in CWIP primarily due to East Pecos being placed in service, partially offset by equipment purchased for wind projects. See FUTURE EARNINGS POTENTIAL – "~~Acquisitions" and "Construction Projects" herein for additional information.~~

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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 ~~$560~~$864 million will be required to repay maturities of long-term debt through ~~March 31,~~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 ~~sometimes exceed~~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 ~~construction payables, as well as~~ fluctuations in cash needs, due to both seasonality and the stage of acquisitions and construction projects. ~~In 2017, Southern Power expects to utilize the debt capital markets, bank term loans, and commercial paper markets as the source of funds for the majority of its debt maturities.~~

~~As of March 31, 2017, Southern Power had cash and cash equivalents of approximately $93 million.~~

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, ~~and~~ for general corporate purposes, ~~including~~and to finance maturing debt. ~~Southern Power's subsidiaries are not borrowers under~~Commercial paper is included in notes payable on the ~~commercial paper program.~~condensed consolidated balance sheet at September 30, 2017.

~~Details of commercial paper were as follows:~~


~~(*)~~	~~Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2017.~~

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Table of Contents

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Company Credit Facility~~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 ~~March 31,~~September 30, 2017, Southern Power had a committed credit facility (Facility) of ~~$600~~$750 million, ~~expiring in 2020,~~ of which ~~$76~~$22 million has been used for letters of credit and ~~$524~~$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 ~~subsidiaries are not borrowers~~borrowing ability under ~~the Facility.~~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~~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.

~~In December 2016,~~ Southern Power ~~entered into an agreement for~~also has a $120 million continuing letter of credit facility for standby letters of credit expiring in 2019. At ~~March 31,~~September 30, 2017, ~~the total amount available~~$111 million has been used for letters of credit and $9 million remains unused.

Southern Power's subsidiaries do not borrow under the ~~facility was $67 million. Southern Power's subsidiaries~~commercial paper program and are not parties to, and do not borrow under, the ~~facility.~~

~~Subsidiary Project Credit~~ Facility

~~In connection with~~ or the ~~construction of the Roserock facility, RE Roserock LLC, an~~ ~~indirect subsidiary of Southern Power, entered into a credit agreement (Project Credit Facility), which was non-recourse to Southern Power (other than the subsidiary party to the agreement).~~ ~~The Project Credit Facility provided (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured~~continuing letter of credit ~~facility that was secured by the membership interests of RE Roserock LLC, with proceeds directed to finance project costs related to the solar~~ facility. ~~The Project Credit Facility was secured by the assets and membership interests of RE Roserock LLC.~~

~~The Project Credit Facility was fully repaid on January 31, 2017.~~ For the three-month period ended March 31, 2017, the Project Credit Facility had a maximum amount outstanding of $209 million and an average amount outstanding of $70 million at a weighted average interest rate of 2.1%.

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, ~~transmission,~~ and ~~foreign currency risk management.~~transmission.

~~143~~168

Table of Contents

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The maximum potential collateral requirements under these contracts at ~~March 31,~~September 30, 2017 were as follows:


Credit Ratings	Maximum Potential Collateral Requirements		Maximum Potential Collateral Requirements
	(in millions)		(in millions)
At BBB and/or Baa2	$	38	$	37
At BBB- and/or Baa3	$	409	$	398
At BB+ and/or Ba1^(*)	$	1,188	$	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 ~~did not issue or redeem any securities during~~amended its $60 million aggregate principal amount floating rate bank loan to, among other things, increase the ~~three months ended March 31, 2017.~~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.

SOUTHERN COMPANY GAS

AND SUBSIDIARY COMPANIES

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)


	Successor			Predecessor			Successor												Predecessor
	For the Three Months Ended March 31,			For the Three Months Ended March 31,			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			2017			2016			2016
	(in millions)			(in millions)			(in millions)												(in millions)
Operating Revenues:
Natural gas revenues (includes revenue taxes of $48 and $40 for the periods presented, respectively)	$	1,530		$	1,302
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	30			32			33			25			95			25			64
Total operating revenues	1,560			1,334			565			543			2,841			543			1,905
Operating Expenses:
Cost of natural gas	719			571			134			133			1,085			133			755
Cost of other sales	7			7			7			2			20			2			14
Other operations and maintenance	253			241			205			216			671			216			454
Depreciation and amortization	120			102			125			116			370			116			206
Taxes other than income taxes	70			62			26			29			140			29			99
Merger-related expenses	—			3			—			35			—			35			56
Total operating expenses	1,169			986			497			531			2,286			531			1,584
Operating Income	391			348			68			12			555			12			321
Other Income and (Expense):
Earnings from equity method investments	39			1			32			29			100			29			2
Interest expense, net of amounts capitalized	(46		)	(48		)	(51		)	(39		)	(145		)	(39		)	(96		)
Other income (expense), net	5			3			18			9			26			9			5
Total other income and (expense)	(2		)	(44		)	(1		)	(1		)	(19		)	(1		)	(89		)
Earnings Before Income Taxes	389			304			67			11			536			11			232
Income taxes	150			111			52			7			233			7			87
Net Income	239			193			15			4			303			4			145
Less: Net income attributable to noncontrolling interest	—			11			—			—			—			—			14
Net Income Attributable to Southern Company Gas	$	239		$	182		$	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.

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

Successor Predecessor
For the Three Months Ended March 31, For the Three Months Ended March 31,
2017 2016
(in millions) (in millions)
Net Income $ 239
$ 193
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1) and $(16), respectively (1 ) (29 )
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 $2, respectively (1 ) 3
Total other comprehensive income (loss) (2 ) (27 )
Less: Comprehensive income attributable to noncontrolling interest —
11
Comprehensive Income Attributable to Southern Company Gas $ 237
$ 155



	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.

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	Successor			Predecessor			Successor						Predecessor
	For the Three Months Ended March 31,			For the Three Months Ended March 31,			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)			(in millions)						(in millions)
Operating Activities:
Net income	$	239		$	193		$	303		$	4		$	145
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	120			102			370			116			206
Deferred income taxes	46			14			265			(30		)	8
Pension, postretirement, and other employee benefits	(6		)	1			(4		)	(123		)	5
Stock based compensation expense	11			5			25			11			20
Hedge settlements							—			(35		)	(26		)
Mark-to-market adjustments	(82		)	5			(32		)	17			162
Other, net	21			(11		)	(67		)	(47		)	(82		)
Changes in certain current assets and liabilities —
-Receivables	117			34			534			(18		)	181
-Natural gas for sale, net of temporary LIFO liquidation	411			363			—			(222		)	273
-Prepaid income taxes	24			151			(7		)	1			151
-Other current assets	19			27			(42		)	(36		)	37
-Accounts payable	(216		)	(64		)	(169		)	78			43
-Accrued taxes	19			84			(24		)	(11		)	41
-Accrued compensation	(14		)	(46		)	(11		)	(36		)	(21		)
-Other current liabilities	49			(17		)	8			(11		)	(30		)
Net cash provided from operating activities	758			841
Net cash provided from (used for) operating activities							1,149			(342		)	1,113
Investing Activities:
Property additions	(301		)	(222		)	(1,093		)	(287		)	(509		)
Cost of removal, net of salvage	(11		)	(15		)	(45		)	(21		)	(32		)
Change in construction payables, net	(12		)	2			49			9			(7		)
Investment in unconsolidated subsidiaries	(81		)	(5		)	(128		)	(1,421		)	(14		)
Returned investment in unconsolidated subsidiaries							22			2			3
Other investing activities	—			2			3			3			—
Net cash used for investing activities	(405		)	(238		)	(1,192		)	(1,715		)	(559		)
Financing Activities:
Decrease in notes payable, net	(234		)	(453		)
Redemptions and repurchases — First mortgage bonds	—			(75		)
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		)	—			—			(19		)
Payment of common stock dividends	(111		)	(64		)	(332		)	(63		)	(128		)
Other financing activities	1			9			(7		)	(8		)	10
Net cash used for financing activities	(344		)	(602		)
Net cash provided from (used for) financing activities							45			2,090			(558		)
Net Change in Cash and Cash Equivalents	9			1			2			33			(4		)
Cash and Cash Equivalents at Beginning of Period	19			19			19			15			19
Cash and Cash Equivalents at End of Period	$	28		$	20		$	21		$	48		$	15
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $3 and $1 capitalized for 2017 and 2016, respectively)	$	41		$	53
Interest (net of $9, $2, and $3 capitalized, respectively)							$	146		$	86		$	119
Income taxes, net	—			(132		)	17			54			(100		)
Noncash transactions — Accrued property additions at end of period	53			51			112			50			41

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

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


Assets	At March 31, 2017			At December 31, 2016			At September 30, 2017			At December 31, 2016
	(in millions)						(in millions)
Current Assets:
Cash and cash equivalents	$	28		$	19		$	21		$	19
Receivables —
Energy marketing receivable	493			623
Energy marketing receivables							427			623
Customer accounts receivable	453			364			221			364
Unbilled revenues	173			239			61			239
Other accounts and notes receivable	69			76			61			76
Accumulated provision for uncollectible accounts	(37		)	(27		)	(26		)	(27		)
Materials and supplies	25			26			24			26
Natural gas for sale	346			631			631			631
Prepaid income taxes	—			24
Prepaid expenses	54			55			103			80
Assets from risk management activities, net of collateral	138			128			103			128
Other regulatory assets, current	60			81			96			81
Other current assets	16			11			25			10
Total current assets	1,818			2,250			1,747			2,250
Property, Plant, and Equipment:
In service	14,660			14,508			15,383			14,508
Less: Accumulated depreciation	4,498			4,439			4,567			4,439
Plant in service, net of depreciation	10,162			10,069			10,816			10,069
Construction work in progress	625			496			596			496
Total property, plant, and equipment	10,787			10,565			11,412			10,565
Other Property and Investments:
Goodwill	5,967			5,967			5,967			5,967
Equity investments in unconsolidated subsidiaries	1,604			1,541			1,609			1,541
Other intangible assets, net of amortization of $60 and $34 at March 31, 2017 and December 31, 2016, respectively	340			366
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			21			21
Total other property and investments	7,932			7,895			7,897			7,895
Deferred Charges and Other Assets:
Other regulatory assets, deferred	958			973			944			973
Other deferred charges and assets	188			170			190			170
Total deferred charges and other assets	1,146			1,143			1,134			1,143
Total Assets	$	21,683		$	21,853		$	22,190		$	21,853

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

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


Liabilities and Stockholder's Equity	At March 31, 2017		At December 31, 2016			At September 30, 2017			At December 31, 2016
	(in millions)					(in millions)
Current Liabilities:
Securities due within one year	$	22	$	22		$	—		$	22
Notes payable	1,023		1,257			934			1,257
Energy marketing trade payables	471		597			451			597
Accounts payable	241		348			368			348
Customer deposits	131		153			137			153
Accrued taxes —
Accrued income taxes	50		26			—			26
Other accrued taxes	63		68			70			68
Accrued interest	59		48			66			48
Accrued compensation	43		58			46			58
Liabilities from risk management activities, net of collateral	18		62			28			62
Other regulatory liabilities, current	148		102			126			102
Accrued environmental remediation, current	66		69			54			69
Temporary LIFO liquidation	126		—
Other current liabilities	124		108			112			108
Total current liabilities	2,585		2,918			2,392			2,918
Long-term Debt	5,246		5,259			5,862			5,259
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	2,059		1,975			2,214			1,975
Employee benefit obligations	434		441			431			441
Other cost of removal obligations	1,630		1,616			1,656			1,616
Accrued environmental remediation, deferred	343		357			345			357
Other regulatory liabilities, deferred	54		51			35			51
Other deferred credits and liabilities	88		127			88			127
Total deferred credits and other liabilities	4,608		4,567			4,769			4,567
Total Liabilities	12,439		12,744			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	9,104		9,095			9,185			9,095
Retained earnings (accumulated deficit)	116		(12		)
Accumulated deficit						(41		)	(12		)
Accumulated other comprehensive income	24		26			23			26
Total stockholder's equity	9,244		9,109
Total common stockholder's equity						9,167			9,109
Total Liabilities and Stockholder's Equity	$	21,683	$	21,853		$	22,190		$	21,853

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

~~149~~175

Table of Contents

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 a constructive regulatory ~~environment,~~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, ~~with Southern Company~~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.

~~Investment in SNG~~

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 ~~$34~~$28 million and $86 million from this investment in the ~~first~~successor third quarter ~~2017.~~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.

~~Other Matters~~

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.

176

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SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Operating Metrics

Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Operating Metrics" of Southern Company Gas in Item 7 of the Form 10-K.

~~Heating Degree Days~~

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

~~150~~

~~Table of Contents~~

~~SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES~~

~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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 ~~all of the earnings upside in the event of colder-than-normal weather for gas distribution operations in Illinois and~~ most of the earnings ~~upside for gas marketing services. The following table presents the Heating Degree Days information for Illinois and Georgia.~~

First Quarter 2017 vs. 2016 2017 vs. normal

Normal^(a)
2017 2016 (warmer) (warmer)
Illinois^(b)
3,121
2,560
2,701
(5 )% (18 )%
Georgia 1,499
925
1,334
(31 )% (38 )%


~~(a)~~	Normal represents the 10-year average from January 1, 2007 through March 31, 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 2,902 for the first three months from 1998 through 2007.~~

For the successor first quarter 2017, weather in Illinois was 18% warmer than normal and 5% warmer than the predecessor first quarter 2016. Southern Company Gas hedged its exposure at Nicor Gas to warmer-than-normal weather for the first quarter 2017 and 2016; therefore, the weather-related negative pre-tax income impact on gas distribution operations was limited to $6 million for both the successor first quarter 2017 and the predecessor first quarter 2016.

For the successor first quarter 2017, weather in Georgia was 38% warmer than normal and 31% warmer than the predecessor first quarter 2016. Southern Company Gas hedged its exposure at gas marketing services to warmer-than-normal weather for the first quarter 2017 and 2016; therefore, the weather-related negative pre-tax income impact on gas marketing services was limited to $7 million for the successor first quarter 2017. For the predecessor first quarter 2016, the positive weather-related pre-tax income impact on gas marketing services was $1 million as a result of the hedging program.

~~Customer Count~~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. ~~The following table provides the number of customers served by Southern Company Gas at March 31, 2017 and 2016.~~

March 31,
2017 2016 2017 vs. 2016
(in thousands, except market share %) (% change)
Gas distribution operations 4,618
4,594
0.5 %
Gas marketing services
Energy customers 661
662
(0.2 )%
Market share of energy customers in Georgia 29.3 % 29.3 %
Service contracts 1,197
1,204
(0.6 )%

Southern Company Gas anticipates overall customer growth trends at gas distribution operations to continue in 2017, as it expects continued improvement in the new housing market and low natural gas prices.

Gas marketing services' market share in Georgia was flat at March 31, 2017 compared to March 31, 2016 despite the highly competitive marketing environment, which Southern Company Gas expects 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.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~Volumes of Natural Gas Sold~~

Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services ~~as shown in the following table,~~ illustrate the effects of ~~warm~~ weather and ~~low~~ customer demand for natural ~~gas compared to the prior year.~~gas. Wholesale gas services' physical sales volumes represent the daily average natural gas volumes sold to its customers.

First Quarter 2017 vs. 2016
2017 2016 % Change
Gas distribution operations (mmBtu in millions)

Firm 263
289
(9.0 )%
Interruptible 25
26
(3.8 )%
Total 288
315
(8.6 )%
Gas marketing services (mmBtu in millions)

Firm:
Georgia 12
17
(29.4 )%
Illinois 5
6
(16.7 )%
Other emerging markets 5
5
— %
Interruptible:
Large commercial and industrial 4
4
— %
Total 26
32
(18.8 )%
Wholesale gas services (mmBtu in millions/day)

Daily physical sales 6.7
7.9
(15.2 )%

Seasonality of Results

~~During~~Heating Season is the ~~months of~~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 ~~during a~~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 ~~successor first~~third quarter 2017 compared to $4 million for the corresponding period in 2016. This increase was ~~$239 million. As~~primarily due to $11 million of additional income from infrastructure replacement programs and base rate increases, net of associated depreciation, and a ~~result~~$7 million gain from the settlement of ~~purchasing the remaining interest in SouthStar in October 2016, all~~contractor litigation claims, partially offset by $12 million lower net income was attributable to Southern Company Gas in the successor period. Net income was positively impacted by $3 million due to the pushdown of acquisition accounting related to the Merger. Net income for the successor period included $15 million in after-tax earnings from the SNG investment, net of related interest expense, as well as $29 million and $48 million in after-tax mark-to-market gains from derivative instruments and revenue from commercial activity, respectively, at wholesale gas ~~services driven by changes~~services. Also contributing to the increase was $24 million in ~~natural gas price volatility. Also reflected~~Merger-related expenses in net income for this period was an increase of $11 million, after-tax, from additional infrastructure replacement programs at gas distribution operations and a base rate increase at Atlanta Gas Light effective March 1, 2017,the third quarter 2016, partially offset by ~~a reduction~~$23 million of ~~$8 million, after-tax, resulting from warmer-than-normal weather, net of hedging.~~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 ~~predecessor first quarter 2016~~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 ~~$182 million.~~ $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 ~~SouthStar for~~ 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 $11 million. Net income of $193 million for the predecessor period reflected $12 million and $26 million in after-tax mark-to-market gains from derivative instruments and commercial activity revenue, respectively, at wholesale gas services dueattributable to ~~changes in natural gas price volatility~~Southern Company Gas in the ~~period, partially offset by a decrease of $3 million, after-tax, attributable to warmer-than-normal weather, net of hedging.~~successor periods.

Natural Gas Revenues

~~Natural~~



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 ~~successor first quarter 2017 and~~corresponding period in 2016.

Details of the ~~predecessor first quarter 2016 were $1.5 billion and $1.3 billion, respectively.~~

Natural gas revenues for the successor first quarter 2017 included a $5 million favorable impact from fair value adjustments to certain assets and liabilities in the application of acquisition accounting for gas marketing services and wholesale gas services as well as $48 million and $80 million in mark-to-market gains from derivative instruments and revenue from commercial activity, respectively, at wholesale gas services driven by changes in natural gas ~~price volatility. Natural gas~~ revenues ~~also reflect the~~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 ~~cost of~~ natural gas ~~discussed below, $19 million in additional revenues generated from~~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 ~~a rate increase that became effective~~the positive impact from the amortization of assets established in ~~March 2017 for Atlanta Gas Light,~~the application of acquisition accounting at gas marketing services. These increases were partially offset by ~~decreases in revenues of $13 million attributable to warmer-than-normal weather, net of hedging.~~

Natural gas revenues for the predecessor first quarter 2016 reflected $20 million and $43 million in mark-to-market gains from derivative instruments and revenue from commercial activity, respectively, at wholesale gas services driven by changes in natural gas price volatility, partially offset by decreases in revenues of $5 million attributable to warmer-than-normal weather, net of hedging.

Natural gas distribution rates include provisions to adjust billings for fluctuation 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~~

Cost of natural gas was $719 million for the successor first quarter 2017 and $571 million for the predecessor first quarter 2016, which primarily reflected an increase of 54% in natural gas prices during the first quarter 2017 compared to the prior period, along with lower demand for natural gas driven by warmer-than-normal weather. See OVERVIEW – "Operating Metrics – Heating Degree Days" herein for additional information regarding the effects of weather.

~~Other Operations and Maintenance Expenses~~

Other operations and maintenance expenses were $253 million for the successor first quarter 2017 and $241 million for the predecessor first quarter 2016. Other operations and maintenance expense for the successor period reflected additional compensation expense in the period due to the timing of accruals and increased pipeline compliance and maintenance activities, partially offset by low bad debt expense as a result of warmer-than-normal weather.

~~Depreciation and Amortization~~

Depreciation and amortization was $120 million for the successor first quarter 2017 and $102 million for the predecessor first quarter 2016. Included in depreciation and amortization for the successor first quarter 2017 was $10 million of additional amortization of intangible assets as a result of fair value adjustments in acquisition accounting, as well as additional depreciation at gas distribution operations due to an $879 million increase in gross property, plant, and equipment since March 31, 2016.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.

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

~~For~~



Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)		(% change)
$(3)		(10.3)

In the ~~successor first~~third quarter 2017, ~~and the predecessor first quarter 2016,~~ taxes other than income taxes were ~~$70~~$26 million ~~and $62~~compared to $29 million ~~respectively, which consisted~~for the corresponding period in 2016. The decrease primarily ~~of revenue tax expenses, property taxes, and payroll taxes.~~ 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 ~~period~~periods reflected increased revenue-based taxes due to higher revenues at gas distribution operations induring the ~~period.~~successor periods.

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Earnings from Equity Method Investments

~~For~~



Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)		(% change)
$3		10.3

In the ~~successor first~~third quarter 2017, earnings from equity method investments were ~~$39~~$32 million ~~which~~compared to $29 million for the corresponding period in 2016. The increase was primarily ~~consists~~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 ~~$34~~$86 million in earnings from SNG and $3$14 million in earnings from ~~PennEast Pipeline. For the predecessor first quarter 2016, earnings from equity method investments were not material.~~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~~"Southern Company Gas – Equity Method ~~Investments"~~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

~~For~~



Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)		(% change)
$12		30.8

In the ~~successor first~~third quarter 2017, interest expense, net of amounts capitalized was ~~$46~~$51 million ~~reflecting~~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, ~~reduction~~respectively, resulting from the fair value adjustment of long-term debt in acquisition ~~accounting, partially offset by additional interest expense on new debt issuances in 2016.~~

~~For the predecessor first quarter 2016, interest expense, net of amounts capitalized, was $48 million.~~accounting.

Income Taxes

~~For~~



Successor
Third Quarter 2017 vs. Third Quarter 2016
(change in millions)		(% change)
$45		N/M

N/M - Not meaningful

In the ~~successor first~~third quarter 2017, income taxes were ~~$150~~$52 million ~~driven by~~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.

~~For the predecessor first quarter 2016,~~



	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 ~~were $111 million.~~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 ~~first quarter~~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 ~~first quarter~~third quarters 2017 and 2016 and the successor year-to-date 2017 is useful as it allows for a measure of comparability to ~~the~~ 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 ~~respectively,~~ 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

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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			Successor												Predecessor
	First Quarter 2017			First Quarter 2016			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)			(in millions)												(in millions)
Operating Income	$	391		$	348		$	68		$	12		$	555		$	12		$	321
Other operating expenses^(a)	443			408			356			396			1,181			396			815
Revenue taxes^(b)	(47		)	(39		)	(8		)	(8		)	(74		)	(8		)	(56		)
Adjusted Operating Margin	$	787		$	717		$	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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Predecessor
First Quarter 2016
(in millions)
Consolidated Net Income Attributable to Southern Company Gas $ 182
Net income attributable to noncontrolling interest 11
Income taxes 111
Interest expense, net of amounts capitalized 48
EBIT $ 352



	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								Predecessor									Successor
	First Quarter 2017								First Quarter 2016									Third Quarter 2017									Third Quarter 2016
	Adjusted Operating			Operating			Net		Adjusted Operating			Operating						Adjusted Operating			Operating			Net Income			Adjusted Operating			Operating			Net Income
	Margin^(*)			Expenses^(*)			Income		Margin^(*)			Expenses^(*)			EBIT			Margin^(*)			Expenses^(*)			(Loss)			Margin^(*)			Expenses^(*)			(Loss)
	(in millions)								(in millions)									(in millions)									(in millions)
Gas distribution operations	$	542		$	313		$	117	$	525		$	291		$	235		$	379		$	271		$	52		$	353		$	284		$	27
Gas marketing services	105			53			31		124			44			80			51			48			1			45			51			(4		)
Wholesale gas services	131			15			68		60			17			44			(25		)	11			(23		)	(8		)	10			(11		)
Gas midstream operations	9			12			15		9			12			(1		)	12			13			14			9			13			14
All other	2			5			8		2			7			(5		)	2			8			(29		)	2			31			(22		)
Intercompany eliminations	(2		)	(2		)	—		(3		)	(2		)	(1		)	(3		)	(3		)	—			(1		)	(1		)	—
Consolidated	$	787		$	396		$	239	$	717		$	369		$	352		$	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. These agencies approve natural gas rates designed to provide Southern Company Gas the opportunity to generate revenues to recover the cost of natural gas delivered to its customers and its fixed and variable costs, such as depreciation, interest, maintenance, and overhead costs, as well as to earn a reasonable return on its investments.

With the exception of Atlanta Gas Light, Southern Company Gas' second largest utility that operates in a deregulated natural gas market and has a straight-fixed-variable rate design that minimizes the variability of its revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed. Southern Company Gas has various weather mechanisms, such as weather normalization mechanisms and weather derivative instruments, that limit its exposure to weather changes within typical ranges in its natural gas utilities' service territories.

Successor ~~first~~Third Quarter 2017 vs. Third Quarter 2016

In the third quarter 2017,

~~Net~~ 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 ~~$117 million includes $542~~$26 million in adjusted operating margin, ~~$313~~a decrease of $13 million in operating expenses, and $4an increase of $11 million in other income (expense), ~~net, which resulted~~net. The change in ~~EBIT of $233 million. Net~~net income also includes ~~$40~~an increase of $7 million in interest expense, net of amounts capitalized, and ~~$76~~an increase of $18 million in income tax expense. ~~Adjusted~~The increase in adjusted operating margin primarily reflects ~~$19~~$24 million in additional revenue from the continued investment in infrastructure replacement programs and a base rate ~~increase~~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 ~~depreciation due to continued investment~~assets placed in ~~infrastructure programs, additional employee~~service, as well as increased compensation ~~in the period due to the timing of accruals for certain~~expense, legal expenses, and ~~increased~~ 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.

~~Predecessor first quarter~~Successor Period of July 1, 2016 through September 30, 2016

~~EBIT~~Net income of ~~$235~~$27 million includes ~~$525~~$353 million in adjusted operating margin, ~~$291~~$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 $1$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 $6$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.~~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 ~~first~~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 ~~$31~~$36 million includes ~~$105~~$213 million in adjusted operating margin and ~~$53~~$149 million in operating expenses, which resulted in EBIT of ~~$52~~$64 million. Net income also includes $1$4 million in interest expense and ~~$20~~$24 million in income tax expense. As a result of purchasing the remaining interest in SouthStar in October 2016, there was no noncontrolling interest and all net income from gas marketing services was attributable to Southern Company Gas in this period. Adjusted operating margin ~~which includes gas marketing and warranty sales,~~ reflects ~~$2 million of additional revenue as~~ a ~~result of fair value adjustments to certain assets and liabilities in the application of acquisition accounting, as well as a $7~~$10 million negative impact of warmer-than-normal weather, net of hedging, and $7 million in unrealized hedge losses, ~~in the period.~~net of recoveries. Operating expenses ~~reflect $10~~include $30 million in additional amortization of intangible assets ~~due to fair value adjustments to certain assets and liabilities~~established in the application of acquisition ~~accounting,~~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 ~~reduction~~loss before interest and taxes of $6 million. Also included in ~~litigation-related expense.~~net loss is $2 million in income tax benefit.

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Predecessor ~~first quarter~~Period of January 1, 2016 through June 30, 2016

EBIT of ~~$80~~$109 million includes ~~$124~~$190 million in adjusted operating margin and ~~$44~~$81 million in operating expenses. Adjusted operating margin reflects ~~revenue from gas marketing and warranty sales, $2~~$9 million in unrealized hedge ~~gains, and a $1 million positive impact of weather, net of hedging, despite warmer-than-normal weather in the period. Operating expenses primarily reflect marketing, legal, and bad debt expenses.~~gains. Earnings in the predecessor period include ~~$11~~$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 ~~first~~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 ~~$68~~$28 million includes ~~$131~~$93 million in adjusted operating margin and ~~$15~~$40 million in operating expenses, which resulted in EBIT of ~~$116~~$53 million. ~~Also included is $2~~Net income also includes $5 million in interest expense and ~~$46~~$20 million in income tax expense. ~~Operating expenses primarily reflect employee compensation and benefits.~~

~~Predecessor first quarter~~Successor Period of July 1, 2016 through September 30, 2016

~~EBIT~~Net loss of ~~$44~~$11 million includes ~~$60~~$(8) million in adjusted operating margin ~~$17~~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. ~~Operating expenses primarily reflect employee compensation and benefits.~~

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The following table illustrates the components of wholesale gas services' adjusted operating margin for the periods presented.


	Successor		Predecessor			Successor												Predecessor
	First Quarter 2017		First Quarter 2016			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)			(in millions)												(in millions)
Commercial activity recognized	$	80	$	43		$	3		$	10		$	80		10			$	34
Gain (loss) on storage derivatives	4		(2		)	4			11			13			11			(38		)
Gain (loss) on transportation and forward commodity derivatives	44		22			(22		)	(7		)	14			(7		)	(31		)
LOCOM adjustments, net of current period recoveries	—		(3		)	—			—			—			—			(1		)
Purchase accounting adjustments to fair value inventory and contracts	3		—
Purchase accounting adjustments						(10		)	(22		)	(14		)	(22		)	—
Adjusted Operating Margin	$	131	$	60		$	(25	)	$	(8	)	$	93		$	(8	)	$	(36	)

Change in ~~commercial activity~~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. ~~Increases in natural gas supply and warmer-than-normal~~Warmer-than-normal weather during the 2016/2017 Heating Season, lower power generation volumes, and ~~the resulting higher~~build-out of new U.S. pipeline infrastructure, along with increases in natural gas ~~inventories at~~supply, caused low volatility and a tightening of locational or transportation spreads in 2017, negatively impacting the ~~end~~amount of ~~2016 caused natural gas prices~~commercial activity revenues generated relative to ~~decline in the early part of 2017.~~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, ~~largely in the first quarter 2017,~~ wholesale gas services was able to capture higher storage values that it expects to ~~accommodate the increase in~~recognize as commercial activity revenues when natural gas ~~supply. Wholesale gas services experienced low volatility in 2016 due partly to weather and~~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

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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 ~~quarter~~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 ~~continued~~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 ~~March 31,~~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						Storage withdrawal schedule
	Total storage (WACOG $2.74)	Expected net operating gains^(a)		Physical transportation transactions – expected net operating losses^(b)			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)			(in mmBtu in millions)	(in millions)		(in millions)
2017	40.3	$	14	$	(21	)	22.0	$	4	$	(13	)
2018 and thereafter	5.2	4		(23		)	40.0	17		28
Total at March 31, 2017	45.5	$	18	$	(44	)
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 ~~based on current expectations, primarily~~ will be reversed ~~during the remainder of 2017~~ 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 ~~consist of the~~include SNG, ~~interest,~~ 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 ~~first~~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 ~~$15~~$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, ~~$12~~$13 million in operating expenses, ~~$38~~$28 million in earnings from equity method investments, ~~which consists~~consisting primarily of ~~equity in~~ earnings from ~~the~~equity method

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~~investment in~~investments at SNG, and $1 million in other income (expense), net, which resulted in EBIT of ~~$36~~$25 million. Also included in net income ~~are $9 million in interest expense and $12~~is $11 million in income tax expense.

Predecessor ~~first quarter~~Period of January 1, 2016 through June 30, 2016

Loss before interest and taxes of $1$6 million includes $9$15 million in adjusted operating margin, ~~$12~~$24 million in operating expenses, and $2$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/~~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 ~~first~~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 ~~predecessor first quarter 2016, these operating expenses included Merger-related expenses~~allocation of ~~less than $1 million and $3 million, respectively.~~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 ~~first~~third quarter and year-to-date 2017, and operating income to adjusted operating margin for ~~the~~all periods presented, are in the following tables. See Note (K) to the Condensed Financial Statements herein for additional information.


	Successor															Successor
	First Quarter 2017															Third Quarter 2017
	Gas Distribution Operations		Gas Marketing Services		Wholesale Gas Services		Gas Midstream Operations		All Other			Intercompany Elimination		Consolidated		Gas Distribution Operations		Gas Marketing Services		Wholesale Gas Services			Gas Midstream Operations		All Other			Intercompany Elimination		Consolidated
	(in millions)															(in millions)
Consolidated Net Income	$	117	$	31	$	68	$	15	$	8		$	—	$	239
Income taxes	76		20		46		12		(4		)	—		150
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	40		1		2		9		(6		)	—		46		39		1		2			9		—			—		51
EBIT	$	233	$	52	$	116	$	36	$	(2	)	$	—	$	435	$	125	$	3	$	(36	)	$	32	$	(6	)	$	—	$	118

Successor
First Quarter 2017
Gas Distribution Operations Gas Marketing Services Wholesale Gas Services Gas Midstream Operations All Other Intercompany Elimination Consolidated
(in millions)
Operating Income (Loss) $ 229
$ 52
$ 116
$ (3 ) $ (3 ) $ —
$ 391
Other operating expenses^(a)
360
53
15
12
5
(2 ) 443
Revenue tax expense^(b)
(47 ) —
—
—
—
—
(47 )
Adjusted Operating Margin $ 542
$ 105
$ 131
$ 9
$ 2
$ (2 ) $ 787



	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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	Predecessor																			Successor
	First Quarter 2016																			Third Quarter 2017
	Gas Distribution Operations			Gas Marketing Services		Wholesale Gas Services		Gas Midstream Operations			All Other			Intercompany Elimination			Consolidated			Gas Distribution Operations			Gas Marketing Services		Wholesale Gas Services			Gas Midstream Operations			All Other			Intercompany Elimination			Consolidated
	(in millions)																			(in millions)
Operating Income (Loss)	$	234		$	80	$	43	$	(3	)	$	(5	)	$	(1	)	$	348		$	108		$	3	$	(36	)	$	(1	)	$	(6	)	$	—		$	68
Other operating expenses^(a)	330			44		17		12			7			(2		)	408			279			48		11			13			8			(3		)	356
Revenue tax expense^(b)	(39		)	—		—		—			—			—			(39		)	(8		)	—		—			—			—			—			(8		)
Adjusted Operating Margin	$	525		$	124	$	60	$	9		$	2		$	(3	)	$	717		$	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 ~~economic growth. The~~the pace of economic growth ~~and natural gas demand~~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,~~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.

~~For additional information relating to these issues, see "Risk Factors" of Southern Company Gas in Item 1A of the Form 10-K.~~

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~~In September 2016, Southern Company Gas acquired a 50% equity interest in SNG. See OVERVIEW – "Investment in SNG" and Note (J)~~For additional information relating to ~~the Condensed Financial Statements herein and Notes 4 and 11 to the financial statements~~these issues, see "Risk Factors" of Southern Company Gas ~~under "Equity Method Investments – SNG" and "Investment in SNG," respectively,~~ in Item 81A of the Form ~~10-K for additional information.~~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~~"Regulatory Matters – Southern Company ~~Gas"~~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. ~~Accordingly, changes~~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, and Integrated Customer Growth~~ 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 ~~Georgia PSC allowed the~~ last monthly Pipeline Replacement Program surcharge increase ~~originally scheduled for October 2017, to occur~~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 iswas based on a projected 12-month test year ending March 31, 2017 and ana ROE of 10.25%. ~~The~~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 ~~issue an order~~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 ~~filing in the third quarter 2017, after which rate adjustments will be effective.~~proposed sale of Elizabethtown Gas.

Pending Base Rate Cases

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10.7%. The Illinois Commission is expected to rule on the requested increase ~~within the 11-month statutory time limit,~~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 iswas based on a projected 12-month test year beginning September 1, 2017 and ana ROE of 10.25%. The requested increase ~~includes~~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 ~~requested increase~~proposed stipulation in the ~~first~~fourth quarter ~~2018.~~2017. Rate adjustments ~~are expected to be~~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 ~~the~~these pending base rate cases cannot be determined at this time.

Regulatory 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 ~~$24~~$178 million of qualifying assets during the first ~~quarter~~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 ~~liquefied natural gas~~LNG facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, Atlanta Gas Light invested ~~$38~~$127 million during the first ~~quarter~~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.

~~The recovery of and return on current and future capital investments under~~ Subsequently, the ~~STRIDE program will be included in the annual base rate revenue adjustment under GRAM rather than a separate surcharge. The~~ proposed capital investments associated with the extension of i-SRP were included in the 2017 annual base rate revenue under GRAM ~~that was~~ approved by the Georgia PSC on February 21, 2017.

See ~~"Base~~"Base Rate ~~Cases"~~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 $3$16 million during the first ~~quarter~~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 $7$21 million during the first ~~quarter~~nine months of 2017.

Florida City Gas

The Florida PSC approved Florida City Gas' ~~Safety, Access, and Facility Enhancement~~SAFE program in 2015. Under the program, Florida City Gas invested $3$9 million during the first ~~quarter~~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 ~~against Southern Company Gas~~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.

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. For such arrangements,~~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 continue to be equivalent to the natural gas supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606~~ 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 ~~longer term contractual commitments and~~ 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 Gas' financial statements. In addition, the power

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and utilities industry ~~is currently addressing~~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.

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The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company Gas ~~must select~~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 ~~transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect~~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 ~~date~~adoption of ~~initial adoption. As~~ASC 606, including the ~~ultimate~~cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of ~~the new standard has not yet been determined,~~revenues recognized in Southern Company Gas' financial statements, Southern Company Gas ~~has not elected its transition method.~~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~~(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. ~~Southern Company Gas is currently evaluating the new standard.~~ 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 ~~first~~third quarter and year-to-date 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor ~~first quarter~~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 ~~March 31,~~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 ~~March 31,~~September 30, 2017, the amount of subsidiary retained earnings and net income available to dividend totaled ~~$722~~$752 million. These restrictions

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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 ~~$758~~$1.1 billion for the successor first nine months of 2017, $(342) million for the successor ~~first quarter 2017~~period of July 1, 2016 through September 30, 2016, and ~~$841 million~~$1.1 billion for the predecessor ~~first quarter~~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 ~~$405 million~~$1.2 billion for the successor first ~~quarter~~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 ~~$238~~$1.7 billion for the successor period of July 1, 2016 through September 30, 2016 and $559 million for the predecessor ~~first quarter~~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.~~operations and the acquisition of Southern Company Gas' ownership interest in SNG in September 2016.

Net cash ~~used for~~provided from financing activities totaled ~~$344~~$45 million for the successor first ~~quarter~~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 ~~used for~~provided from (used for) financing activities totaled ~~$602~~$2.1 billion for the successor period of July 1, 2016 through September 30, 2016 and $(558) million for the predecessor ~~first quarter~~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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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Significant balance sheet changes at ~~March 31,~~September 30, 2017 include an increase of ~~$222~~$847 million in total property, plant, and equipment primarily due to capital expenditures for infrastructure replacement programs, ~~and decreases~~an increase in long-term debt of ~~$411~~$603 million ~~in natural gas for sale, including temporary LIFO liquidation~~primarily due to ~~the use~~$450 million of ~~natural gas stored during the~~senior notes and $200 million of first ~~quarter~~mortgage bonds at Nicor Gas issued in May 2017 and ~~$234~~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 ~~decreases~~an increase of ~~$107~~$239 million in ~~accounts payable~~accumulated deferred income taxes, primarily as a result of tax depreciation related to infrastructure assets placed in service as well as ~~$130~~the impact of State of Illinois tax legislation, and decreases of $196 million and ~~$126~~$146 million in energy marketing ~~receivable~~receivables and ~~energy marketing~~ 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. ~~Approximately $22 million will be required through March 31, 2018 to fund~~There are no scheduled maturities of long-term ~~debt.~~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

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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 ~~March 31,~~September 30, 2017, Southern Company Gas' current liabilities exceeded current assets by ~~$767 million.~~$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 ~~its~~ 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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At ~~March 31,~~September 30, 2017, Southern Company Gas had approximately ~~$28~~$21 million of cash and cash equivalents. Committed credit arrangements with banks at ~~March 31,~~September 30, 2017 were as follows:


	Expires								Expires Within One Year
Company	2017		2018		Total		Unused		Term Out		No Term Out		Expires 2022		Unused
	(in millions)												(millions)
Southern Company Gas Capital	$	49	$	1,251	$	1,300	$	1,249	$	—	$	49	$	1,200	$	1,161
Nicor Gas	26		674		700		700		—		26		700		700
Total	$	75	$	1,925	$	2,000	$	1,949	$	—	$	75	$	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 totaling $200 million.~~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.

~~The~~In May 2017, Southern Company Gas ~~Credit Facility~~Capital and ~~the~~ Nicor Gas ~~Credit Facility included~~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 each contain~~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 ~~contain cross acceleration provisions~~Nicor Gas and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of the applicable company. Such ~~cross acceleration provisions~~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 ~~March 31,~~September 30, 2017, ~~each of the applicable~~both companies ~~was~~were in compliance with ~~all~~ such ~~covenants. Neither of the bank credit arrangements~~covenant. The Facility does not contain a material adverse change ~~clauses~~clause at the time of borrowings.

Subject to applicable market conditions, the applicable company expects to renew or replace ~~its bank credit arrangements~~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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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Details of short-term borrowings were as follows:~~

Short-term Debt at
March 31, 2017

Short-term Debt During the Period^(*)
Amount
Outstanding Weighted Average Interest Rate Average Amount Outstanding Weighted Average Interest Rate Maximum Amount Outstanding
Commercial paper: (in millions) (in millions) (in millions)
Southern Company Gas Capital $ 715
1.28 % $ 630
1.09 % $ 733
Nicor Gas 308
1.16
410
0.98
525
Short-term loans:
Southern Company Gas —
—
1
1.91
113
Total $ 1,023
1.24 % $ 1,041
1.04 %


~~(*)~~	~~Average and maximum amounts are based upon daily balances during the successor three-month period ended March 31, 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.~~

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 ~~March 31,~~September 30, 2017 were ~~$13~~$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 ~~March 31,~~September 30, 2017, the non-principal components totaled ~~$556~~$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 ~~first~~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.

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~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF~~

~~FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

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 ~~its~~ end-use customers have limited exposure to market volatility of natural gas prices.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 ~~the~~all periods presented, and provides details of the net fair value of contracts outstanding as of the dates presented.


	Successor		Predecessor			Successor												Predecessor
	First Quarter		First Quarter			Third Quarter			Third Quarter			Year-to-Date			July 1, 2016 through September 30, 2016			January 1, 2016 through June 30, 2016
	2017		2016			2017			2016			2017			July 1, 2016 through September 30, 2016			January 1, 2016 through June 30, 2016
	(in millions)		(in millions)			(in millions)												(in millions)
Contracts outstanding at beginning of period, assets (liabilities), net	$	12	$	75		$	51		$	(54	)	$	12		$	(54	)	$	75
Contracts realized or otherwise settled	4		(85		)	(6		)	(3		)	(22		)	(3		)	(77		)
Current period changes^(a)	48		(34		)	(16		)	—			39			—			(82		)
Contracts outstanding at the end of period, assets (liabilities), net	64		(44		)	29			(57		)	29			(57		)	(84		)
Netting of cash collateral	92		165			76			111			76			111			120
Cash collateral and net fair value of contracts outstanding at end of period^(b)	$	156	$	121		$	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 ~~$19~~$13 million at ~~March 31,~~September 30, 2017 and $9$7 million at ~~March 31,~~September 30, 2016.

The maturities of Southern Company Gas' energy-related derivative contracts at ~~March 31,~~September 30, 2017 were as follows:


				Fair Value Measurements												Fair Value Measurements
				Successor – March 31, 2017												Successor – September 30, 2017
	Total Fair Value			Maturity									Total Fair Value			Maturity
	Total Fair Value			Year 1			Years 2 & 3			Years 4 and thereafter			Total Fair Value			Year 1			Years 2 & 3			Years 4 and thereafter
	(in millions)												(in millions)
Level 1^(a)	$	(28	)	$	(2	)	$	(21	)	$	(5	)	$	(35	)	$	(10	)	$	(20	)	$	(5	)
Level 2^(b)	92			57			29			6			64			12			45			7
Level 3	—			—			—			—
Fair value of contracts outstanding at end of period^(c)	$	64		$	55		$	8		$	1		$	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 ~~$92~~$76 million at ~~March 31,~~September 30, 2017.

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

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

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 ~~March 31,~~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 ~~March 31,~~September 30, 2017 and the three months ended September 30, 2016, as well as its financial condition as of ~~March 31,~~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.

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.

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. For such arrangements, the~~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 ~~that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and~~ the adoption of ASC 606 will not result in a significant shift infrom the current timing of revenue recognition for such ~~sales.~~transactions.

The registrants' ongoing evaluation of other revenue streams and related contracts includes ~~longer term contractual commitments and~~ 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 ~~is currently addressing~~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. 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.

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The registrants ~~must select~~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 ~~transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect~~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 ~~date~~adoption of ~~initial adoption. As~~ASC 606, including the ~~ultimate~~cumulative-effect adjustment, is not expected to have a material impact on either the timing or amount of revenues recognized in the ~~new standard has not yet been determined,~~registrants' financial statements, the registrants ~~have not elected a transition method.~~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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

~~electric operating companies, and Southern Company Gas are currently evaluating the new standard.~~ 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 ~~three~~nine months ended ~~March 31,~~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, ~~$26~~$8 million, $6$2 million, and $9$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 ~~three~~nine months ended ~~March 31,~~September 30, 2017, natural gas purchases made by Georgia Power and Southern Power from Southern Company Gas' subsidiaries were approximately ~~$23 million.~~$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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Goodwill and Other Intangible Assets

~~As of March 31,~~At September 30, 2017 and December 31, 2016, goodwill was as follows:


			Goodwill
	Goodwill		At September 30, 2017		At December 31, 2016
	(in millions)		(in millions)
Southern Company	$	6,251	$	6,267	$	6,251
Southern Power	$	2	$	2	$	2
Southern Company Gas
Gas distribution operations	$	4,702	$	4,702	$	4,702
Gas marketing services	1,265		1,265		1,265
Southern Company Gas total	$	5,967	$	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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Other intangible assets were as follows:


	As of March 31, 2017							As of December 31, 2016							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		Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net
	(in millions)							(in millions)							(in millions)							(in millions)
Southern Company
Other intangible assets subject to amortization:
Customer relationships	$	268	$	(44	)	$	224	$	268	$	(32	)	$	236	$	288	$	(70	)	$	218	$	268	$	(32	)	$	236
Trade names	158		(8		)	150		158		(5		)	153		159		(15		)	144		158		(5		)	153
Patents	4		—			4		4		—			4
Backlog	5		(1		)	4		5		(1		)	4
Storage and transportation contracts	64		(15		)	49		64		(2		)	62		64		(27		)	37		64		(2		)	62
Software and other	2		(1		)	1		2		—			2
PPA fair value adjustments	456		(28		)	428		456		(22		)	434		456		(41		)	415		456		(22		)	434
Other															16		(3		)	13		11		(1		)	10
Total other intangible assets subject to amortization	$	957	$	(97	)	$	860	$	957	$	(62	)	$	895	$	983	$	(156	)	$	827	$	957	$	(62	)	$	895
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	$	75	$	—		$	75	$	75	$	—		$	75	$	75	$	—		$	75	$	75	$	—		$	75
Total other intangible assets	$	1,032	$	(97	)	$	935	$	1,032	$	(62	)	$	970	$	1,058	$	(156	)	$	902	$	1,032	$	(62	)	$	970

Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	456	$	(28	)	$	428	$	456	$	(22	)	$	434	$	456	$	(41	)	$	415	$	456	$	(22	)	$	434

Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	221	$	(41	)	$	180	$	221	$	(30	)	$	191	$	221	$	(65	)	$	156	$	221	$	(30	)	$	191
Trade names	115		(4		)	111		115		(2		)	113		115		(8		)	107		115		(2		)	113
Wholesale gas services
Storage and transportation contracts	64		(15		)	49		64		(2		)	62		64		(27		)	37		64		(2		)	62
Total other intangible assets subject to amortization	$	400	$	(60	)	$	340	$	400	$	(34	)	$	366	$	400	$	(100	)	$	300	$	400	$	(34	)	$	366

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Amortization associated with other intangible assets was as follows:


	Three Months Ended		Three Months Ended		Nine Months Ended
	March 31, 2017		September 30, 2017
	(in millions)		(in millions)
Southern Company	$	35	$	29	$	94
Southern Power	$	6	$	6	$	19
Southern Company Gas	$	26	$	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 ~~but~~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 ~~storm~~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'~~Gas had no inventory decrement at ~~March 31, 2017 is expected to be restored prior to year end.~~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 ~~recorded~~had no material LOCOM adjustment in ~~the successor first quarter 2017 and recorded a $3 million LOCOM adjustment in the predecessor first quarter 2016.~~any period presented.

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 offormer Mississippi ~~Power's former~~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 offormer Mississippi ~~Power's former~~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. ~~Southern Company believes this legal challenge has no merit; however,~~On June 12, 2017, the plaintiffs filed an ~~adverse outcome in this proceeding could have~~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 ~~impact~~opposition on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in this matter, and the ultimate outcome of this matter cannot be determined at this time.September 11, 2017.

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

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.

Georgia Power

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

certiorari with the Georgia Supreme ~~Court.~~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

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~~Nicor Gas

~~The Southern Company system must comply with environmental laws~~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 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 naturalexpand gas distribution ~~utilities~~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 ~~Illinois, New Jersey,~~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 ~~Florida have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs~~upgrade its core gas distribution system in years 2017 through ~~regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits~~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 ~~state PSCs or~~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 ~~applicable state~~matters being litigated and regulatory ~~agencies.~~

Georgia Power's environmental remediation liability as of March 31, 2017 was $13 million. 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 $52 million as of March 31, 2017. 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 projectsmatters that could affect future earnings. In addition, Southern Company Gas is subject to ~~FDEP approval.~~certain claims and legal actions arising in the

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ordinary course of business. The ~~projects~~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 ~~been approved by~~a material effect on Southern Company Gas' financial statements. See Note (B) to the ~~Florida PSC~~Condensed Financial Statements herein for ~~recovery through Gulf Power's environmental cost recovery clause; therefore,~~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 ~~liabilities~~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 noa material impact on ~~net income.~~Southern Company Gas' financial statements.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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' ~~environmental remediation liability~~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 ~~March 31, 2017 was $409 million based~~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 ~~estimated cost~~power

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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 byutilities industry continues to evaluate other specific industry issues, including the ~~applicable state regulatory agencies~~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 ~~natural gas distribution utilities, with the exception~~scope of ~~one site representing $5 million of the total accrued remediation costs.~~ASC 606.

The ~~final outcome~~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 ~~these matters cannot be determined~~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 ~~this time. However,~~ the ~~final disposition~~date of ~~these matters~~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 ~~Georgia Power, Gulf Power, or Southern Company Gas.~~

~~FERC Matters~~

~~Municipal and Rural Associations Tariff~~

~~See Note 3 to the financial statements of Mississippi Power under "FERC Matters"~~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

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

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.

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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SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Credit Rating Risk

Southern Company Gas does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

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.

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 July 2017, Atlanta Gas Light Company repaid at maturity $22 million of Series C medium-term notes.

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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SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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			July 1, 2016 through September 30, 2016			January 1, 2016 through June 30, 2016
	(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
	Total Fair Value			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.

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

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

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 ~~a settlement agreement entered into by Mississippi Power regarding~~ the Merger.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

~~establishment of a regulatory asset for Kemper IGCC-related costs. See "Integrated Coal Gasification Combined Cycle" herein for additional information regarding Mississippi Power's construction of the Kemper IGCC.~~Recently Issued Accounting Standards

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 is estimated to be approximately $18 million until the end of May 2017 when the Kemper IGCC is projected to be placed in service.

~~Fuel Cost Recovery~~

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At March 31, 2017, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $12 million compared to $13 million at December 31, 2016. At March 31, 2017 and December 31, 2016, the amount of over-recovered wholesale MB fuel costs included in the balance sheets was $1 million.

See Note 31 to the financial statements of ~~Mississippi Power~~the registrants under ~~"FERC Matters~~ – ~~Fuel Cost Recovery"~~"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.

~~Market-Based Rate Authority~~

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~~companies', and Southern ~~Power have authority~~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 ~~FERC~~current timing of revenue recognition for such transactions.

The registrants' ongoing evaluation of other revenue streams and related contracts includes unregulated sales to ~~sell electricity at market-based rates. Since 2008, that authority,~~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 ~~certain balancing authority areas,~~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 conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority,issued, Southern Company, the traditional electric operating companies, and Southern ~~Power filed~~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 ~~triennial market power analysis~~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 ~~2014, which included continued reliance on~~ the ~~energy auction as tailored mitigation. In 2015,~~registrants' financial statements, the ~~FERC issued an order finding that~~registrants will continue to evaluate the traditional electric operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. The FERC directed the traditional electric operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional electric operating companies and Southern Power filed a request for rehearing and filed their response with the FERC in 2015.

~~In December 2016, the traditional electric operating companies and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction,~~requirements, as well as ~~several non-tariff changes.~~ any additional clarifying guidance that may be issued.

On ~~February 2,~~January 26, 2017, the ~~FERC~~FASB issued ~~an order accepting all such changes subject~~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 ~~an additional condition~~compare the implied fair value of ~~cost-based price caps for certain sales outside~~goodwill with the carrying amount as part of Step 2 of the ~~energy auction, finding~~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 ~~all~~reporting unit, which may increase the frequency of ~~these changes would provide adequate alternative mitigation~~goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for ~~the traditional electric operating companies'~~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 ~~Power's potential~~Company Gas are evaluating the standard and expect to ~~exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas.~~ early adopt ASU 2017-04 effective January 1, 2018.

On ~~February 23,~~March 10, 2017, the ~~traditional electric operating companies~~FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Southern Power accepted the terms of the order in a compliance filing. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.

~~The ultimate outcome of these matters cannot be determined at this time.~~Net Periodic Postretirement Benefit Cost (ASU

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

~~Regulatory Matters~~

~~Alabama Power~~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.

~~See Note 3~~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 ~~financial statements~~completion of Southern Company ~~and~~Gas' acquisition of its 50% equity interest in SNG, SCS (as agent for 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 March 31,
2017 December 31, 2016

(in millions)
Rate CNP Compliance^(*)
Deferred under recovered regulatory clause revenues $ —
$ 9
Rate CNP PPA Over recovered regulatory clause revenues 3
—
Deferred under recovered regulatory clause revenues —
142
Retail Energy Cost Recovery Other regulatory liabilities, current 40
76
Natural Disaster Reserve Other regulatory liabilities, deferred 66
69


~~(*)~~	In accordance with an accounting order issued on February 17, 2017 by the Alabama PSC, Alabama Power reclassified the $23 million under recovered balance for Rate CNP Compliance to a deferred regulatory asset account.

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.

~~Rate Plans~~

~~See Note 3 to the financial statements~~SCS, as agent for Georgia Power and Southern Power, has agreements with certain subsidiaries of Southern Company ~~and~~Gas to purchase natural gas. For the nine months ended September 30, 2017, natural gas purchases made by Georgia Power ~~under "Regulatory Matters – Georgia~~and Southern Power ~~– Rate Plans"~~from Southern Company Gas' subsidiaries were approximately $18 million and ~~"Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of~~$94 million, respectively. For the ~~Form 10-K for additional information.~~

~~Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject~~period subsequent 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~~Southern Company's acquisition of Southern Company ~~under "Regulatory Matters –~~Gas through September 30, 2016, natural gas purchases made by Georgia Power ~~– Nuclear Construction"~~ and ~~Georgia~~Southern 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~~from Southern Company ~~under "Regulatory Matters – Georgia Power – Fuel Cost Recovery"~~Gas' subsidiaries were approximately $7 million 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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

of recovery for costs of approximately $50 million incurred through March 31, 2017 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.Goodwill and Other Intangible Assets

~~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 March 31,~~At September 30, 2017 and December 31, 2016, ~~Georgia Power's over recovered fuel balance totaled $18 million and $84 million, respectively, and~~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 ~~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,~~amortized, but ~~will affect cash flow.~~

~~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, the Vogtle Construction Litigation (as defined below), and the Contractor Settlement Agreement (as defined below).

~~Vogtle 3 and 4 Agreement and Contractor Bankruptcy~~

In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 (Vogtle 3 and 4 Agreement). 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. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and certain performance guarantees, eachis subject to an ~~aggregate cap~~annual impairment test during the fourth quarter of ~~10% of the contract price,~~each year, or approximately $920 million. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions with maximum additional capital costs under this provision attributable to Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%. In the event of a credit rating downgrade below investment grade of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement.

On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Among other things, the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) revised the guaranteed substantial completion dates to June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (ii) provided that delay liquidated damages will commencemore frequently if the nuclear fuel loading date for each unit does not occur by December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; and (iii) provided that, pursuant to the amendment to the Vogtle 3 and 4 Agreement, Georgia Power, based on its ownership interest, pay to the Contractor and capitalize to the project cost approximately $350 million in settlement of disputed claims. Further, as a consequence of the settlement and Westinghouse's acquisition of WECTEC, Westinghouse engaged Fluor Enterprises, Inc. (Fluor Enterprises), a subsidiary of Fluor Corporation (Fluor), as a new construction subcontractor.impairment indicators arise.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Under the terms of the Vogtle 3 and 4 Agreement, the Contractor does not have a right to terminate the Vogtle 3 and 4 Agreement for convenience. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. In the event of an abandonment of work by the Contractor, the maximum liability of the Contractor under the Vogtle 3 and 4 Agreement is increased to 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest). The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for convenience, provided that the Vogtle Owners will be required to pay certain termination costs. In addition, the Vogtle Owners may terminate the Vogtle 3 and 4 Agreement for certain Contractor breaches, including abandonment of work by the Contractor.Other intangible assets were as follows:

Under the Toshiba Guarantee, Toshiba has guaranteed certain payment obligations of the Contractor, including any liability of the Contractor for abandonment of work. However, due to Toshiba's financial situation described below, substantial risk regarding the Vogtle Owners' ability to fully collect under the Toshiba Guarantee exists. 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 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. In the event of such notice, the Vogtle Owners would be able to draw on the entire balance of the Westinghouse Letters of Credit. The Westinghouse Letters of Credit remain in place in accordance with the terms of the Vogtle 3 and 4 Agreement.

On March 29, 2017, Westinghouse and WECTEC each filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an interim assessment agreement with the Contractor and WECTEC Staffing Services LLC (WECTEC Staffing), as of March 29, 2017 (Interim Assessment Agreement), to provide for a continuation of work with respect to Plant Vogtle Units 3 and 4. Georgia Power's entry into the Interim Assessment Agreement was conditioned upon South Carolina Electric & Gas Company entering into a similar interim assessment agreement with the Contractor relating to V.C. Summer, which also occurred on March 29, 2017. The provisions in the Interim Assessment Agreement became effective upon approval of the Interim Assessment Agreement by the bankruptcy court on March 30, 2017. The term of the Interim Assessment Agreement was originally scheduled to expire on April 28, 2017. On April 28, 2017, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an amendment to the Interim Assessment Agreement with the Contractor and WECTEC Staffing solely to extend the term of the Interim Assessment Agreement through the earlier of (i) May 12, 2017 and (ii) termination of the Interim Assessment Agreement by any party upon five business days' notice (Interim Assessment Period).



	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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

~~A number of subcontractors~~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 ~~Contractor,~~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 ~~Fluor Enterprises, have alleged non-payment~~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 ~~Contractor for amounts owed for work performed~~Florida PSC on ~~Plant Vogtle Units 3~~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 ~~4. Georgia~~is required to resume accruals of $3.5 million annually if the reserve balance falls below zero. In addition, Gulf Power ~~acting for itself and as agent for~~may initiate a storm surcharge to recover costs associated with any tropical systems named by the ~~Vogtle Owners, has taken, and continues to take, action to remove liens filed by these subcontractors through~~National Hurricane Center or other catastrophic storm events that reduce the ~~posting of surety bonds.~~

~~Georgia Power estimates~~property damage reserve in the aggregate ~~liability~~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 ~~Vogtle Owners under the Interim Assessment Agreement and the removal of subcontractor liens~~property damage reserve to be approximately ~~$470 million, of which Georgia Power's proportionate share would total approximately $215~~$40 million. As of ~~March 31,~~September 30, 2017, ~~$245 million~~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 ~~this aggregate liability had been paid or accrued. Georgia Power~~Nicor Gas, carry natural gas inventory on a WACOG basis.

Nicor Gas' natural gas inventory is ~~evaluating remedies available~~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 ~~Vogtle Owners for these payments, including draws under~~estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the ~~Westinghouse Letters of Credit and enforcement~~actual LIFO cost of the ~~Toshiba Guarantee.~~

~~In February 2017, the Contractor provided Georgia Power with revised forecasted in-service dates~~inventory layers liquidated. Southern Company Gas had no inventory decrement at September 30, 2017. The cost of ~~December 2019~~natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and September 2020 for Plant Vogtle Units 3 and 4, respectively. However, based on information subsequently made available during Westinghouse and WECTEC's bankruptcy proceedings and pursuant to the Interim Assessment Agreement, Georgia Power and the Vogtle Owners do not believe the revised in-service dates are achievable. Georgia Power, along with the other Vogtle Owners, is undertaking a comprehensive schedule and cost-to-complete assessment, as well as a cancellation cost assessment. It is reasonably possible these assessments result in estimated incremental costs to complete, including owners' costs, that materially exceed the value of the Toshiba Guarantee. Georgia Power intends to work with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4. Georgia Power, for itself and as agent for the other Vogtle Owners, is also negotiating a new service agreement which would, if necessary, engage the Contractor to provide design, engineering, and procurement services to Southern Nuclear, in the event Southern Nuclear assumes control over construction management. In addition, Georgia Power, on behalf of itself and the other Vogtle Owners, intends to take all actions available to it to enforce its rights related to the Vogtle 3 and 4 Agreement, including enforcing the Toshiba Guarantee, subject to the Interim Assessment Agreement, and accessing the Westinghouse Letters of Credit.

~~The Contractor's bankruptcy filing is expected to~~amounts billed; therefore, LIFO liquidations 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~~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.

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 ~~Georgia Power's financial statements.~~regulatory matters.

General Litigation Matters

Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, ~~an inability or other failure by Toshiba to perform its obligations under~~ the ~~Toshiba Guarantee could have a further material impact on the net cost to the Vogtle Owners to complete construction~~business activities of ~~Plant Vogtle Units 3 and 4 and, therefore, on~~ Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and ~~Georgia Power's financial statements.~~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 ~~these matters also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment,~~such pending or potential litigation against each registrant and any subsidiaries cannot be ~~determined~~predicted at this ~~time.~~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.

~~Regulatory Matters~~Southern Company

~~In 2009,~~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, ~~PSC voted~~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 ~~certify construction~~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 ~~Plant Vogtle Units 3~~Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and ~~4 with~~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 ~~certified capital cost~~shareholder derivative lawsuit in the Superior Court 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~~Gwinnett County, State of Georgia ~~enacted~~and, on May 31, 2017, Judy Mesirov filed a shareholder derivative lawsuit in the ~~Georgia Nuclear Energy Financing Act, which allows Georgia~~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, ~~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.~~

~~On December 20, 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence matters: (i) none~~behalf 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 toSouthern Company, unspecified actual damages

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

~~be paid pursuant~~and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain unspecified changes to ~~the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) financing costs on verified~~Southern Company's corporate governance 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 PSCinternal processes. On August 15, 2017, these two shareholder derivative lawsuits were consolidated in the ~~2013 ARP) to 10.00% effective January 1, 2016. For purposes~~U.S. District Court for the Northern District of ~~the AFUDC calculation, the ROE on costs between $4.418 billion and $5.440 billion will also be 10.00%~~Georgia and the ~~ROE~~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 ~~any amounts above $5.440 billion would be Georgia Power's average cost~~Southern Company's results of ~~long-term debt. If~~operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, 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~~ ultimate outcome of ~~these matters~~which cannot be determined at this time.

~~Other Matters~~Georgia Power

~~As of March 31, 2017,~~In 2011, plaintiffs filed a putative class action against Georgia Power ~~had borrowed $2.6 billion related~~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 ~~Plant Vogtle Units 3~~municipalities) exceeded the amounts allowed in orders of the Georgia PSC and ~~4 costs through a loan guarantee agreement between~~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 ~~and~~filed a petition for writ of certiorari with the ~~DOE and a multi-advance credit facility among~~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 ~~DOE,~~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 ~~FFB. See Note 6~~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 ~~financial statements~~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 ~~Georgia Power under "DOE Loan Guarantee Borrowings"~~Nicor Inc. were defendants in ~~Item 8~~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 ~~Form 10-K~~customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company 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~~variously alleged that the ~~applicable unit be placed~~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 ~~service prior to 2021.~~unjust enrichment of these entities. The ~~net present value~~plaintiffs sought, on behalf 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 as 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-basedclasses they

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

~~compliance matters, including~~purported to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On February 8, 2017, the ~~timely resolution of Inspections, Tests, Analyses,~~judge denied the plaintiffs' motion for class certification and Acceptance Criteria and the related approvals by the NRC, may arise as 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.

As construction continues, the risk remains that challenges with 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. Georgia Power's previously estimated owner's costs of approximately $10 million per month and financing costs of approximately $30 million per month for Plant Vogtle Units 3 and 4 are being evaluated as part of the comprehensive schedule and cost-to-complete analysis being performed as a result of the Contractor's bankruptcy.

~~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~~Gas' motion for summary judgment. On March 7, 2017, the ~~Form 10-K for additional information.~~

~~In 2013, the Florida PSC approved~~parties reached a settlement, agreement (2013 Rate Case 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 may 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. In the first quarter 2017, Gulf Power recognized reductions in depreciation totaling $25.5 million. The 2013 Rate Case Settlement Agreement remains in effect through June 30, 2017.

On April 4, 2017, the Florida PSC approved the 2017 Rate Case Settlement Agreement among Gulf Power and three of the intervenors to Gulf Power's retail base rate case, with respect to Gulf Power's request to increase retail base rates. Under the terms of the 2017 Rate Case Settlement Agreement, Gulf Power will, among other things, increase rates effective July 1, 2017 to provide an annual overall net customer impact of approximately $54.3 million. The net customer impact consists of a $62.0 million increase in annual base revenues less an annual credit for certain wholesale revenues to be provided through December 2019 through the purchased power capacity cost recovery clause, which is estimated to be approximately $7.7 million for 2017. Gulf Power also will (1) continue its current authorized retail ROE midpoint (10.25%) and range (9.25% to 11.25%); (2) be deemed to have an equity ratio of 52.5% for all retail regulatory purposes; (3) 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 (4) 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~~finalized and effective on April 3, 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.

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

~~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 March 31,
2017 December 31, 2016

(in millions)
Fuel Cost Recovery Other regulatory liabilities, current $ 5
$ 15
Purchased Power Capacity Recovery Under recovered regulatory clause revenues 4
—
Environmental Cost Recovery Under recovered regulatory clause revenues 40
13
Energy Conservation Cost Recovery Under recovered regulatory clause revenues 3
4

~~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.

~~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.

In November 2016, Mississippi Power submitted its Energy Efficiency Cost Rider (EECR) Compliance filing, which included an increase of $1 million in annual retail revenues. On March 13, 2017, Mississippi Power amended and revised the EECR Compliance filing to request a $2 million annual increase in retail revenues. The ultimate outcome of this matter cannot be determined at this time.

~~Fuel Cost Recovery~~

See Note 3 to the financial statements of Mississippi Power under "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 March 31, 2017, the amount of over-recovered retail fuel costs included on Mississippi Power's condensed balance sheet was $27 million compared to $37 million at December 31, 2016.~~

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

~~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 April 7, 2017, Mississippi Power submitted its 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. The ultimate outcome of this matter cannot be determined at this time.

~~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. Accordingly, changes in the billing factor willsettlement did not have a ~~significant effect~~material impact on Southern Company's or Southern Company Gas' ~~revenues or net income, but will affect cash flows.~~financial statements.

~~Base Rate Cases~~Environmental Matters

~~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.~~

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, Integrated System Reinforcement Program, and Integrated Customer Growth 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.

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 Georgia PSC allowed the last monthly Pipeline Replacement Program surcharge increase, originally scheduled for October 2017, to occur effective March 1, 2017.

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 an ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase within the 11-month statutory time limit, after which rate adjustments will be effective.

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

~~The ultimate outcome of the 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

Atlanta Gas Light

See "Base Rate Cases" herein for additional information.

Elizabethtown Gas

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

Sources of Capital

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Credit Rating Risk

Southern Company Gas does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

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.

Financing Activities

In July 2017, Atlanta Gas Light Company repaid at maturity $22 million of Series C medium-term notes.

Market Price Risk

Southern Company Gas is exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas distribution utilities of Southern Company Gas that sell natural gas directly to end-use customers have limited exposure to market volatility of natural gas prices.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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			July 1, 2016 through September 30, 2016			January 1, 2016 through June 30, 2016
	(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
	Total Fair Value			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.

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

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

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.

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.

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.

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.

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.

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

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.

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

Southern Company

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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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

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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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.

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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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

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

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 million annually 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 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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Nuclear Construction

Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy

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.

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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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.

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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(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.

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

Regulatory Matters

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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.

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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)



	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 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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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

Gulf Power

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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Cost Recovery Clauses



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

Mississippi Power

Performance Evaluation Plan

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.

Environmental Compliance Overview Plan

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 Mississippi Power's condensed balance sheet was $2 million compared to $37 million at December 31, 2016.

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.

Southern Company Gas

Riders

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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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.

The ultimate outcome of these pending base rate cases cannot be determined at this time.

Regulatory Infrastructure Programs

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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

Virginia Natural Gas

In March 2016, the Virginia Commission approved an extension to the SAVE program, under which Virginia Natural Gas invested $7$21 million during the first ~~quarter~~nine months of 2017.

Florida City Gas

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

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

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 ~~and plans to operate~~ 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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 remainder of the plant, including the gasifiers and the gas clean-up facilities, represents first-of-a-kind technology.~~

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. ~~Mississippi Power continues to work toward achieving sustained operation sufficient to place~~During testing, the ~~remainder of the~~ plant ~~in service. The plant has, however,~~ produced and captured CO₂, and ~~has~~ produced sulfuric acid and ammonia, ~~all~~each of acceptable quality under the related off-take agreements. AsHowever, Mississippi Power experienced numerous challenges during the extended start-up process to achieve integrated operation of the gasifiers on a ~~result~~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 ~~ongoing challenges~~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 ~~ash removal and gas cleanup sour water systems, efforts to improve reliability and reach sustained operation~~Kemper IGCC (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of ~~both gasifiers and production~~pursuing a global settlement of ~~electricity from syngas in both combustion turbines remain in process. Mississippi Power currently expects the remainder~~costs of the Kemper IGCC ~~including both gasifiers, will be placed in service by~~(Kemper IGCC Settlement Docket). On June 28, 2017, Mississippi Power notified the ~~end of May 2017. The schedule reflects~~Mississippi PSC that it would begin a process to suspend operations and start-up activities on the ~~expected time needed to repair a leak in one~~gasifier portion of the ~~particulate control devices for~~Kemper IGCC, given the uncertainty as to the future of the gasifier ~~"A," make other minor modifications~~portion of the Kemper IGCC. Mississippi Power expects to ~~each gasifier's ash removal systems, repair~~continue to operate the ~~sour water system, and establish sustained operation~~combined cycle portion of ~~both gasifiers for~~ the ~~production of electricity from syngas.~~

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

Kemper IGCC as it has done since August 2014.

Mississippi Power's Kemper IGCC 2010 project estimate ~~current~~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 (which includes the impacts of the Mississippi Supreme Court's (Court) decision discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of March 31, 2017, all of which include 100% of the costs for the Kemper IGCC ~~are as follows:~~

Cost Category
2010 Project Estimate^(a)

Current Cost Estimate^(b)
Actual Costs
(in billions)
Plant Subject to Cost Cap^(c)(e)
$ 2.40
$ 5.75
$ 5.57
Lignite Mine and Equipment 0.21
0.23
0.23
CO₂ Pipeline Facilities
0.14
0.12
0.12
AFUDC^(d)
0.17
0.83
0.80
Combined Cycle and Related Assets Placed in
Service – Incremental^(e)
—
0.05
0.04
General Exceptions 0.05
0.10
0.09
Deferred Costs^(e)
—
0.22
0.22
Additional DOE Grants^(f)
—
(0.14 ) (0.14 )
Total Kemper IGCC^(g)
$ 2.97
$ 7.16
$ 6.93


~~(a)~~	~~The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO~~₂ ~~pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions.~~


~~(b)~~	~~Amounts in the Current Cost Estimate include certain estimated post-in-service~~was approximately $7.38 billion, including approximately $5.95 billion of costs ~~which are expected to be~~ subject to ~~the cost cap.~~

~~(c)~~

~~The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO~~₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap, and ~~exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs~~ – ~~2013 MPSC Rate Order" herein for additional information.~~

~~(d)~~

~~Mississippi Power's 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach~~ was ~~not approved by the Mississippi PSC as described in "Rate Recovery of Kemper IGCC Costs~~ – ~~2013 MPSC Rate Order." The Current Cost Estimate also reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.~~

~~(e)~~


~~(f)~~	On April 8, 2016, Mississippi Power received approximately $137 million in additional grants from the DOE for the Kemper IGCC (Additional DOE Grants), which are expected to be used to reduce future rate impacts for customers.

~~(g)~~

~~Of the total costs, including post-in-service costs for the lignite mine, incurred as of March 31, 2017, $3.73 billion was included in property, plant, and equipment (which is~~ net of the ~~Initial DOE Grants, the Additional DOE Grants, and estimated probable losses of $2.95 billion), $6~~$137 million in ~~other property and investments, $64 million in fossil fuel stock, $48 million in materials and supplies, $24 million in other regulatory assets, current, $173 million in~~

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

~~other regulatory assets, deferred, $1 million in other current assets, and $17 million in other deferred charges and assets in~~additional grants from the ~~balance sheet.~~

~~Mississippi Power does not intend to seek rate recovery~~DOE for ~~any costs related to the construction of~~ the Kemper IGCC ~~that exceed the $2.88 billion cost cap, net of the Initial~~(Additional DOE ~~Grants and excluding the Cost Cap Exceptions.~~ Grants).

Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap for the Kemper IGCC of ~~$108~~$196 million ($67121 million after tax) in the ~~first~~second quarter through May 31, 2017 and a total of $305 million ($188 million after tax) for year-to-date through May 31, 2017. ~~Since 2012, in~~In the aggregate, Mississippi Power ~~has~~ incurred charges of ~~$2.87~~$3.07 billion ($~~1.77~~1.89 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through ~~March~~May 31, 2017. The ~~increase to the~~May 31, 2017 cost estimate inincluded approximately $175 million of estimated costs to be incurred beyond the ~~first quarter 2017 primarily reflects $67 million for the extension of the Kemper IGCC's projected~~then-estimated in-service date ~~from mid-March~~of June 30, 2017 ~~to the end of May 2017, $23 million related to start-up fuel, and $18 million primarily related to outage maintenance and operational improvements.~~

~~In addition to the current construction cost estimate, Mississippi Power is identifying potential improvement projects to enhance plant performance, safety, and/or operations~~ that ~~ultimately may be completed subsequent~~were expected to placing the remainder of the Kemper IGCC in service. Approximately $12 million of related potential costs was recorded in 2016 and included in the current construction cost estimate. Other projects have yet to be fully evaluated, have not been included in the current cost estimate, and may 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 ~~in-service date~~suspension period beyond ~~May~~December 31, 2017 is currently estimated to result in additional ~~base~~suspension costs of approximately $25 million to $35 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date beyond May 31, 2017 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $16 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $3$5 million per month. ~~For~~In the event the gasification portions of the project are ultimately canceled, additional ~~information, see "Rate Recovery of~~pre-tax costs, which include mine and Kemper IGCC ~~Costs~~ – ~~2015 Rate Case" herein.~~plant closure

~~Further cost increases and/or extensions of~~

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

costs and contract termination costs, currently estimated at approximately $100 million to $200 million are expected to be incurred. In the ~~expected in-service date may result from factors including, but not limited~~aggregate, Mississippi Power recorded total pre-tax charges to ~~difficulties integrating the systems required~~income for sustained operations, sustaining nitrogen supply, continued issues with ash removal systems, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). Any further changes in 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 subject to~~IGCC. The Kemper combined cycle balances as presented in the ~~$2.88~~condensed balance sheet at September 30, 2017 include $1.1 billion ~~cost cap,~~in property, plant, and equipment, net of ~~the Initial DOE Grants~~$80 million in accumulated depreciation; $15 million in materials and ~~excluding the Cost Cap Exceptions, will be reflected~~supplies; $10 million in ~~Southern Company's~~other deferred charges and ~~Mississippi Power's statements~~assets; and $113 million in regulatory assets, net of ~~income~~accumulated amortization of $63 million, of which $21 million is included in other regulatory assets, current and ~~these changes could be material.~~$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 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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Asassociated with the gasification portions of ~~March~~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 ~~in addition~~ to ~~the $2.87 billion of costs above~~reflect the Mississippi PSC's ~~$2.88 billion cost cap that have been recognized~~schedule for the Kemper IGCC Settlement Docket, as ~~a charge~~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 ~~income,~~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 ~~had incurred~~has recorded a total of approximately ~~$2.01~~$1.3 billion in costs ~~subject to~~associated with the ~~cost cap and approximately $1.50 billion in Cost Cap Exceptions related to the construction and start-up~~combined cycle portion of the Kemper IGCC ~~that are~~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. These~~rates includes costs ~~primarily relate to~~in excess of the ~~following:~~

Prudence

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

ultimate resolution of Kemper IGCC cost recovery.

Economic Viability Analysis

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 ~~2017 Rate Case.~~Kemper IGCC Settlement Docket.

~~2017~~2015 Rate Case

Mississippi Power continues to believe that all costs related to the Kemper IGCC that remain subject to recovery have been prudently incurred in accordance with the requirements of the 2012 MPSC CPCN Order. Mississippi Power recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further herein and under "Prudence," "Lignite Mine and CO₂ Pipeline Facilities," "Termination of Proposed Sale of Undivided Interest," and "Income Tax Matters," these challenges include, but are not limited to, prudence issues associated with capital costs, financing costs (AFUDC), and future operating costs net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the 15% portion of the project previously contracted to SMEPA.

After the remainder of the plant is placed in service, AFUDC equity of approximately $12 million per month will no longer be recorded in income, and Mississippi Power expects to incur approximately $25 million per month in depreciation, taxes, operations and maintenance expenses, interest expense, and regulatory costs in excess of current rates. In connection with the 2017 Rate Case, Mississippi Power expects to file a request for authority fromOn December 3, 2015, the Mississippi PSC ~~and separately from~~issued the ~~FERC, to defer all Kemper IGCC costs incurred after the in-service date that cannot be capitalized, are not included~~In-Service Asset Rate Order adopting in ~~current rates, and are not required to be charged against earnings as~~full a result of the $2.88 billion cost cap until such time as the Mississippi PSC completes its review and includes the resulting allowable costs in rates. In the event the Mississippi PSC does not grant Mississippi Power's request, these monthly expenses will be charged to income as incurred and will not be recoverable through rates.

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

~~Power expects that timely resolution of the 2017 Rate Case will likely require a settlement agreement~~stipulation entered into between Mississippi Power and the MPUS (and other parties) that may include other operational or cost recovery alternatives and would be subject to the approval of the Mississippi PSC. While Mississippi Power intends to pursue any available settlement alternatives, the ability to achieve a negotiated settlement is uncertain. If a settlement is achieved, full regulatory recovery of the amounts not currently in rates is unlikely and could result in further material charges; however, the impact of such an agreement on Southern Company's and Mississippi Power's financial statements would depend on the method, amount, and type of cost recovery ultimately excluded, none of which can be reasonably determined at this time. Certain costs, including operating costs, would be recorded to income in the period incurred, while other costs, including investment-related costs, would be charged to income when it is probable they will not be recovered and the amounts can be reasonably estimated. In the event an agreement acceptable to the parties cannot be reached, Mississippi Power intends to fully litigate its request for full recovery through the Mississippi PSC regulatory process and any subsequent legal challenges.

~~2015 Rate Case~~

On August 13, 2015, the Mississippi PSC approved Mississippi Power's request for interim rates, which presented an alternative rate proposal (In-Service Asset Proposal) designed to recover Mississippi Power's costs associated withregarding the Kemper IGCC assets that ~~are~~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 interim rates were designed to collect approximately $159 million annually and became effective in September 2015, subject to refund and certain other conditions.~~

On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full a stipulation (2015 Stipulation) entered into between Mississippi Power and the MPUS regarding the In-Service Asset Proposal. 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 ~~SMEPA~~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.

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~~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,~~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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 iswas placed in service, based on a mirror CWIP methodology (Mirror CWIP rate).

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

~~2012 MPSC CPCN Order~~

Mississippi Power expects the Mississippi PSC to ~~apply operational parameters~~address this matter in connection with the ~~2017 Rate Case and future proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the~~ Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Southern Company's or Mississippi Power's financial statements. See "~~Prudence" herein for additional information.~~

~~Regulatory Assets and Liabilities~~

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

~~March 31, 2017, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $8 million. See "2015 Rate Case" herein for additional information.~~

~~See Note 1 to the financial statements of Southern Company and Mississippi Power under "Regulatory Assets and Liabilities" in Item 8 of the Form 10-K for additional information.~~Settlement Docket.

Lignite Mine and CO₂ Pipeline Facilities

In addition, Mississippi Power ~~has~~ constructed ~~and will operate~~ 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, and termination rights if~~years. Denbury has the right to terminate the contract at any time because Mississippi Power ~~has~~did not ~~satisfied its contractual obligation to deliver captured CO~~₂place the Kemper IGCC in service by July 1, 2017, in addition to Denbury's existing termination rights in the event of a change in law, force majeure, or an event of default by Mississippi Power. Any termination or material modification of the agreement with Denbury could impact the operations of the Kemper IGCC and result in a material reduction in Mississippi Power's revenues to the extent Mississippi Power is not able to enter into other similar contractual arrangements or otherwise sequester the CO₂ produced. Additionally, sustained oil price reductions could result in significantly lower revenues than Mississippi Power originally forecasted to be available to offset customer rate impacts, which could have a material impact on Mississippi Power's financial statements.2017.

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

Termination of Proposed Sale of Undivided Interest

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Litigation

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

~~District of Mississippi. The plaintiffs filed a request to remand the case back to state court, which was granted on November 17, 2016.~~ The individual plaintiff ~~John Carlton Dean,~~ 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 ~~December 7, 2016,~~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 ~~motions to dismiss, which the Circuit Court is expected to address in the second quarter 2017.~~notice of an appeal.

Southern Company and Mississippi Power believe these legal challenges have no merit; however, an adverse outcome in these proceedings could ~~impact Southern Company's results of operations, financial condition, and liquidity and 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

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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)


(C)	FAIR VALUE MEASUREMENTS

As of ~~March 31,~~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:										Fair Value Measurements Using:
As of March 31, 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
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)										(in millions)
Southern Company
Assets:
Energy-related derivatives^(a)(b)	$	274	$	213	$	—	$	—	$	487	$	231	$	184	$	—	$	—	$	415
Interest rate derivatives	—		13		—		—		13		—		5		—		—		5
Foreign currency derivatives											—		103		—		—		103
Nuclear decommissioning trusts^(c)	714		942		—		21		1,677		752		1,004		—		26		1,782
Cash equivalents	589		—		—		—		589		1,271		—		—		—		1,271
Other investments	9		—		1		—		10		9		—		1		—		10
Total	$	1,586	$	1,168	$	1	$	21	$	2,776	$	2,263	$	1,296	$	1	$	26	$	3,586
Liabilities:
Energy-related derivatives^(a)(b)	$	303	$	155	$	—	$	—	$	458	$	265	$	146	$	—	$	—	$	411
Interest rate derivatives	—		32		—		—		32		—		24		—		—		24
Foreign currency derivatives	—		62		—		—		62		—		23		—		—		23
Contingent consideration	—		—		20		—		20		—		—		20		—		20
Total	$	303	$	249	$	20	$	—	$	572	$	265	$	193	$	20	$	—	$	478

Alabama Power
Assets:
Energy-related derivatives	$	—	$	11	$	—	$	—	$	11	$	—	$	9	$	—	$	—	$	9
Nuclear decommissioning trusts:^(d)
Domestic equity	405		77		—		—		482		422		81		—		—		503
Foreign equity	52		51		—		—		103		60		57		—		—		117
U.S. Treasury and government agency securities	—		28		—		—		28		—		27		—		—		27
Corporate bonds	22		143		—		—		165		19		150		—		—		169
Mortgage and asset backed securities	—		18		—		—		18		—		18		—		—		18
Private Equity	—		—		—		21		21		—		—		—		26		26
Other	—		7		—		—		7		—		8		—		—		8
Cash equivalents	555		—		—		—		555		808		—		—		—		808
Total	$	1,034	$	335	$	—	$	21	$	1,390	$	1,309	$	350	$	—	$	26	$	1,685
Liabilities:
Energy-related derivatives	$	—	$	10	$	—	$	—	$	10	$	—	$	7	$	—	$	—	$	7

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)


	Fair Value Measurements Using:										Fair Value Measurements Using:
As of March 31, 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
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)										(in millions)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	24	$	—	$	—	$	24	$	—	$	18	$	—	$	—	$	18
Interest rate derivatives	—		2		—		—		2		—		1		—		—		1
Nuclear decommissioning trusts:^{(d) (e)}
Domestic equity	216		1		—		—		217		235		1		—		—		236
Foreign equity	—		137		—		—		137		—		156		—		—		156
U.S. Treasury and government agency securities	—		196		—		—		196		—		225		—		—		225
Municipal bonds	—		70		—		—		70		—		64		—		—		64
Corporate bonds	—		168		—		—		168		—		160		—		—		160
Mortgage and asset backed securities	—		41		—		—		41		—		38		—		—		38
Other	19		5		—		—		24		16		19		—		—		35
Cash equivalents	—		—		—		—		—		112		—		—		—		112
Total	$	235	$	644	$	—	$	—	$	879	$	363	$	682	$	—	$	—	$	1,045
Liabilities:
Energy-related derivatives	$	—	$	13	$	—	$	—	$	13	$	—	$	11	$	—	$	—	$	11
Interest rate derivatives	—		4		—		—		4		—		3		—		—		3
Total	$	—	$	17	$	—	$	—	$	17	$	—	$	14	$	—	$	—	$	14

Gulf Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	—	$	2
Cash equivalents	21		—		—		—		21		$	21	$	—	$	—	$	—	$	21
Total	$	21	$	2	$	—	$	—	$	23
Liabilities:
Energy-related derivatives	$	—	$	31	$	—	$	—	$	31	$	—	$	22	$	—	$	—	$	22

Mississippi Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3	$	—	$	3	$	—	$	—	$	3
Interest rate derivatives	—		4		—		—		4		—		2		—		—		2
Cash equivalents											209		—		—		—		209
Total	$	—	$	7	$	—	$	—	$	7	$	209	$	5	$	—	$	—	$	214
Liabilities:
Energy-related derivatives	$	—	$	12	$	—	$	—	$	12	$	—	$	7	$	—	$	—	$	7

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)


	Fair Value Measurements Using:										Fair Value Measurements Using:
As of March 31, 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
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)										(in millions)
Southern Power
Assets:
Energy-related derivatives	$	—	$	15	$	—	$	—	$	15	$	—	$	9	$	—	$	—	$	9
Foreign currency derivatives											—		103		—		—		103
Cash equivalents											90		—		—		—		90
Total											$	90	$	112	$	—	$	—	$	202
Liabilities:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5	$	—	$	4	$	—	$	—	$	4
Foreign currency derivatives	—		62		—		—		62		—		23		—		—		23
Contingent consideration	—		—		20		—		20		—		—		20		—		20
Total	$	—	$	67	$	20	$	—	$	87	$	—	$	27	$	20	$	—	$	47

Southern Company Gas
Assets:
Energy-related derivatives^(a)(b)	$	274	$	158	$	—	$	—	$	432	$	231	$	145	$	—	$	—	$	376
Liabilities:
Energy-related derivatives^(a)(b)	$	303	$	84	$	—	$	—	$	387	$	265	$	95	$	—	$	—	$	360


(a)	Excludes ~~$19~~$13 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value.


(b)	Excludes cash collateral of ~~$92~~$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 ~~March 31,~~September 30, 2017, approximately ~~$56~~$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 ~~$63~~$50 million and ~~$20~~$168 million, respectively, for the three and nine months ended ~~March 31,~~September 30, 2017, and ~~2016, respectively.~~by $49 million and $116 million, respectively, for the three and nine months ended September 30, 2016. Alabama Power recorded ~~an increase~~increases in fair value of ~~$34~~$25 million and ~~$11~~$87 million, respectively, for the three and nine months ended ~~March 31,~~September 30, 2017 and $26 million and $66 million, respectively, for the three and nine months ended September 30, 2016 ~~respectively,~~ as a change in regulatory liabilities related to its AROs. Georgia Power recorded ~~an increase~~increases in fair value of ~~$29~~$25 million and $9$81 million, respectively, for the three and nine months ended ~~March 31,~~September 30, 2017 and $23 million and $50 million, respectively, for the three and nine months ended September 30, 2016 ~~respectively,~~ 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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(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

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

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 ~~pay~~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 ~~have~~has been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.

As of ~~March 31,~~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 March 31, 2017:	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
As of September 30, 2017:							Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)						(in millions)
Southern Company	$	21	$	22	Not Applicable	Not Applicable	$	26	$	24	Not Applicable	Not Applicable
Alabama Power	$	21	$	22	Not Applicable	Not Applicable	$	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, ~~a fund~~funds that ~~invests~~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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

As of ~~March 31,~~September 30, 2017, other financial instruments for which the carrying amount did not equal fair value were as follows:


	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)				(in millions)
Long-term debt, including securities due within one year:
Southern Company	$	45,881	$	46,828	$	47,269	$	49,348
Alabama Power	$	7,439	$	7,807	$	7,404	$	8,031
Georgia Power	$	11,362	$	11,777	$	11,713	$	12,237
Gulf Power	$	1,079	$	1,110	$	1,292	$	1,352
Mississippi Power	$	2,977	$	2,909	$	2,123	$	2,117
Southern Power	$	5,648	$	5,694	$	5,810	$	5,916
Southern Company Gas	$	5,268	$	5,487	$	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 March 31, 2017	Three Months Ended March 31, 2016	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)		(in millions)
As reported shares	993	916	1,003	968	998	940
Effect of options and performance share award units	7	6	7	7	7	5
Diluted shares	1,000	922	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 ~~March 31,~~September 30, 2017 and 2016.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(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			Number of Common Shares			Common Stockholders' Equity			Preferred and Preference Stock of Subsidiaries						Total Stockholders' Equity
	Issued	Treasury		Common Stockholders' Equity			Preferred and Preference Stock of Subsidiaries		Noncontrolling Interests^(*)			Total Stockholders' Equity			Issued	Treasury		Common Stockholders' Equity			Preferred and Preference Stock of Subsidiaries			Noncontrolling Interests^(*)			Total Stockholders' Equity
	(in thousands)			(in millions)											(in thousands)			(in millions)
Balance at December 31, 2016	991,213	(819	)	$	24,758		$	609	$	1,245		$	26,612		991,213	(819	)	$	24,758		$	609		$	1,245		$	26,612
Consolidated net income attributable to Southern Company	—	—		658			—		—			658			—	—		347			—			—			347
Other comprehensive income (loss)	—	—		(9		)	—		—			(9		)	—	—		(2		)	—			—			(2		)
Stock issued	4,240	—		186			—		—			186			13,308	—		613			—			—			613
Stock-based compensation	—	—		57			—		—			57			—	—		97			—			—			97
Cash dividends on common stock	—	—		(556		)	—		—			(556		)	—	—		(1,716		)	—			—			(1,716		)
Preference stock redemption															—	—		—			(150		)	—			(150		)
Contributions from noncontrolling interests	—	—		—			—		71			71			—	—		—			—			77			77
Distributions to noncontrolling interests	—	—		—			—		(18		)	(18		)	—	—		—			—			(87		)	(87		)
Net income attributable to noncontrolling interests	—	—		—			—		(4		)	(4		)	—	—		—			—			45			45
Reclassification from redeemable noncontrolling interests															—	—		—			—			114			114
Other	—	(35	)	—			—		(1		)	(1		)	—	(75	)	(15		)	3			1			(11		)
Balance at March 31, 2017	995,453	(854	)	$	25,094		$	609	$	1,293		$	26,996
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		915,073	(3,352	)	$	20,592		$	609		$	781		$	21,982
Consolidated net income attributable to Southern Company	—	—		489			—		—			489			—	—		2,251			—			—			2,251
Other comprehensive income (loss)	—	—		(114		)	—		—			(114		)	—	—		(95		)	—			—			(95		)
Stock issued	6,572	—		270			—		—			270			65,725	2,599		3,265			—			—			3,265
Stock-based compensation	—	—		57			—		—			57			—	—		94			—			—			94
Cash dividends on common stock	—	—		(497		)	—		—			(497		)	—	—		(1,553		)	—			—			(1,553		)
Contributions from noncontrolling interests	—	—		—			—		129			129			—	—		—			—			357			357
Distributions to noncontrolling interests	—	—		—			—		(4		)	(4		)	—	—		—			—			(21		)	(21		)
Purchase of membership interests from noncontrolling interests	—	—		—			—		(129		)	(129		)	—	—		—			—			(129		)	(129		)
Net income attributable to noncontrolling interests	—	—		—			—		1			1			—	—		—			—			36			36
Other	—	(35	)				—		—			—			—	(46	)	(7		)	—			—			(7		)
Balance at March 31, 2016	921,645	(3,387	)	$	20,797		$	609	$	778		$	22,184
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. ~~Subsequent to March 31,~~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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)


(E)	FINANCING

Going Concern

As of ~~March 31,~~September 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately ~~$1.2 billion~~$769 million primarily due to ~~a $1.2 billion unsecured term loan~~approximately $935 million that ~~matures on March~~will be required through September 30, 2018 to fund maturities of long-term debt and ~~$35~~$4 million ~~in senior notes~~ that ~~mature on November 15, 2017, as well as $36 million~~will be required to fund maturities of short-term ~~notes payable,~~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 ~~expects the funds needed~~intends to ~~satisfy maturing debt obligations will exceed amounts available from~~utilize operating cash flows, lines of credit, and ~~other external sources. Accordingly, Mississippi Power intends to satisfy these obligations through~~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.~~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, consistent with GAAP.~~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.~~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 (Loan~~Loan Guarantee ~~Agreement)~~Agreement with the DOE and related multi-advance term loan facility (FFB Credit Facility) with the FFB.

~~Advances~~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%.

~~Future~~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. The Contractor's bankruptcy and failure to perform its obligations under the Vogtle 3 and 4 Agreement could impact Georgia Power's ability to make further borrowings under the Loan Guarantee Agreement.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(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 Agreement under certain circumstances; (ii)~~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 ~~(iii)~~(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.

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

Under the FFB Credit Facility, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.

~~In connection with any cancellation of Plant Vogtle Units 3 and 4 that results in a mandatory prepayment event,~~On September 28, 2017, the DOE ~~may elect~~issued a conditional commitment to ~~continue construction~~Georgia Power for up to approximately $1.67 billion of ~~Plant Vogtle Units 3~~additional guaranteed loans under the Loan Guarantee Agreement. Final approval and ~~4. In such an event,~~issuance of these additional loan guarantees by the DOE ~~will have~~cannot be assured and are subject to the ~~right to assume Georgia Power's rights~~negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and ~~obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion~~satisfaction of ~~Georgia Power's ownership interest in Plant Vogtle Units 3 and 4.~~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 ~~March 31,~~September 30, 2017 was approximately ~~$1.9~~$1.5 billion (comprised of approximately ~~$890~~$854 million at Alabama Power, ~~$868~~$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 ~~March 31,~~September 30, 2017, the traditional electric operating companies had approximately ~~$386~~$699 million (comprised of approximately ~~$250~~$509 million at Georgia Power, ~~$86~~$140 million at Gulf Power, and $50 million at Mississippi Power) of ~~fixed rate~~ pollution control revenue bonds outstanding that were required to be ~~reoffered~~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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

The following table outlines the committed credit arrangements by company as of ~~March 31,~~September 30, 2017:


	Expires										Executable Term Loans				Expires Within One Year				Expires														Executable Term Loans				Expires Within One Year
Company	2017		2018		2020		Total		Unused		One Year		Two Years		Term Out		No Term Out		2017		2018		2019		2020		2022		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)																		(in millions)
Southern Company^(a)	$	—	$	1,000	$	1,250	$	2,250	$	2,250	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	2,000	$	2,000	$	2,000	$	—	$	—	$	—	$	—
Alabama Power	35		500		800		1,335		1,335		—		—		—		35		—		35		—		500		800		1,335		1,335		—		—		—		35
Georgia Power	—		—		1,750		1,750		1,732		—		—		—		—		—		—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	85		195		—		280		280		45		—		25		70		30		195		25		30		—		280		280		45		—		—		40
Mississippi Power	173		—		—		173		141		—		13		13		160		100		—		—		—		—		100		100		—		—		—		100
Southern Power Company(b)	—		—		600		600		524		—		—		—		—		—		—		—		—		750		750		728		—		—		—		—
Southern Company Gas^(b)(c)	75		1,925		—		2,000		1,949		—		—		—		75		—		—		—		—		1,900		1,900		1,861		—		—		—		—
Other	55		—		—		55		55		20		—		20		35		—		30		—		—		—		30		30		20		—		20		10
Southern Company Consolidated	$	423	$	3,620	$	4,400	$	8,443	$	8,266	$	65	$	13	$	58	$	375	$	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 $~~1.3~~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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Financing Activities

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


Company^(a)	Senior Note Issuances		Senior Note Maturities and Redemptions		Other Long-Term Debt Issuances		Other Long-Term Debt Redemptions and Maturities^(b)		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)								(in millions)
Southern Company^(c)(b)	$	—	$	—	$	—	$	400	$	300	$	400	$	—	$	500		$	400
Alabama Power	550		200		—		—		550		200		36		—			—
Georgia Power	850		—		—		2		1,350		450		65		370			13
Gulf Power	—		—		6		—		300		85		—		6			—
Mississippi Power									—		—		—		40			893
Southern Power	—		—		3		2		—		—		—		43			4
Southern Company Gas^(c)									450		—		—		200			22
Other	—		—		—		4		—		—		—		—			12
Elimination^(d)									—		—		—		(40		)	(599		)
Southern Company Consolidated	$	1,400	$	200	$	9	$	408	$	2,950	$	1,135	$	101	$	1,119		$	745


(a)	~~Mississippi Power and Southern Company Gas did not issue or redeem any long-term debt during the first three months of 2017.~~


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


~~(c)~~(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 ~~March~~June 2017, Southern Company ~~repaid~~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 ~~maturity~~ a ~~$400~~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 ~~18-month~~aggregate principal amount floating rate bank ~~loan.~~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.

Alabama Power

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(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 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.

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.

Gulf Power

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,

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

OnIn 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 ~~28,~~ 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.

OnIn 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 ~~31,~~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 $9floating rate promissory note to Southern Company in an aggregate principal amount of up to $150 million ~~short-term note~~ bearing interest ~~at 5% per annum, which was~~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 ~~on April 27,~~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

Southern Company Gas

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~


(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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Components of the net periodic benefit costs for the three and nine months ended ~~March 31,~~September 30, 2017 and 2016 are presented in the following tables.


Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)															(in millions)
Three Months Ended March 31, 2017
Three Months Ended September 30, 2017
Service cost	$	73		$	16		$	19		$	3		$	4		$	73		$	15		$	19		$	3		$	4
Interest cost	114			24			34			5			5			114			25			34			5			5
Expected return on plan assets	(224		)	(49		)	(71		)	(10		)	(10		)	(224		)	(49		)	(71		)	(10		)	(9		)
Amortization:
Prior service costs	3			1			1			—			—			3			1			—			—			—
Net (gain)/loss	40			10			14			2			2			41			10			15			2			1
Net periodic pension cost (income)	$	6		$	2		$	(3	)	$	—		$	1		$	7		$	2		$	(3	)	$	—		$	1
Three Months Ended March 31, 2016
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	$	62		$	14		$	17		$	3		$	3		$	68		$	14		$	17		$	3		$	3
Interest cost	100			24			34			5			5			110			23			34			5			4
Expected return on plan assets	(187		)	(46		)	(64		)	(9		)	(9		)	(203		)	(46		)	(64		)	(9		)	(9		)
Amortization:
Prior service costs	4			1			1			—			—			3			1			1			—			1
Net (gain)/loss	38			10			14			2			2			45			10			14			2			2
Net periodic pension cost	$	17		$	3		$	2		$	1		$	1		$	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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Pension Plans
Southern
Company
Gas
(in millions)
Successor – Three Months Ended March 31, 2017
Service cost $ 6
Interest cost 10
Expected return on plan assets (18 )
Amortization:
Prior service costs —
Net (gain)/loss 5
Net periodic pension cost $ 3

Predecessor – Three Months Ended March 31, 2016
Service cost $ 6
Interest cost 10
Expected return on plan assets (16 )
Amortization:
Prior service costs —
Net (gain)/loss 6
Net periodic pension cost $ 6


Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power
Pension Plans														Southern Company Gas
	(in millions)													(in millions)
Three Months Ended March 31, 2017
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	$	6		$	1		$	2		$	—	$	—	$	17
Interest cost	20			5			7			1		1		30
Expected return on plan assets	(16		)	(6		)	(6		)	—		—		(53		)
Amortization:
Prior service costs	2			1			—			—		—		(1		)
Net (gain)/loss	2			—			2			—		—		15
Net periodic postretirement benefit cost	$	14		$	1		$	5		$	1	$	1
Three Months Ended March 31, 2016
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	$	5		$	1		$	2		$	—	$	—	$	13
Interest cost	18			5			8			1		1		21
Expected return on plan assets	(14		)	(6		)	(6		)	—		—		(33		)
Amortization:
Prior service costs	2			1			—			—		—		(1		)
Net (gain)/loss	3			—			2			—		—		13
Net periodic postretirement benefit cost	$	14		$	1		$	6		$	1	$	1
Net periodic pension cost														$	13

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)


Postretirement Benefits	Southern Company Gas			Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)			(in millions)
Successor – Three Months Ended March 31, 2017
Three Months Ended September 30, 2017
Service cost	$	1		$	6		$	1		$	2		$	—		$	—
Interest cost	3			19			4			6			1			1
Expected return on plan assets	(2		)	(16		)	(5		)	(6		)	—			—
Amortization:
Prior service costs	(1		)	2			1			—			—			—
Net (gain)/loss	1			3			—			3			—			—
Net periodic postretirement benefit cost	$	2		$	14		$	1		$	5		$	1		$	1


Predecessor – Three Months Ended March 31, 2016
Nine Months Ended September 30, 2017
Service cost	$	1		$	18		$	4		$	5		$	1		$	1
Interest cost	3			59			13			21			2			3
Expected return on plan assets	(2		)	(49		)	(19		)	(18		)	(1		)	(1		)
Amortization:
Prior service costs	(1		)	5			3			1			—			—
Net (gain)/loss	1			10			1			6			—			—
Net periodic postretirement benefit cost	$	2		$	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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(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 ~~March 31,~~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, ~~and~~increased generation at existing wind facilities, carrying back the federal net operating loss, ~~as well as~~and potential tax reform legislation, ~~on existing renewable incentives, could further delay existing tax credit carryforwards.~~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 ~~32.1%~~42.6% for the ~~three~~nine months ended ~~March 31,~~September 30, 2017 compared to ~~30.2%~~28.3% for the corresponding period in 2016. The effective tax rate increase was primarily due to ~~higher pre-tax earnings resulting from~~ the ~~Merger with Southern Company Gas and decreased~~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 and state apportionment rate changes.~~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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Mississippi Power

Mississippi Power's effective tax (benefit) rate was ~~(58.7)~~(30.3)% for the ~~three~~nine months ended ~~March 31,~~September 30, 2017 compared to ~~(850.4)~~(282.8)% for the corresponding period in 2016. The effective tax rate increase was primarily due to the estimated probable losses on ~~construction~~the Kemper IGCC, net of the ~~Kemper IGCC.~~non-deductible AFUDC equity portion and the related state valuation allowances.

Southern Power

Southern Power's effective tax (benefit) rate was ~~(385.9)~~(66.5)% for the ~~three~~nine months ended ~~March 31,~~September 30, 2017 compared to ~~(84.0)~~(88.9)% for the corresponding period in 2016. The effective tax rate ~~decrease~~increase was primarily due to ~~additional PTCs arising from Southern Power's wind facility acquisitions, state apportionment rate changes, and lower pre-tax earnings, partially offset by~~ a decrease in tax benefits from ~~ITCs.~~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.

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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

~~Changes during the three months ended March 31, 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 3
1
9
Tax positions from prior periods —
—
7
Balance as of March 31, 2017 $ 468
$ 18
$ 500

The tax positions from current and prior periods primarily relate to state tax benefits, deductions for R&E expenditures, and charitable contribution carryforwards that ~~will be~~were impacted as a result of the ~~proposed~~ settlement of ~~research and experimental (R&E)~~R&E expenditures associated with the Kemper ~~IGCC.~~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 March 31, 2017						As of December 31, 2016		As of September 30, 2017				As of December 31, 2016
	Mississippi Power		Southern Power		Southern Company		Southern Company		Mississippi Power		Southern Company		Southern Company
	(in millions)								(in millions)
Tax positions impacting the effective tax rate	$	4	$	18	$	36	$	20	$	2	$	17	$	20
Tax positions not impacting the effective tax rate	464		—		464		464		—		—		464
Balance of unrecognized tax benefits	$	468	$	18	$	500	$	484	$	2	$	17	$	484

The tax positions impacting the effective tax rate primarily relate to ~~federal deferred income tax credits and Southern Company's estimate of the uncertainty related to the amount of those benefits, and~~ state tax benefits and charitable contribution carryforwards that ~~will be~~were impacted as a result of the ~~proposed~~ settlement of R&E expenditures associated with the Kemper IGCC. See "Section 174 Research and Experimental Deduction" herein for additional information. If these tax positions are not able to be recognized due to a federal audit adjustment in the amount that has been estimated, the amount of tax credit carryforwards discussed above would be reduced by approximately $98 million.

Accrued interest for all tax positions ~~other than the Section 174 R&E deductions~~ 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 ~~and the U.S. Congress Joint Committee on Taxation approval of the R&E expenditures associated with the Kemper IGCC~~ could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. ~~See "Section 174 Research and Experimental Deduction" herein for more information.~~

The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through ~~2012. Southern Company has filed its 2013, 2014, and 2015 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits.~~2016. Southern Company is a participant in the Compliance Assurance Process of the IRS. ~~In addition,~~However, the pre-Merger Southern Company Gas 2014, 2015, and June 30, 2016 federal tax

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

~~return is~~ 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

The Kemper IGCC is based on first-of-a-kind technology, and Southern Company and Mississippi Power believe that a significant portion of the plant costs qualify as deductible R&E expenditures under Internal Revenue Code Section 174. In December 2016, Southern Company and the IRS reached a proposed settlement, ~~subject to approval of~~which was approved on September 8, 2017 by the U.S. Congress Joint Committee on Taxation (JCT), resolving a methodology for these deductions. ~~Due to~~As a result of the ~~uncertainty related to this tax position,~~JCT approval, Southern Company ~~and Mississippi Power had~~recognized $176 million of previously unrecognized tax benefits and reversed $36 million of associated ~~with these R&E deductions totaling approximately $464 million and associated interest~~accrued interest. If the suspension of ~~$32 million~~the Kemper IGCC start-up activities results in an abandonment, any amount not allowed under IRC Section 174 would be claimed as ~~of March 31, 2017. This matter is expected to be resolved~~a deduction under IRC Section 165 in the ~~next 12 months; however, 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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(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 ~~through~~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

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(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 ~~March 31,~~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	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)			(in millions)
Southern Company^(*)	503	2021	2024	463	2021	2024
Alabama Power	71	2020	—	66	2020	—
Georgia Power	155	2020	—	159	2021	—
Gulf Power	42	2020	—	28	2020	—
Mississippi Power	37	2021	—	44	2021	—
Southern Power	21	2017	2017	13	2018	—
Southern Company Gas^(*)	177	2019	2024	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 ~~3.4~~3.3 billion mmBtu and short natural gas positions of ~~3.2~~3.1 billion mmBtu as of ~~March 31,~~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 1034 million mmBtu for Southern Company, 411 million mmbtu for Georgia Power and Southern Power, 5 million mmbtu for Alabama Power, 3 million mmBtu for ~~Southern~~Gulf Power, and 14 million mmBtu for ~~each of Alabama Power, Gulf Power, and~~ Mississippi Power.

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

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 ~~March 31,~~September 30, 2018 are ~~$10~~$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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At ~~March 31,~~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 March 31, 2017			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)			(in millions)					(in millions)
Cash Flow Hedges of Forecasted Debt
Gulf Power	$	80	3-month LIBOR	2.32%	December 2026	$	—
Cash Flow Hedges of Existing Debt	Cash Flow Hedges of Existing Debt								Cash Flow Hedges of Existing Debt
Mississippi Power	900		1-month LIBOR	0.79%	March 2018	4			$	900	1-month LIBOR	0.79%	March 2018	$	2
Fair Value Hedges of Existing Debt	Fair Value Hedges of Existing Debt								Fair Value Hedges of Existing Debt
Southern Company^(*)	250		1.30%	3-month LIBOR + 0.17%	August 2017	—
Southern Company^(*)	300		2.75%	3-month LIBOR + 0.92%	June 2020	1			300		2.75%	3-month LIBOR + 0.92%	June 2020	—
Southern Company^(*)	1,500		2.35%	1-month LIBOR + 0.87%	July 2021	(21		)	1,500		2.35%	1-month LIBOR + 0.87%	July 2021	(19		)
Georgia Power	250		5.40%	3-month LIBOR + 4.02%	June 2018	—			250		5.40%	3-month LIBOR + 4.02%	June 2018	—
Georgia Power	500		1.95%	3-month LIBOR + 0.76%	December 2018	(3		)	500		1.95%	3-month LIBOR + 0.76%	December 2018	(2		)
Georgia Power	200		4.25%	3-month LIBOR + 2.46%	December 2019	1			200		4.25%	3-month LIBOR + 2.46%	December 2019	—
Southern Company Consolidated	$	3,980				$	(18	)	$	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 ~~March 31,~~September 30, 2018 are $(19) million for Southern Company and immaterial for all other registrants.

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At ~~March 31,~~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 March 31, 2017			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)			(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt	Cash Flow Hedges of Existing Debt										Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	(35	)	$	677	2.95%	€	600	1.00%	June 2022	$	42
Southern Power	564		3.78%	500		1.85%	June 2026	(27		)	564		3.78%	500		1.85%	June 2026	38
Total	$	1,241		€	1,100			$	(62	)	$	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 ~~March 31,~~September 30, 2018 are ~~$24~~$(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.

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 March 31, 2017						As of December 31, 2016						As of September 30, 2017						As of December 31, 2016
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities			Assets			Liabilities			Assets			Liabilities
	(in millions)												(in millions)
Southern Company
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Liabilities from risk management activities, net of collateral	$	48		$	30		$	73		$	27
Other current assets/Other current liabilities													$	21		$	25		$	73		$	27
Other deferred charges and assets/Other deferred credits and liabilities	6			38			25			33			13			23			25			33
Total derivatives designated as hedging instruments for regulatory purposes	$	54		$	68		$	98		$	60		$	34		$	48		$	98		$	60
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Liabilities from risk management activities, net of collateral	$	14		$	5		$	23		$	7
Other current assets/Other current liabilities													$	8		$	6		$	23		$	7
Interest rate derivatives:
Other current assets/Liabilities from risk management activities, net of collateral	13			—			12			1
Other current assets/Other current liabilities													5			1			12			1
Other deferred charges and assets/Other deferred credits and liabilities	—			32			1			28			—			23			1			28
Foreign currency derivatives:
Other current assets/Liabilities from risk management activities, net of collateral	—			25			—			25
Other current assets/Other current liabilities													—			23			—			25
Other deferred charges and assets/Other deferred credits and liabilities	—			37			—			33			103			—			—			33
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	27		$	99		$	36		$	94		$	116		$	53		$	36		$	94
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Liabilities from risk management activities, net of collateral	$	306		$	271		$	489		$	483
Other current assets/Other current liabilities													$	271		$	254		$	489		$	483
Other deferred charges and assets/Other deferred credits and liabilities	132			114			66			81			115			103			66			81
Interest rate derivatives:
Other current assets/Liabilities from risk management activities, net of collateral	—			—			1			—
Other current assets/Other current liabilities													—			—			1			—
Total derivatives not designated as hedging instruments	$	438		$	385		$	556		$	564		$	386		$	357		$	556		$	564
Gross amounts recognized	$	519		$	552		$	690		$	718		$	536		$	458		$	690		$	718
Gross amounts offset^(*)	$	(303	)	$	(395	)	$	(462	)	$	(524	)	$	(275	)	$	(351	)	$	(462	)	$	(524	)
Net amounts recognized in the Balance Sheets	$	216		$	157		$	228		$	194		$	261		$	107		$	228		$	194

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)


	As of March 31, 2017						As of December 31, 2016						As of September 30, 2017						As of December 31, 2016
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities			Assets			Liabilities			Assets			Liabilities
	(in millions)												(in millions)

Alabama Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Liabilities from risk management activities	$	9		$	5		$	13		$	5
Other current assets/Other current liabilities													$	6		$	4		$	13		$	5
Other deferred charges and assets/Other deferred credits and liabilities	2			5			7			4			3			3			7			4
Total derivatives designated as hedging instruments for regulatory purposes	$	11		$	10		$	20		$	9		$	9		$	7		$	20		$	9
Gross amounts recognized	$	11		$	10		$	20		$	9		$	9		$	7		$	20		$	9
Gross amounts offset	$	(6	)	$	(6	)	$	(8	)	$	(8	)	$	(5	)	$	(5	)	$	(8	)	$	(8	)
Net amounts recognized in the Balance Sheets	$	5		$	4		$	12		$	1		$	4		$	2		$	12		$	1

Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	20		$	2		$	30		$	1		$	10		$	3		$	30		$	1
Other deferred charges and assets/Other deferred credits and liabilities	4			11			14			7			8			8			14			7
Total derivatives designated as hedging instruments for regulatory purposes	$	24		$	13		$	44		$	8		$	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	$	2		$	—		$	2		$	—		$	1		$	1		$	2		$	—
Other deferred charges and assets/Other deferred credits and liabilities	—			4			—			3			—			2			—			3
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	2		$	4		$	2		$	3		$	1		$	3		$	2		$	3
Gross amounts recognized	$	26		$	17		$	46		$	11		$	19		$	14		$	46		$	11
Gross amounts offset	$	(6	)	$	(6	)	$	(8	)	$	(8	)	$	(10	)	$	(10	)	$	(8	)	$	(8	)
Net amounts recognized in the Balance Sheets	$	20		$	11		$	38		$	3		$	9		$	4		$	38		$	3

Gulf Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Liabilities from risk management activities	$	2		$	14		$	4		$	12
Other current assets/Other current liabilities													$	—		$	13		$	4		$	12
Other deferred charges and assets/Other deferred credits and liabilities	—			17			1			17			—			9			1			17
Total derivatives designated as hedging instruments for regulatory purposes	$	2		$	31		$	5		$	29		$	—		$	22		$	5		$	29
Gross amounts recognized	$	2		$	31		$	5		$	29		$	—		$	22		$	5		$	29
Gross amounts offset	$	(2	)	$	(2	)	$	(4	)	$	(4	)	$	—		$	—		$	(4	)	$	(4	)
Net amounts recognized in the Balance Sheets	$	—		$	29		$	1		$	25		$	—		$	22		$	1		$	25

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)


	As of March 31, 2017						As of December 31, 2016						As of September 30, 2017						As of December 31, 2016
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities			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	$	3		$	7		$	2		$	6		$	1		$	4		$	2		$	6
Other deferred charges and assets/Other deferred credits and liabilities	—			5			2			5			2			3			2			5
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	12		$	4		$	11		$	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	$	4		$	—		$	2		$	—		$	2		$	—		$	2		$	—
Other deferred charges and assets/Other deferred credits and liabilities	—			—			1			—			—			—			1			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	4		$	—		$	3		$	—		$	2		$	—		$	3		$	—
Gross amounts recognized	$	7		$	12		$	7		$	11		$	5		$	7		$	7		$	11
Gross amounts offset	$	(2	)	$	(2	)	$	(3	)	$	(3	)	$	(3	)	$	(3	)	$	(3	)	$	(3	)
Net amounts recognized in the Balance Sheets	$	5		$	10		$	4		$	8		$	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	$	13		$	4		$	18		$	4		$	8		$	4		$	18		$	4
Foreign currency derivatives:
Other current assets/Other current liabilities	—			25			—			25			—			23			—			25
Other deferred charges and assets/Other deferred credits and liabilities	—			37			—			33			103			—			—			33
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	13		$	66		$	18		$	62		$	111		$	27		$	18		$	62
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	2		$	1		$	3		$	1		$	1		$	—		$	3		$	1
Interest rate derivatives:
Other current assets/Other current liabilities	—			—			1			—			—			—			1			—
Total derivatives not designated as hedging instruments	$	2		$	1		$	4		$	1		$	1		$	—		$	4		$	1
Gross amounts recognized	$	15		$	67		$	22		$	63		$	112		$	27		$	22		$	63
Gross amounts offset	$	(3	)	$	(3	)	$	(5	)	$	(5	)	$	(1	)	$	(1	)	$	(5	)	$	(5	)
Net amounts recognized in the Balance Sheets	$	12		$	64		$	17		$	58		$	111		$	26		$	17		$	58

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)


	As of March 31, 2017						As of December 31, 2016						As of September 30, 2017						As of December 31, 2016
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities			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	$	14		$	2		$	24		$	3		$	4		$	1		$	24		$	3
Other deferred charges and assets/Other deferred credits and liabilities	—			—			1			—			—			—			1			—
Total derivatives designated as hedging instruments for regulatory purposes	$	14		$	2		$	25		$	3		$	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	$	1		$	1		$	4		$	3		$	—		$	2		$	4		$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	304		$	270		$	486		$	482		$	270		$	254		$	486		$	482
Other deferred charges and assets/Other deferred credits and liabilities	132			114			66			81			115			103			66			81
Total derivatives not designated as hedging instruments	$	436		$	384		$	552		$	563		$	385		$	357		$	552		$	563
Gross amounts of recognized	$	451		$	387		$	581		$	569		$	389		$	360		$	581		$	569
Gross amounts offset^(*)	$	(272	)	$	(364	)	$	(435	)	$	(497	)	$	(251	)	$	(327	)	$	(435	)	$	(497	)
Net amounts recognized in the Balance Sheets	$	179		$	23		$	146		$	72		$	138		$	33		$	146		$	72


(*)	Gross amounts offset include cash collateral held on deposit in broker margin accounts of ~~$92~~$76 million and $62 million as of ~~March 31,~~September 30, 2017 and December 31, 2016, respectively.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At ~~March 31,~~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 March 31, 2017
Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at September 30, 2017																			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^(b)			Southern Company^(b)			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas^(c)
	(in millions)																		(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(19	)	$	(1	)	$	—		$	(12	)	$	(5	)	$	(1	)	$	(18	)	$	(1	)	$	—		$	(13	)	$	(3	)	$	(1	)
Other regulatory assets, deferred	(32		)	(3		)	(7		)	(17		)	(5		)	—			(12		)	(1		)	(1		)	(9		)	(1		)	—
Other regulatory liabilities, current^(a)	33			5			18			—			1			9			14			3			7			—			—			4
Other regulatory liabilities, deferred^(b)																			2			1			1			—			—			—
Total energy-related derivative gains (losses)	$	(18	)	$	1		$	11		$	(29	)	$	(9	)	$	8		$	(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 $4$1 million at ~~March 31,~~September 30, 2017.

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~



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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the three months ended ~~March 31,~~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)							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							Statements of Income Location	Amount												Statements of Income Location	Amount
	2017			2016				2017			2016			2017			2016				2017			2016
	(in millions)							(in millions)						(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	(11	)	$	—		Depreciation and amortization	$	(4	)	$	(1	)	$	(6	)	$	—		Depreciation and amortization	$	(6	)	$	1
Interest rate derivatives	1			(190		)	Interest expense, net of amounts capitalized	(5		)	(3		)	(1		)	(6		)	Interest expense, net of amounts capitalized	(5		)	(6		)
Foreign currency derivatives	(4		)	—			Interest expense, net of amounts capitalized	(6		)	—			46			37			Interest expense, net of amounts capitalized	(5		)	(6		)
							Other income (expense), net^(*)	17			—									Other income (expense), net^(*)	43			7
Total	$	(14	)	$	(190	)		$	2		$	(4	)	$	39		$	31			$	27		$	(4	)
Gulf Power
Energy-related derivatives	$	(1	)	$	—		Depreciation and amortization	$	—		$	—
Alabama Power
Interest rate derivatives	—			(5		)	Interest expense, net of amounts capitalized	—			—			$	—		$	—		Interest expense, net of amounts capitalized	$	(2	)	$	(2	)
Total	$	(1	)	$	(5	)		$	—		$	—
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	$	(8	)	$	—		Depreciation and amortization	$	(4	)	$	(1	)	$	(6	)	$	—		Depreciation and amortization	$	(6	)	$	1
Foreign currency derivatives	(4		)	—			Interest expense, net of amounts capitalized	(6		)	—			46			37			Interest expense, net of amounts capitalized	(5		)	(6		)
							Other income (expense), net^(*)	17			—									Other income (expense), net^(*)	43			7
Total	$	(12	)	$	—			$	7		$	(1	)	$	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.

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)
Derivatives in Cash Flow Hedging Relationships							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 ~~three~~successor nine months ended ~~March 31,~~September 30, 2017, the successor period of July 1, 2016 through September 30, 2016, and the predecessor period of January 1, 2016 through ~~March 31,~~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)
	Successor			Predecessor				Successor		Predecessor		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	Three Months Ended March 31, 2017			Three Months Ended March 31, 2016			Statements of Income Location	Three Months Ended March 31, 2017		Three Months Ended March 31, 2016		Nine Months Ended September 30, 2017			Statements of Income Location	Nine Months Ended September 30, 2017
	(in millions)			(in millions)				(in millions)		(in millions)		(in millions)				(in millions)
Energy-related derivatives	$	(2	)	$	—		Cost of natural gas	$	—	$	—	$	(4	)	Cost of natural gas	$	—
Interest rate derivatives	—			(45		)	Interest expense, net of amounts capitalized	—		1
Total	$	(2	)	$	(45	)		$	—	$	1

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 ~~March 31,~~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 ~~March 31,~~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)						Gain (Loss)
		Three Months Ended March 31,						Three Months Ended September 30,					Nine Months Ended September 30,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2017			2016		Statements of Income Location	2017			2016		2017			2016
		(in millions)						(in millions)					(in millions)
Southern Company
Energy Related derivatives:	Natural gas revenues^(*)	$	50		$	—	Natural gas revenues^(*)	$	(17	)	$	—	$	48		$	—
	Cost of natural gas	(3		)	—		Cost of natural gas	2			6		(2		)	6
Total derivatives in non-designated hedging relationships	Total derivatives in non-designated hedging relationships	$	47		$	—	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 ~~$14~~$15 million for the ~~three~~nine months ended ~~March 31, 2017.~~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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Gain (Loss)
Successor Predecessor
Derivatives in Non-Designated Hedging Relationships Statements of Income Location
Three Months Ended
March 31, 2017

Three Months Ended
March 31, 2016
(in millions) (in millions)
Southern Company Gas
Energy Related derivatives:
Natural gas revenues^(*)
$ 50
$ 20
Cost of natural gas (3 ) (1 )
Total derivatives in non-designated hedging relationships $ 47
$ 19


~~(*)~~	Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $14 million for the successor three months ended March 31, 2017 and $3 million for the predecessor three months ended March 31, 2016.

For the three and nine months ended ~~March 31,~~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)						Gain (Loss)
		Three Months Ended March 31,						Three Months Ended September 30,						Nine Months Ended September 30,
Derivative Category	Statements of Income Location	2017			2016		Statements of Income Location	2017			2016			2017			2016
		(in millions)						(in millions)
Southern Company
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	(8	)	$	20	Interest expense, net of amounts capitalized	$	(5	)	$	(9	)	$	(6	)	$	15
Georgia Power
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	(1	)	$	14	Interest expense, net of amounts capitalized	$	—		$	(5	)	$	(1	)	$	10

For the three and nine months ended ~~March 31,~~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 ~~March 31,~~September 30, 2017, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

At ~~March 31,~~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 ~~$11 million~~immaterial for ~~Southern Company, $9 million for the traditional electric operating companies and Southern Power, and $2 million for Southern Company Gas.~~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.

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

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 ~~maintains~~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 ~~March 31,~~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 ~~March 31,~~September 30, 2017, cash collateral held on deposit in broker margin accounts was ~~$92~~$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

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 Gasconducts 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.

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.

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

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 ~~$1.6~~$565 million and $2.8 billion and net income of ~~$239~~$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 ~~March 31, 2017.~~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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)


	For the Three Months Ended March 31,		For the Nine Months Ended September 30,
	2016		2016
Operating revenues (in millions)	$	5,320	$	16,609
Net income attributable to Southern Company (in millions)	$	650	$	2,394
Basic EPS	$	0.70
Basic Earnings Per Share (EPS)			$	2.52
Diluted EPS	$	0.69	$	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.

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

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)			(in millions)
Current assets	$	172		$	172
Property, plant, and equipment	46			46
Intangible assets	101			106
Goodwill	282			284
Other assets	4			4
Current liabilities	(114		)	(121		)
Long-term debt, including current portion	(48		)	(48		)
Deferred credits and other liabilities	(14		)	(14		)
Total purchase price	$	429		$	429

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of ~~$282~~$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.

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 ~~Three~~Nine Months Ended ~~March 31,~~September 30, 2017



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

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

The aggregate ~~amount~~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 ~~during the first quarter~~for year-to-date 2017 is $4 million. The aggregate amount of net income, excluding impacts from PTCs, recognized by Southern Power during the three months ended March 31, 2017 included in Southern Power's condensed consolidated statements of income waswere 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, ~~subsequent to March 31, 2017,~~ 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.

Construction Projects Completed and in Progress



Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
~~Project~~Projects Completed During the ~~Three~~Nine Months Ended ~~March 31,~~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 ~~March 31,~~September 30, 2017
~~Lamesa~~ Cactus Flats^(*)	~~Solar~~Wind	~~102~~148	~~Dawson~~Concho County, TX	~~April 2017~~Third quarter 2018	1512-15 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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Development Projects

Southern Company Gas

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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments as of ~~March 31,~~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 ~~March 31, 2017~~September 30, 2016, and for the predecessor period ~~ended March 31,~~January 1, 2016 through June 30, 2016 were as follows:



Balance Sheet Information	March 31, 2017		December 31, 2016		September 30, 2017		December 31, 2016
	(in millions)				(in millions)
SNG	$	1,430	$	1,394	$	1,385	$	1,394
Atlantic Coast Pipeline					61		33
PennEast Pipeline					49		22
Triton	44		44		43		44
Pivotal JAX LNG, LLC					40		16
Horizon Pipeline	31		30		30		30
PennEast Pipeline	30		22
Atlantic Coast Pipeline	42		33
Pivotal JAX LNG, LLC	26		16
Other	1		2		1		2
Total	$	1,604	$	1,541	$	1,609	$	1,541


	Successor		Predecessor		Successor		Successor		Successor		Predecessor
Income Statement Information	Three Months Ended March 31, 2017		Three Months Ended March 31, 2016		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	$	34	$	—	$	28	$	27	$	86	$	—
Horizon Pipeline	1		1
PennEast Pipeline	3		—		1		—		5		—
Atlantic Coast Pipeline	1		—		1		1		4		—
Triton					1		1		3		1
Horizon Pipeline					1		—		2		1
Total	$	39	$	1	$	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 ~~first quarter~~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 March 31, 2017		Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017		September 1, 2016 through September 30, 2016
	(in millions)		(in millions)
Revenues	$	155	$	146	$	445	$	82
Operating income	$	84	$	71	$	218	$	60
Net income	$	66	$	57	$	172	$	55

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(K) SEGMENT AND RELATED INFORMATION

Southern Company

The primary ~~business~~businesses of the Southern Company system isare 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 ~~$100~~$105 million and $295 million for the three and nine months ended ~~March 31,~~September 30, 2017, respectively, and ~~$97~~$110 million and $313 million for the three and nine months ended ~~March 31, 2016.~~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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Financial data for business segments and products and services for the three and nine months ended ~~March 31,~~September 30, 2017 and 2016 was as follows:


	Electric Utilities																			Electric Utilities
	Traditional Electric Operating Companies		Southern Power		Eliminations			Total		Southern Company Gas		All Other			Eliminations			Consolidated		Traditional Electric Operating Companies		Southern Power		Eliminations			Total		Southern Company Gas		All Other			Eliminations			Consolidated
	(in millions)																			(in millions)
Three Months Ended March 31, 2017:
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	$	3,786	$	450	$	(105	)	$	4,131	$	1,560	$	123		$	(43	)	$	5,771	$	12,960	$	1,597	$	(318	)	$	14,239	$	2,841	$	442		$	(119	)	$	17,403
Segment net income (loss)^(a)(b)(c)	432		70		—			502		239		(84		)	1			658		—		276		—			276		303		(232		)	—			347
Total assets at March 31, 2017	$	72,692	$	14,681	$	(306	)	$	87,067	$	21,683	$	2,574		$	(1,564	)	$	109,760
Three Months Ended March 31, 2016:
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	$	3,769	$	315	$	(103	)	$	3,981	$	—	$	47		$	(36	)	$	3,992	$	13,120	$	1,189	$	(330	)	$	13,979	$	543	$	311		$	(118	)	$	14,715
Segment net income (loss)^(a)(b)	465		50		—			515		—		(23		)	(3		)	489		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	$	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 ~~$108~~$34 million ($6721 million after tax) and ~~$53~~$88 million ($3354 million after tax) for the three months ended ~~March 31,~~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 ~~three~~nine months ended ~~March 31,~~September 30, 2017. See Note (B) under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information.

~~NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)~~

~~(UNAUDITED)~~

Products and Services

Electric Utilities' Revenues
Period Retail Wholesale Other Total
(in millions)
Three Months Ended March 31, 2017 $ 3,394
$ 531
$ 206
$ 4,131
Three Months Ended March 31, 2016 3,377
396
208
3,981



	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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)


	Southern Company Gas' Revenues								Southern Company Gas' Revenues
Period	Gas Distribution Operations		Gas Marketing Services		Other		Total		Gas Distribution Operations		Gas Marketing Services		Other			Total
	(in millions)								(in millions)
Three Months Ended March 31, 2017	$	1,132	$	288	$	140	$	1,560
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

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

~~Business segment financial data for the successor period January 1, 2017 through March 31, 2017 and the predecessor period January 1, 2016 through March 31, 2016 was as follows:~~


	Gas Distribution Operations		Gas Marketing Services		Wholesale Gas Services^(*)		Gas Midstream Operations			Total		All Other			Eliminations			Consolidated		Gas Distribution Operations		Gas Marketing Services			Wholesale Gas Services^(*)			Gas Midstream Operations			Total		All Other			Eliminations			Consolidated
	(in millions)																			(in millions)
Successor – January 1, 2017 through March 31, 2017:
Successor – Three Months Ended September 30, 2016:																				Successor – Three Months Ended September 30, 2016:
Operating revenues	$	1,180	$	288	$	131	$	25		$	1,624	$	2		$	(66	)	$	1,560	$	455	$	126		$	(8	)	$	13		$	586	$	2		$	(45	)	$	543
Segment net income	117		31		68		15			231		8			—			239
Successor – Total assets at March 31, 2017	$	18,201	$	2,118	$	1,018	$	2,363		$	23,700	$	10,860		$	(12,877	)	$	21,683
Predecessor – January 1, 2016 through March 31, 2016:
Segment net income (loss)																				27		(4		)	(11		)	14			26		(22		)	—			4
Predecessor – January 1, 2016 through June 30, 2016:																				Predecessor – January 1, 2016 through June 30, 2016:
Operating revenues	$	1,028	$	286	$	63	$	15		$	1,392	$	2		$	(60	)	$	1,334	$	1,575	$	435		$	(32	)	$	25		$	2,003	$	4		$	(102	)	$	1,905
Segment EBIT	235		80		44		(1		)	358		(5		)	(1		)	352		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	$	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 – January 1, 2017 through March 31, 2017 $ 1,839
$ 136
$ 1,975
$ 1,844
$ 131
Predecessor – January 1, 2016 through March 31, 2016 $ 1,443
$ 81
$ 1,524
$ 1,461
$ 63



	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	)

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.

I~~tem~~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 ~~Westinghouse and WECTEC~~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 ~~Toshiba~~ 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, ~~Westinghouse and WECTEC each~~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 ~~and WECTEC Staffing Services LLC (WECTEC Staffing), as of March 29, 2017~~ (Interim Assessment Agreement), ~~to provide for a continuation of work with respect to Plant Vogtle Units 3 and 4. Georgia Power's entry into~~which the bankruptcy court approved on March 30, 2017.

The Interim Assessment Agreement was conditioned upon South Carolina Electric & Gas Company entering into a similar interim assessment agreement with the Contractor relating to V.C. Summer, which also occurred on March 29, 2017. The provisions in the Interim Assessment Agreement became effective upon approval of the Interim Assessment Agreement by the bankruptcy court on March 30, 2017. The term of the Interim Assessment Agreement was originally scheduled to expire on April 28, 2017. On April 28, 2017, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an amendment to the Interim Assessment Agreement with the Contractor and WECTEC Staffing solely to extendprovided, among other items, that during the term of the Interim Assessment Agreement ~~through the earlier of (i) May 12, 2017 and (ii) termination of the Interim Assessment Agreement by any party upon five business days' notice (Interim Assessment Period).~~

~~The Interim Assessment Agreement provides, among other items, that (i)~~ Georgia Power ~~will be~~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 during the Interim Assessment Period, with these amounts to be paid to the Contractor, except for amounts accrued for Fluor Corporation (Fluor), which will be paid directly to Fluor; (ii) during the Interim Assessment Period, the Contractor shall provide certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extent as contemplated by the engineering, procurement, and construction agreement with the Contractor (the Vogtle 3 and 4 Agreement), and Georgia Power, on behalf of the Vogtle Owners, will make payments of $5.4 million per week for these services; (iii) Georgia Power will have the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who have accounts past due with the Contractor; (iv) during the Interim Assessment Period, the Contractor will use its commercially reasonable efforts to provide information reasonably requested by Georgia Power as is necessary to continue construction and investigate the completion status of Plant Vogtle Units 3 and 4; (v) the Contractor will reject or accept the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) during the Interim Assessment Period, Georgia Power will not exercise any remedies against Toshiba under the Toshiba Guarantee. Under theprovided. The Interim Assessment Agreement, ~~all parties expressly reserve all rights and remedies under~~as amended, expired on July 27, 2017.

Subsequent to the ~~Vogtle 3 and 4 Agreement, all related security and collateral, under applicable law.~~

AEPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc. ~~(Fluor Enterprises)~~, ~~have~~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, ~~action~~actions to remove liens filed by these subcontractors through the posting of surety bonds.

Georgia Power estimates the aggregate liability, ~~for~~through September 30, 2017, of the Vogtle Owners ~~under the Interim Assessment Agreement and~~for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to betotal approximately ~~$470~~$386 million, of which $340 million had been paid or accrued as of September 30, 2017. Georgia Power's proportionate share ~~would total approximately $215 million. As of March 31, 2017, $245 million~~ of this aggregate liability had been paid or accrued. Georgia Power is evaluating remedies available to the Vogtle Owners for these payments, including draws under the $920 million of letters of credit delivered by Westinghouse (Westinghouse Letters of Credit) and enforcement of the Toshiba Guarantee.totaled approximately $176 million.

The Vogtle 3 and 4 Agreement also ~~provides~~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. In the event of an abandonment of work by the Contractor, the maximum liability of the Contractor under the Vogtle 3 and 4 Agreement is increased to 40% of the contract price~~million (approximately ~~$1.7 billion~~$420 million based on Georgia Power's ownership interest). The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for convenience, provided that the Vogtle Owners will be required to pay certain termination costs. In addition, the Vogtle Owners may terminate the Vogtle 3 and 4 Agreement for certain Contractor breaches, including abandonment of work by the Contractor.

On ~~April 11,~~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 ~~filed~~released its ~~unaudited~~ financial ~~statements as of and~~results for the ~~nine months~~quarter ended ~~December 31, 2016,~~June 30, 2017, which reflected a negative shareholders' equity balance of ~~$1.9~~approximately $4.5 billion ~~with Japanese regulators.~~as of June 30, 2017. Toshiba ~~also~~previously announced ~~that further substantial charges may be required in~~ the ~~quarter ended March 31, 2017 in connection with the bankruptcy filing~~existence of ~~Westinghouse and WECTEC and that there are~~ material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern.

In February 2017, the Contractor provided Georgia Power with revised forecasted in-service dates of December 2019 and September 2020 for Plant Vogtle Units 3 and 4, respectively. However, based on information subsequently made available during Westinghouse and WECTEC's bankruptcy proceedings and pursuant to the Interim Assessment Agreement, Georgia Power and As a result, substantial risk regarding the Vogtle ~~Owners do not believe~~Owners' ability to fully collect the revised in-service dates are achievable. Georgia Power, along with the other Vogtle Owners, is undertaking a comprehensive schedule and cost-to-complete assessment, as well as a cancellation cost assessment. It is reasonably possible these assessments result in estimated incremental costsGuarantee Obligations continues to complete, including owners' costs, that materially exceed the value of the Toshiba Guarantee. Georgia Power intends to work with the Georgia PSC and the other Vogtle Owners to determine future actions related to Plant Vogtle Units 3 and 4. Georgia Power, for itself and as agent for the other Vogtle Owners, is also negotiating a new service agreement which would, if necessary, engage the Contractor to provide design, engineering, and procurement services to Southern Nuclear, in the event Southern Nuclear assumes control over construction management. In addition, Georgia Power, on behalf of itself and the other Vogtle Owners, intends to take all actions available to it to enforce its rights related to the Vogtle 3 and 4 Agreement, including enforcing the Toshiba Guarantee, subject to the Interim Assessment Agreement, and accessing the Westinghouse Letters of Credit.

The Contractor's bankruptcy filing 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 Southern Company's

~~and Georgia Power's financial statements. In addition, an~~exist. An inability or other failure by Toshiba to perform its obligations under the ~~Toshiba~~ 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.

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.

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.

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.



	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 ultimate outcome of these matters ~~also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and~~ cannot be determined at this time.

I~~tem 5. Other Information.~~

On April 28, 2017, the Board of Directors of Gulf Power approved certain amendments to Section 7 of Gulf Power's Bylaws, effective as of July 1, 2017, to limit the service of directors, other than directors who are full-time executive employees of Gulf Power, Southern Company, or its affiliates, to no more than 12 years unless otherwise determined by the Board of Directors.

On May 1, 2017, the Board of Directors of Mississippi Power approved certain amendments to Section 2.02 of Mississippi Power's Bylaws, effective as of July 1, 2017, to limit the service of directors, other than directors who are full-time executive employees of Mississippi Power, Southern Company, or its affiliates, to no more than 12 years unless otherwise determined by the Board of Directors.

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

	~~Gulf~~Alabama Power

*	~~(d)~~		~~By-Laws of Gulf Power, as amended, effective July 1, 2017.~~

	~~Mississippi~~(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.)

*	~~(e)~~		~~By-Laws of Mississippi Power, as amended, effective July 1, 2017.~~



(4) Instruments Describing Rights of Security Holders, Including Indentures

~~Alabama~~Georgia Power

~~(b)~~(c)1	-	~~Fifty-Sixth~~ Fifty-Eighth Supplemental Indenture to Senior Note Indenture, dated as of ~~March 3,~~August 8, 2017, providing for the issuance of the Series ~~2017A 2.45% Senior Notes due March 30, 2022. (Designated in Form 8-K dated February 27, 2017, File No. 1-3164, as Exhibit 4.6.)~~

~~Georgia Power~~

~~(c)1~~	-	~~Fifty-Sixth Supplemental Indenture to Senior Note Indenture, dated as of March 3, 2017, providing for the issuance of the Series 2017A~~2017C 2.00% Senior Notes due ~~March 30,~~September 8, 2020. (Designated in Form 8-K dated ~~February 28,~~August 3, 2017, File No. 1-6468, as Exhibit ~~4.2(a).~~4.2.)

(c)2	-	~~Fifty-Seventh Supplemental Indenture to Senior~~ Subordinated Note Indenture, dated as of ~~March 3,~~September 1, 2017, ~~providing for the issuance~~between Georgia Power and Wells Fargo Bank, National Association, as Trustee, and First Supplemental Indenture thereto dated as of ~~the Series 2017B 3.25% Senior Notes due March 30, 2027.~~September 21, 2017. (Designated in Form 8-K dated ~~February 28,~~September 18, 2017, File No. 1-6468, as Exhibit ~~4.2(b)~~4.3 and in Form 8-K dated September 18, 2017, File No. 1-6468, as Exhibit 4.4.)



		~~(10) Material Contracts~~

		~~Southern Company~~

#	*	~~(a)1~~	-	~~Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan.~~

#	*	~~(a)2~~	-	~~Form of Terms for Restricted Stock Unit with Performance Measure Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan.~~

#	*	~~(a)~~(c)3	-	~~Letter Agreement among Southern Company Gas, Southern Company, and Andrew W. Evans and Performance Stock Unit Award~~ Amendment No. 3, dated July 27, 2017 to Loan Guarantee Agreement dated ~~September 29, 2016.~~

#	*	~~(a)4~~	-	~~Form of Time-Vesting Restricted Stock Unit Awards granted under~~February 20, 2014, between Georgia Power and the ~~Southern Company 2011 Omnibus Incentive Compensation Plan.~~

#		~~(a)5~~	-	Nonqualified Savings Plan as amended and restated as of January 1, 2009, First Amendment effective December 18, 2009, Second Amendment effective January 1, 2013, and Third Amendment effective January 1, 2013.DOE. (Designated in Form ~~10-K for the year ended December 31, 2008,~~8-K dated July 27, 2017, File No. ~~1-14174,~~1-6468, as Exhibit ~~10.1.av and in Form 10-K for the year ended December 31, 2013, File No. 1-14174, as Exhibits 10.1.aa, 10.1.ab, and 10.1.ac.~~4.1.)

#		~~(a)6~~	-	~~Excess Benefit Plan as amended and restated as of January 1, 2009. (Designated in Form 10-K for the year ended December 31, 2008, File No. 1-14174, as Exhibit 10.1.az.)~~

		~~Alabama Power~~(10) Material Contracts

#		~~(b)1~~	-	~~Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)1 herein.~~

#		~~(b)2~~	-	~~Form of Terms for Restricted Stock Unit with Performance Measure Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.~~

		~~Georgia Power~~

#		~~(c)1~~	-	~~Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)1 herein.~~

#		~~(c)2~~	-	~~Form of Terms for Restricted Stock Unit with Performance Measure Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.~~

	*	~~(c)3~~	-	Interim Assessment Agreement dated as of March 29, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse, WECTEC Staffing Services LLC, and WECTEC.

	*	~~(c)4~~	-	Amendment No. 1 to Interim Assessment Agreement dated as of March 29, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse, WECTEC Staffing Services LLC, and WECTEC.

		~~Gulf Power~~

#		~~(d)1~~	-	~~Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)1 herein.~~



#		~~(d)2~~	-	~~Form of Terms for Restricted Stock Unit with Performance Measure Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.~~

		Mississippi Power

#		(e)1	-	~~Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)1 herein.~~

#		~~(e)2~~	-	~~Form of Terms for Restricted Stock Unit with Performance Measure Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.~~

	*	~~(e)3~~	-	~~Amended and Restated~~ Promissory Note dated ~~February 28,~~September 15, 2017, between Mississippi Power and Southern Company in the aggregate principal amount of up to ~~$375,000,000.~~$150,000,000. (Designated in Form 8-K dated September 15, 2017, File No. 001-11229, as Exhibit 10.1.)

	*	~~(e)4~~			-	~~Second Amended and Restated Promissory Note dated February 28, 2017 between Mississippi Power and~~ Southern Company ~~in the aggregate principal amount of $301,126,146.39.~~Gas

	*	~~(e)5~~(g)1	-	~~Amended~~ Asset Purchase Agreement, dated as of October 15, 2017, by and ~~Restated Promissory Note~~between Pivotal Utility Holdings, Inc., as Seller, and South Jersey Industries, Inc., as Buyer. (Designated in Form 8-K dated ~~February 28,~~October 15, 2017, ~~between Mississippi Power and Southern Company in the aggregate principal amount of up to $275,000,000.~~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).)



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.



	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

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: ~~May 2,~~October 31, 2017

ALABAMA POWER COMPANY

SIGNATURES



		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: ~~May 2,~~October 31, 2017

GEORGIA POWER COMPANY

SIGNATURES



		GEORGIA POWER COMPANY

By		W. Paul Bowers
		Chairman, President, and Chief Executive Officer
		(Principal Executive Officer)

By		~~W. Ron Hinson~~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: ~~May 2,~~October 31, 2017

GULF POWER COMPANY

SIGNATURES



		GULF POWER COMPANY

By		S. W. Connally, Jr.
		Chairman, President and Chief Executive Officer
		(Principal Executive Officer)

By		~~Xia Liu~~Robin B. Boren
		Vice President, ~~and~~ Chief Financial Officer, and Treasurer
		(Principal Financial Officer)

By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: ~~May 2,~~October 31, 2017

MISSISSIPPI POWER COMPANY

SIGNATURES



		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: ~~May 2,~~October 31, 2017

SOUTHERN POWER COMPANY

SIGNATURES



		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: ~~May 2,~~October 31, 2017

SOUTHERN COMPANY GAS

SIGNATURES



		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: ~~May 2,~~October 31, 2017

~~242~~292



Cost Category	2010 Project Estimate^(a)		Current Cost Estimate^(b)			Actual Costs
	(in billions)
Plant Subject to Cost Cap^(c)(e)	$	2.40	$	5.75		$	5.57
Lignite Mine and Equipment	0.21		0.23			0.23
CO₂ Pipeline Facilities	0.14		0.12			0.12
AFUDC^(d)	0.17		0.83			0.80
Combined Cycle and Related Assets Placed in Service – Incremental^(e)	—		0.05			0.04
General Exceptions	0.05		0.10			0.09
Deferred Costs^(e)	—		0.22			0.22
Additional DOE Grants	—		(0.14		)	(0.14		)
Total Kemper IGCC^(f)	$	2.97	$	7.16		$	6.93



	Short-term Debt at March 31, 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	$	381	1.3	%	$	144	1.1	%	$	381



	First Quarter			2017 vs. 2016		2017 vs. normal
	Normal^(a)	2017	2016	(warmer)		(warmer)
Illinois^(b)	3,121	2,560	2,701	(5	)%	(18	)%
Georgia	1,499	925	1,334	(31	)%	(38	)%



	March 31,
	2017		2016		2017 vs. 2016
	(in thousands, except market share %)				(% change)
Gas distribution operations	4,618		4,594		0.5	%
Gas marketing services
Energy customers	661		662		(0.2	)%
Market share of energy customers in Georgia	29.3	%	29.3	%
Service contracts	1,197		1,204		(0.6	)%



Note		Page Number
A	Introduction	~~170~~207
B	Contingencies and Regulatory Matters	~~175~~213
C	Fair Value Measurements	~~196~~236
D	Stockholders' Equity	~~200~~240
E	Financing	~~202~~242
F	Retirement Benefits	~~205~~247
G	Income Taxes	~~208~~253
H	Derivatives	~~210~~255
I	Acquisitions and Dispositions	~~221~~270
J	Joint Ownership Agreements	~~224~~273
K	Segment and Related Information	~~226~~275



Regulatory Clause	Balance Sheet Line Item	March 31, 2017		December 31, 2016
		(in millions)
Rate CNP Compliance^(*)	Deferred under recovered regulatory clause revenues	$	—	$	9
Rate CNP PPA	Over recovered regulatory clause revenues	3		—
	Deferred under recovered regulatory clause revenues	—		142
Retail Energy Cost Recovery	Other regulatory liabilities, current	40		76
Natural Disaster Reserve	Other regulatory liabilities, deferred	66		69

Third Quarter 2017 vs. Third Quarter 2016

Year-to-Date 2017 vs. Year-to-Date 2016

(change in millions)

(% change)

(change in millions)

(% change)