Document

Second Quarter 2017 vs. Second Quarter 2016

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

(change in millions)

(% change)

(change in millions)

(% change)

10-Q 1 so_10qx6302017.htm 10-Q Document

Table of Contents

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 June 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

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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 June 30, 2017
The Southern Company	Par Value $5 Per Share	999,474,028
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

June 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	53
	Condensed Statements of Comprehensive Income	53
	Condensed Statements of Cash Flows	54
	Condensed Balance Sheets	55
	Management's Discussion and Analysis of Financial Condition and Results of Operations	57
	Georgia Power Company
	Condensed Statements of Income	70
	Condensed Statements of Comprehensive Income	70
	Condensed Statements of Cash Flows	71
	Condensed Balance Sheets	72
	Management's Discussion and Analysis of Financial Condition and Results of Operations	74
	Gulf Power Company
	Condensed Statements of Income	93
	Condensed Statements of Comprehensive Income	93
	Condensed Statements of Cash Flows	94
	Condensed Balance Sheets	95
	Management's Discussion and Analysis of Financial Condition and Results of Operations	97
	Mississippi Power Company
	Condensed Statements of Income	111
	Condensed Statements of Comprehensive Income	111
	Condensed Statements of Cash Flows	112
	Condensed Balance Sheets	113
	Management's Discussion and Analysis of Financial Condition and Results of Operations	115
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	141
	Condensed Consolidated Statements of Comprehensive Income	141
	Condensed Consolidated Statements of Cash Flows	142
	Condensed Consolidated Balance Sheets	143
	Management's Discussion and Analysis of Financial Condition and Results of Operations	145

INDEX TO QUARTERLY REPORT ON FORM 10-Q

June 30, 2017



		Page Number
	PART I—FINANCIAL INFORMATION (CONTINUED)
	Southern Company Gas and Subsidiary Companies
	Condensed Consolidated Statements of Income	159
	Condensed Consolidated Statements of Comprehensive Income	160
	Condensed Consolidated Statements of Cash Flows	161
	Condensed Consolidated Balance Sheets	162
	Management's Discussion and Analysis of Financial Condition and Results of Operations	164
	Notes to the Condensed Financial Statements	188
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	51
Item 4.	Controls and Procedures	51

	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	258
Item 1A.	Risk Factors	258
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	Inapplicable
Item 3.	Defaults Upon Senior Securities	Inapplicable
Item 4.	Mine Safety Disclosures	Inapplicable
Item 5.	Other Information	Inapplicable
Item 6.	Exhibits	261
	Signatures	266

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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
Baseload Act	State of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of Mississippi
CCR	Coal combustion residuals
Clean Power Plan	Final action published by the EPA in 2015 that established guidelines for states to develop plans to meet EPA-mandated CO₂ emission rates or emission reduction goals for existing electric generating units
CO₂	Carbon dioxide
COD	Commercial operation date
Contractor Settlement Agreement	The December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the Vogtle 3 and 4 Agreement
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
IGCC	Integrated coal gasification combined cycle
IIC	Intercompany interchange contract
Illinois Commission	Illinois Commerce Commission, the state regulatory agency for Nicor Gas
IRC	Internal Revenue Code of 1986, as amended

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DEFINITIONS

(continued)



Term	Meaning

IRS	Internal Revenue Service
ITC	Investment tax credit
Kemper IGCC	Mississippi Power's IGCC project in Kemper County, Mississippi
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
LIFO	Last-in, first-out
LNG	Liquefied natural gas
LOCOM	Lower of weighted average cost or current market price
LTSA	Long-term service agreement
MATS rule	Mercury and Air Toxics Standards rule
Merger	The merger, effective July 1, 2016, of a wholly-owned, direct subsidiary of Southern Company with and into Southern Company Gas, with Southern Company Gas continuing as the surviving corporation
Mirror CWIP	A regulatory liability used by Mississippi Power to record customer refunds resulting from a 2015 Mississippi PSC order
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal units
Moody's	Moody's Investors Service, Inc.
MRA	Municipal and Rural Associations
MW	Megawatt
natural gas distribution utilities	Southern Company Gas' seven natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, Elizabethtown Gas, Florida City Gas, Chattanooga Gas Company, and Elkton Gas)
NCCR	Georgia Power's Nuclear Construction Cost Recovery
New Jersey BPU	New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
Nicor Gas	Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas
NRC	U.S. Nuclear Regulatory Commission
NYMEX	New York Mercantile Exchange, Inc.
OCI	Other comprehensive income
PennEast Pipeline	PennEast Pipeline Company, LLC
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
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

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DEFINITIONS

(continued)



Term	Meaning

Rate CNP PPA	Alabama Power's Rate Certificated New Plant Power Purchase Agreement
Rate ECR	Alabama Power's Rate Energy Cost Recovery
Rate NDR	Alabama Power's Rate Natural Disaster Reserve
Rate RSE	Alabama Power's Rate Stabilization and Equalization plan
registrants	Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and Southern Company Gas
ROE	Return on equity
S&P	S&P Global Ratings, a division of S&P Global Inc.
scrubber	Flue gas desulfurization system
SCS	Southern Company Services, Inc. (the Southern Company system service company)
SEC	U.S. Securities and Exchange Commission
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 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

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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, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC);


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


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


•	investment performance of the Southern Company system's employee and retiree benefit plans and nuclear decommissioning trust funds;


•	advances in technology;


•	ongoing renewable energy partnerships and development agreements;


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


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

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)


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


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


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


•	the inherent risks involved in transporting and storing natural gas;


•	the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;


•	internal restructuring or other restructuring options that may be pursued;


•	potential business strategies, including acquisitions or dispositions of assets or businesses, 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.

Table of Contents

THE SOUTHERN COMPANY

AND SUBSIDIARY COMPANIES

Table of Contents

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Operating Revenues:
Retail electric revenues	$	3,777		$	3,748		$	7,171		$	7,124
Wholesale electric revenues	618			446			1,149			842
Other electric revenues	167			166			342			348
Natural gas revenues	684			—			2,214			—
Other revenues	184			99			326			137
Total operating revenues	5,430			4,459			11,202			8,451
Operating Expenses:
Fuel	1,092			1,023			2,088			1,934
Purchased power	211			189			390			354
Cost of natural gas	232			—			951			—
Cost of other sales	114			58			203			77
Other operations and maintenance	1,301			1,099			2,631			2,206
Depreciation and amortization	754			569			1,469			1,110
Taxes other than income taxes	308			255			638			511
Estimated loss on Kemper IGCC	3,012			81			3,120			134
Total operating expenses	7,024			3,274			11,490			6,326
Operating Income (Loss)	(1,594		)	1,185			(288		)	2,125
Other Income and (Expense):
Allowance for equity funds used during construction	58			45			115			98
Earnings (loss) from equity method investments	28			(1		)	67			(1		)
Interest expense, net of amounts capitalized	(424		)	(293		)	(840		)	(539		)
Other income (expense), net	(3		)	(28		)	(11		)	(56		)
Total other income and (expense)	(341		)	(277		)	(669		)	(498		)
Earnings (Loss) Before Income Taxes	(1,935		)	908			(957		)	1,627
Income taxes (benefit)	(587		)	261			(273		)	479
Consolidated Net Income (Loss)	(1,348		)	647			(684		)	1,148
Less:
Dividends on preferred and preference stock of subsidiaries	11			12			22			23
Net income attributable to noncontrolling interests	22			12			17			13
Consolidated Net Income (Loss) Attributable to Southern Company	$	(1,381	)	$	623		$	(723	)	$	1,112
Common Stock Data:
Earnings (loss) per share —
Basic	$	(1.38	)	$	0.67		$	(0.73	)	$	1.20
Diluted	$	(1.37	)	$	0.66		$	(0.72	)	$	1.20
Average number of shares of common stock outstanding (in millions)
Basic	998			934			996			925
Diluted	1,005			940			1,003			931
Cash dividends paid per share of common stock	$	0.5800		$	0.5600		$	1.1400		$	1.1025

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

Table of Contents

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Consolidated Net Income (Loss)	$	(1,348	)	$	647		$	(684	)	$	1,148
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $23, $(13), $17, and $(85), respectively	38			(20		)	29			(137		)
Reclassification adjustment for amounts included in net income, net of tax of $(25), $10, $(26), and $11, respectively	(41		)	16			(42		)	18
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $1, $-, $1, and $1, respectively	1			1			2			2
Total other comprehensive income (loss)	(2		)	(3		)	(11		)	(117		)
Comprehensive Income (Loss)	(1,350		)	644			(695		)	1,031
Less:
Dividends on preferred and preference stock of subsidiaries	11			12			22			23
Comprehensive income attributable to noncontrolling interests	22			12			17			13
Consolidated Comprehensive Income (Loss) Attributable to Southern Company	$	(1,383	)	$	620		$	(734	)	$	995

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)



	For the Six Months Ended June 30,
	2017			2016
	(in millions)
Operating Activities:
Consolidated net income (loss)	$	(684	)	$	1,148
Adjustments to reconcile consolidated net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	1,683			1,306
Deferred income taxes	(270		)	279
Allowance for equity funds used during construction	(115		)	(98		)
Pension, postretirement, and other employee benefits	(83		)	(56		)
Settlement of asset retirement obligations	(87		)	(66		)
Stock based compensation expense	73			69
Hedge settlements	1			(201		)
Estimated loss on Kemper IGCC	3,120			134
Income taxes receivable, non-current	(58		)	—
Other, net	(63		)	63
Changes in certain current assets and liabilities —
-Receivables	110			(197		)
-Prepayments	(61		)	(28		)
-Fossil fuel for generation	6			70
-Natural gas for sale, net of temporary LIFO liquidation	223			—
-Other current assets	(36		)	(25		)
-Accounts payable	(353		)	(71		)
-Accrued taxes	(132		)	74
-Accrued compensation	(331		)	(222		)
-Retail fuel cost over recovery	(187		)	(54		)
-Other current liabilities	(14		)	15
Net cash provided from operating activities	2,742			2,140
Investing Activities:
Business acquisitions, net of cash acquired	(1,062		)	(897		)
Property additions	(3,398		)	(3,486		)
Investment in restricted cash	(16		)	(8,608		)
Distribution of restricted cash	27			649
Nuclear decommissioning trust fund purchases	(388		)	(585		)
Nuclear decommissioning trust fund sales	383			580
Cost of removal, net of salvage	(128		)	(99		)
Change in construction payables, net	(117		)	(260		)
Investment in unconsolidated subsidiaries	(116		)	—
Payments pursuant to LTSAs	(132		)	(82		)
Other investing activities	58			113
Net cash used for investing activities	(4,889		)	(12,675		)
Financing Activities:
Increase in notes payable, net	30			471
Proceeds —
Long-term debt	2,958			12,038
Common stock	417			1,383
Short-term borrowings	1,004			—
Redemptions and repurchases —
Long-term debt	(1,478		)	(1,272		)
Preference stock	(150		)	—
Short-term borrowings	—			(475		)
Distributions to noncontrolling interests	(40		)	(11		)
Capital contributions from noncontrolling interests	73			179
Purchase of membership interests from noncontrolling interests	—			(129		)
Payment of common stock dividends	(1,134		)	(1,023		)
Other financing activities	(75		)	(133		)
Net cash provided from financing activities	1,605			11,028
Net Change in Cash and Cash Equivalents	(542		)	493
Cash and Cash Equivalents at Beginning of Period	1,975			1,404
Cash and Cash Equivalents at End of Period	$	1,433		$	1,897
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $55 and $61 capitalized for 2017 and 2016, respectively)	$	833		$	458
Income taxes, net	1			(138		)
Noncash transactions — Accrued property additions at end of period	629			549

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)



Assets	At June 30, 2017			At December 31, 2016
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,433		$	1,975
Receivables —
Customer accounts receivable	1,600			1,565
Energy marketing receivables	482			623
Unbilled revenues	593			706
Under recovered regulatory clause revenues	26			18
Income taxes receivable, current	544			544
Other accounts and notes receivable	513			377
Accumulated provision for uncollectible accounts	(52		)	(43		)
Materials and supplies	1,461			1,462
Fossil fuel for generation	624			689
Natural gas for sale	477			631
Prepaid expenses	361			364
Other regulatory assets, current	569			581
Other current assets	206			230
Total current assets	8,837			9,722
Property, Plant, and Equipment:
In service	101,021			98,416
Less: Accumulated depreciation	30,667			29,852
Plant in service, net of depreciation	70,354			68,564
Nuclear fuel, at amortized cost	892			905
Construction work in progress	7,440			8,977
Total property, plant, and equipment	78,686			78,446
Other Property and Investments:
Goodwill	6,271			6,251
Equity investments in unconsolidated subsidiaries	1,632			1,549
Other intangible assets, net of amortization of $126 and $62 at June 30, 2017 and December 31, 2016, respectively	929			970
Nuclear decommissioning trusts, at fair value	1,722			1,606
Leveraged leases	782			774
Miscellaneous property and investments	230			270
Total other property and investments	11,566			11,420
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,325			1,629
Unamortized loss on reacquired debt	215			223
Other regulatory assets, deferred	6,668			6,851
Other deferred charges and assets	1,387			1,406
Total deferred charges and other assets	9,595			10,109
Total Assets	$	108,684		$	109,697

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)



Liabilities and Stockholders' Equity	At June 30, 2017			At December 31, 2016
	(in millions)
Current Liabilities:
Securities due within one year	$	3,031		$	2,587
Notes payable	3,274			2,241
Energy marketing trade payables	534			597
Accounts payable	1,920			2,228
Customer deposits	546			558
Accrued taxes —
Accrued income taxes	125			193
Unrecognized tax benefits	400			385
Other accrued taxes	490			667
Accrued interest	508			518
Accrued compensation	584			915
Asset retirement obligations, current	300			378
Liabilities from risk management activities, net of collateral	71			107
Acquisitions payable	—			489
Other regulatory liabilities, current	169			236
Other current liabilities	799			818
Total current liabilities	12,751			12,917
Long-term Debt	43,885			42,629
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	13,529			14,092
Deferred credits related to income taxes	212			219
Accumulated deferred ITCs	2,301			2,228
Employee benefit obligations	2,156			2,299
Asset retirement obligations, deferred	4,297			4,136
Accrued environmental remediation	399			397
Other cost of removal obligations	2,706			2,748
Other regulatory liabilities, deferred	233			258
Other deferred credits and liabilities	805			880
Total deferred credits and other liabilities	26,638			27,257
Total Liabilities	83,274			82,803
Redeemable Preferred Stock of Subsidiaries	118			118
Redeemable Noncontrolling Interests	51			164
Stockholders' Equity:
Common Stockholders' Equity:
Common stock, par value $5 per share —
Authorized — 1.5 billion shares
Issued — June 30, 2017: 1.0 billion shares
— December 31, 2016: 991 million shares
Treasury — June 30, 2017: 0.9 million shares
— December 31, 2016: 0.8 million shares
Par value	4,997			4,952
Paid-in capital	10,106			9,661
Treasury, at cost	(34		)	(31		)
Retained earnings	8,494			10,356
Accumulated other comprehensive loss	(191		)	(180		)
Total Common Stockholders' Equity	23,372			24,758
Preferred and Preference Stock of Subsidiaries	462			609
Noncontrolling Interests	1,407			1,245
Total Stockholders' Equity	25,241			26,612
Total Liabilities and Stockholders' Equity	$	108,684		$	109,697

The accompanying notes as they relate to Southern Company 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

SECOND QUARTER 2017 vs. SECOND QUARTER 2016

AND

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

OVERVIEW

Southern Company is a holding company that owns all of the common stock of the traditional electric operating companies and the parent entities of Southern Power and Southern Company Gas and owns other direct and indirect subsidiaries. Discussion of the results of operations is focused on the Southern Company system's primary businesses of electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. Southern Company's other business activities include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers. Customer solutions include distributed generation systems, utility infrastructure solutions, and energy efficiency products and services. Other business activities also include investments in telecommunications, leveraged lease projects, and gas storage facilities. For additional information, see BUSINESS – "The Southern Company System – Traditional Electric Operating Companies," " – Southern Power," " – Southern Company Gas," and " – Other Businesses" in Item 1 of the Form 10-K.

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

Construction Program

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

Kemper IGCC

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

Although the ability to achieve a negotiated settlement is uncertain, Mississippi Power intends to pursue any available settlement alternatives. In addition, the Kemper Settlement Order provides that, in the event a settlement agreement is not reached, the Mississippi PSC reserves its right to take any appropriate steps, including issuing an order to show cause as to why the CPCN for the Kemper IGCC should not be revoked.

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

At June 30, 2017, approximately $3.3 billion in actual Kemper IGCC costs were not reflected in Mississippi Power's retail and wholesale rates, of which $0.5 billion was related to the combined cycle and associated facilities and $2.8 billion was related to the gasification portions 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 Settlement Order, 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 event the gasification portions of the project are ultimately canceled, additional pre-tax costs currently estimated at approximately $100 million to $200 million are expected to be incurred.

Total pre-tax charges to income for the estimated probable losses on the Kemper IGCC were $3.0 billion ($2.1 billion after tax) for the second quarter 2017 and $3.1 billion ($2.2 billion after tax) for the six months ended June 30, 2017. In the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $6.0 billion ($3.9 billion after tax) through June 30, 2017.

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

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

Nuclear Construction

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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. 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.

Georgia Power and the other Vogtle Owners are continuing to conduct comprehensive schedule and cost-to-complete assessments, as well as cancellation cost assessments, to determine the impact of the EPC Contractor's bankruptcy filing on the construction cost and schedule for Plant Vogtle Units 3 and 4. 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, and currently expects to include its recommendation in its seventeenth Vogtle Construction Monitoring (VCM) report to be filed with the Georgia PSC in late August 2017.

An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's financial statements. The ultimate outcome of these matters also is dependent on the completion of the assessments described above, 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 preliminary cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.

RESULTS OF OPERATIONS

Net Income (Loss)

N/M - Not meaningful

Consolidated net loss attributable to Southern Company was $(1.4) billion ($(1.38) per share) for the second quarter 2017 compared to net income of $623 million ($0.67 per share) for the corresponding period in 2016. The decrease was primarily due to charges of $3.0 billion and $81 million in the second quarter 2017 and 2016, respectively, related to the Kemper IGCC at Mississippi Power. Also contributing to the change were increases in renewable energy sales at Southern Power, higher retail electric revenues resulting from increases in base rates, and $49 million in net income from Southern Company Gas, which was acquired on July 1, 2016, partially offset by higher interest expense.

Consolidated net loss attributable to Southern Company was $(723) million ($(0.73) per share) for year-to-date 2017 compared to net income of $1.1 billion ($1.20 per share) for the corresponding period in 2016. The decrease was primarily due to charges of $3.1 billion and $134 million for year-to-date 2017 and 2016, respectively, related to the Kemper IGCC at Mississippi Power. Also contributing to the change was $288 million in net income from Southern Company Gas, increases in renewable energy sales at Southern Power, and higher retail electric revenues

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

resulting from increases in base rates, partially offset by higher interest expense and a decrease in retail electric revenues resulting from milder weather for year-to-date 2017 compared to the corresponding period in 2016.

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

Retail Electric Revenues

In the second quarter 2017, retail electric revenues were $3.8 billion compared to $3.7 billion for the corresponding period in 2016. For year-to-date 2017, retail revenues were $7.2 billion compared to $7.1 billion for the corresponding period in 2016.

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



	Second Quarter 2017					Year-to-Date 2017
	(in millions)			(% change)		(in millions)			(% change)
Retail electric – prior year	$	3,748				$	7,124
Estimated change resulting from –
Rates and pricing	81			2.2		200			2.8
Sales decline	(12		)	(0.3	)	(22		)	(0.3	)
Weather	(51		)	(1.4	)	(189		)	(2.6	)
Fuel and other cost recovery	11			0.3		58			0.8
Retail electric – current year	$	3,777		0.8	%	$	7,171		0.7	%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to a Rate RSE increase at Alabama Power effective January 1, 2017, the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff at Georgia Power, and an ECO Plan rate increase at Mississippi Power implemented in the third quarter 2016. Additionally, the second quarter 2017 increase was partially offset by the rate pricing effect of decreased customer usage and lower contributions from commercial and industrial customers under a rate plan for variable demand-driven pricing at Georgia Power.

See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power" and " – Georgia Power – Rate Plans" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.

Revenues attributable to changes in sales decreased in the second quarter 2017 when compared to the corresponding period in 2016. Industrial KWH sales decreased 0.8% in the second quarter 2017 primarily in the paper, primary metals, and transportation sectors, partially offset by increased sales in the chemicals sector. Despite a more stable dollar and improving global economy, the industrial sector remains constrained by economic policy uncertainty. Weather-adjusted residential KWH sales decreased 0.4% in the second quarter 2017 primarily due to decreased customer usage primarily resulting from increased efficiency improvements in residential appliances and lighting, partially offset by customer growth. Weather-adjusted commercial KWH sales were flat in the second quarter 2017 primarily due to decreased customer usage resulting from an increase in electronic commerce transactions and energy saving initiatives, offset by customer growth.

Revenues attributable to changes in sales decreased for year-to-date 2017 when compared to the corresponding period in 2016. Industrial KWH sales decreased 1.5% for year-to-date 2017 primarily in the paper, stone, clay, and

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glass, and transportation sectors. Despite a more stable dollar and improving global economy, the industrial sector remains constrained by economic policy uncertainty. Weather-adjusted commercial KWH sales decreased 0.9% for year-to-date 2017 primarily due to decreased customer usage resulting from an increase in electronic commerce transactions and energy saving initiatives, partially offset by customer growth. Weather-adjusted residential KWH sales increased 0.2% for year-to-date 2017 primarily due to customer growth, partially offset by decreased customer usage primarily resulting from efficiency improvements in residential appliances and lighting.

Fuel and other cost recovery revenues increased $11 million and $58 million in the second quarter and year-to-date 2017, respectively, when compared to the corresponding periods in 2016 primarily due to an increase in natural gas 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

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 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. 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 second quarter 2017, wholesale electric revenues were $618 million compared to $446 million for the corresponding period in 2016. This increase was primarily related to a $158 million increase in energy revenues and a $14 million increase in capacity revenues. For year-to-date 2017, wholesale electric revenues were $1.1 billion compared to $842 million for the corresponding period in 2016. This increase was primarily related to a $276 million increase in energy revenues and a $31 million increase in capacity revenues. The increases 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 non-PPA revenues from short-term sales. The increases in capacity revenues primarily resulted from PPAs related to new natural gas facilities and additional customer load requirements at Southern Power.

Natural Gas Revenues

Natural gas revenues represent sales from the natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. Following the Merger, $684 million and $2.2 billion of natural gas revenues are included in the consolidated statements of income for the second quarter and year-to-date 2017, respectively.

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

Other Revenues

N/M - Not meaningful

In the second quarter 2017, other revenues were $184 million compared to $99 million for the corresponding period in 2016. For year-to-date 2017, other revenues were $326 million compared to $137 million for the corresponding period in 2016. These increases were primarily due to increases of $60 million and $130 million for the second quarter and year-to-date 2017, respectively, from products and services at PowerSecure, which was acquired on May 9, 2016, and $32 million and $62 million for the second quarter and year-to-date 2017, respectively, of revenues from gas marketing products and services at Southern Company Gas following the Merger.

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



	Second Quarter 2017 vs. Second Quarter 2016			Year-to-Date 2017 vs. Year-to-Date 2016
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	69	6.7	$	154	8.0
Purchased power	22		11.6	36		10.2
Total fuel and purchased power expenses	$	91		$	190

In the second quarter 2017, total fuel and purchased power expenses were $1.3 billion compared to $1.2 billion for the corresponding period in 2016. The increase was primarily the result of a $154 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset by a $63 million decrease primarily due to the volume of KWHs purchased.

For year-to-date 2017, total fuel and purchased power expenses were $2.5 billion compared to $2.3 billion for the corresponding period in 2016. The increase was primarily the result of a $277 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset by an $87 million decrease primarily due to the volume of KWHs 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:



	Second Quarter 2017	Second Quarter 2016	Year-to-Date 2017	Year-to-Date 2016
Total generation (in billions of KWHs)	49	45	93	89
Total purchased power (in billions of KWHs)	3	4	7	8
Sources of generation (percent) —
Coal	31	32	30	30
Nuclear	16	16	16	17
Gas	43	48	45	47
Hydro	3	2	3	4
Other	7	2	6	2
Cost of fuel, generated (in cents per net KWH) —
Coal	2.77	3.20	2.82	3.22
Nuclear	0.80	0.82	0.80	0.82
Gas	2.94	2.24	2.93	2.20
Average cost of fuel, generated (in cents per net KWH)	2.49	2.33	2.49	2.28
Average cost of purchased power (in cents per net KWH)^(*)	7.70	5.03	6.85	5.14


(*)	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 second quarter 2017, fuel expense was $1.1 billion compared to $1.0 billion for the corresponding period in 2016. The increase was primarily due to a 31.3% increase in the average cost of natural gas per KWH generated and a 3.0% increase in the volume of KWHs generated by coal, partially offset by a 13.4% decrease in the average cost of coal per KWH generated and a 4.8% decrease in the volume of KWHs generated by natural gas.

For year-to-date 2017, fuel expense was $2.1 billion compared to $1.9 billion for the corresponding period in 2016. The increase was primarily due to a 33.2% increase in the average cost of natural gas per KWH generated and a 4.1% increase in the volume of KWHs generated by coal, partially offset by a 12.4% decrease in the average cost of coal per KWH generated and a 6.6% decrease in the volume of KWHs generated by natural gas.

Purchased Power

In the second quarter 2017, purchased power expense was $211 million compared to $189 million for the corresponding period in 2016. The increase was primarily due to a 53.1% increase in the average cost per KWH purchased, primarily as a result of higher natural gas prices, partially offset by a 28.0% decrease in the volume of KWHs purchased.

For year-to-date 2017, purchased power expense was $390 million compared to $354 million for the corresponding period in 2016. The increase was primarily due to a 33.3% increase in the average cost per KWH purchased, primarily as a result of higher natural gas prices, partially offset by a 16.8% 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

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 the Merger, $232 million and $951 million of natural gas costs were included in the consolidated statements of income for the second quarter and year-to-date 2017, respectively.

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

Cost of Other Sales

N/M - Not meaningful

In the second quarter 2017, cost of other sales was $114 million compared to $58 million for the corresponding period in 2016. For year-to-date 2017, cost of other sales was $203 million compared to $77 million for the corresponding period in 2016. These increases were primarily due to 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. See Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information.

Other Operations and Maintenance Expenses

In the second quarter 2017, other operations and maintenance expenses were $1.3 billion compared to $1.1 billion for the corresponding period in 2016. The increase was primarily due to $213 million in operations and maintenance expenses at Southern Company Gas following the Merger, a $19 million increase associated with new solar, wind, and gas facilities at Southern Power, and a $15 million increase in operations and maintenance expenses at PowerSecure, which was acquired on May 9, 2016. These increases were partially offset by a $24 million decrease in acquisition-related expenses and a $7 million decrease in scheduled outage and maintenance costs at generation facilities.

For year-to-date 2017, other operations and maintenance expenses were $2.6 billion compared to $2.2 billion for the corresponding period in 2016. The increase was primarily due to increases of $467 million and $36 million in operations and maintenance expenses from Southern Company Gas and PowerSecure, respectively, a $35 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 by a $46 million decrease in scheduled outage and maintenance costs at generation facilities, a $26 million decrease in acquisition-related expenses, a $19 million increase in gains from sales of integrated transmission system assets at Georgia Power, a $16 million decrease in customer accounts, service, and sales costs primarily associated with demand-side management costs related to the timing of new programs at Georgia Power, and a $14 million decrease in employee compensation and benefits including pension costs.

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

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Condensed Financial Statements under "Southern Company" herein for additional information related to the Merger and the acquisition of PowerSecure.

Depreciation and Amortization

In the second quarter 2017, depreciation and amortization was $754 million compared to $569 million for the corresponding period in 2016. Following the Merger, $125 million in depreciation and amortization for Southern Company Gas is included in the consolidated statements of income for the second quarter 2017. Additionally, the increase reflects $61 million related to additional plant in service at the traditional electric operating companies and Southern Power, partially offset by $8 million more of a reduction in depreciation in the second quarter 2017 compared to the corresponding period in 2016 at Gulf Power, as authorized in its 2013 rate case settlement approved by the Florida PSC.

For year-to-date 2017, depreciation and amortization was $1.5 billion compared to $1.1 billion for the corresponding period in 2016. Following the Merger, $244 million in depreciation and amortization for Southern Company Gas is included in the consolidated statements of income for year-to-date 2017. Additionally, the increase reflects $122 million related to additional plant in service at the traditional electric operating companies and Southern Power, partially offset by $28 million more of a reduction in depreciation for year-to-date 2017 compared to the corresponding period in 2016 at Gulf Power, as authorized in its 2013 rate case settlement approved by the Florida PSC.

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

Taxes Other Than Income Taxes

In the second quarter 2017, taxes other than income taxes were $308 million compared to $255 million for the corresponding period in 2016. For year-to-date 2017, taxes other than income taxes were $638 million compared to $511 million for the corresponding period in 2016. These increases were primarily related to $44 million and $114 million in the second quarter and year-to-date 2017, respectively, 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.

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Estimated Loss on Kemper IGCC

N/M - Not meaningful

Prior to the project suspension on June 28, 2017, estimated probable losses on the Kemper IGCC of $196 million and $305 million were recorded at Mississippi Power in the second quarter and year-to-date 2017, respectively, compared to $81 million and $134 million in the second quarter and year-to-date 2016, respectively. These losses reflected revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC prior to project suspension 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 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).

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 Settlement Order, 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, which includes estimated costs associated with the gasification portions of the plant and lignite mine.

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 second quarter 2017, AFUDC equity was $58 million compared to $45 million in the corresponding period in 2016. For year-to-date 2017, AFUDC equity was $115 million compared to $98 million in the corresponding period in 2016. These increases primarily resulted from a higher AFUDC rate and an increase in Kemper IGCC CWIP subject to AFUDC prior to project suspension at Mississippi Power.

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Earnings from Equity Method Investments

N/M - Not meaningful

In the second quarter and year-to-date 2017, earnings from equity method investments were $28 million and $67 million, respectively, 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.

Interest Expense, Net of Amounts Capitalized

In the second quarter 2017, interest expense, net of amounts capitalized was $424 million compared to $293 million in the corresponding period in 2016. For year-to-date 2017, interest expense, net of amounts capitalized was $840 million compared to $539 million in the corresponding period in 2016. These increases were primarily due to an increase in average outstanding long-term debt primarily related to the Merger and the funding of Southern Power's acquisitions and construction projects. In addition, following the Merger, $48 million and $94 million in interest expense of Southern Company Gas was included in the consolidated statements of income for the second quarter and year-to-date 2017, respectively.

See Note (E) 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

In the second quarter 2017, other income (expense), net was $(3) million compared to $(28) million for the corresponding period in 2016. For year-to-date 2017, other income (expense), net was $(11) million compared to $(56) million for the corresponding period in 2016. These changes were primarily due to expenses incurred in 2016 associated with bridge financing for the Merger. These changes also include increases of $99 million and $116 million in currency losses arising from a translation of euro-denominated fixed-rate notes into U.S. dollars for the second quarter and year-to-date 2017, respectively, fully offset by an equal change in gains on the foreign currency hedges that were reclassified from accumulated OCI into earnings at Southern Power.

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

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Income Taxes (Benefit)

N/M - Not meaningful

In the second quarter 2017, income tax benefit was $587 million compared to income tax expense of $261 million for the corresponding period in 2016. The decrease was primarily due to $865 million in tax benefits related to the estimated probable losses on the Kemper IGCC at Mississippi Power, partially offset by $31 million in taxes at Southern Company Gas following the Merger.

For year-to-date 2017, income tax benefit was $273 million compared to income tax expense of $479 million for the corresponding period in 2016, primarily due to $886 million in tax benefits related to the estimated probable losses on the Kemper IGCC at Mississippi Power. In addition, the change reflects $180 million in taxes at Southern Company Gas following the Merger, partially offset by a net increase in tax benefits of $16 million from renewable tax credits at Southern Power.

See Note (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.

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. Completion of cost assessments and the determination of future actions related to Plant Vogtle Units 3 and 4 construction and rate recovery and the ability to recover costs for the remainder of the Kemper County energy facility not included in current rates are also major factors. In addition, the profitability of Southern Power's competitive wholesale business and successful additional investments in renewable and other energy projects are also major factors.

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

Future earnings for the electricity and natural gas businesses will be driven primarily by customer growth. Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and higher multi-family home construction. Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the prices of electricity and natural gas, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale electric business also depends on numerous factors including regulatory matters, creditworthiness of customers, total electric generating capacity available and related costs, future acquisitions and construction of electric generating facilities, the impact of tax credits from renewable energy projects, and the successful remarketing of capacity as current contracts expire. Demand for electricity and natural gas is primarily driven by economic growth. The pace of economic growth and electricity and natural gas demand may be affected by changes

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in regional and global economic conditions, which may impact future earnings. In addition, the volatility of natural gas prices has a significant impact on the natural gas distribution utilities' customer rates, long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services and wholesale gas services businesses to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability.

As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company.

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.

Environmental Statutes and Regulations

Air Quality

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

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

On June 18, 2017, the EPA published a notice delaying attainment designations for the 2015 eight-hour ozone NAAQS by one year, setting a revised deadline of October 1, 2018. 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.

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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 June 6, 2017, the EPA proposed a rule establishing a stay of the compliance deadlines for certain effluent limitations and pretreatment standards under the rule.

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

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

Global Climate Issues

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

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

On 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

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, it remains a separate, ongoing matter.

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.

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 –

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Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery for the traditional electric operating companies.

The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.

Renewables

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

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

During the six months ended June 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.

Mississippi Power placed in service two solar projects in January 2017 and June 2017. A third solar project is expected to be placed in service in the third quarter 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 June 9, 2017, Mississippi Power submitted a CPCN to the Mississippi PSC for the approval of construction, operation, and maintenance of a 52.5-MW solar energy generating facility, which, if approved, is expected to be placed in service by January 2020.

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

Alabama Power

Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power" in Item 8 of the Form 10-K for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.

Georgia Power

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's NCCR tariff. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information regarding Georgia Power's fuel cost recovery.

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Integrated Resource Plan

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

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

Gulf Power

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Gulf Power" of Southern Company in Item 7 of the Form 10-K for additional information regarding Gulf Power's October 2016 request to the Florida PSC to increase retail base rates and Gulf Power's ownership of Plant Scherer Unit 3.

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

Southern Company Gas

Natural Gas Cost Recovery

Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flows.

Base Rate Cases

On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and a ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase within the 11-month statutory time limit, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.

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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. 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 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). Georgia Power and the other Vogtle Owners are continuing to conduct comprehensive schedule and cost-to-complete assessments, as well as cancellation cost assessments, to determine the impact of the EPC Contractor's bankruptcy filing on the construction cost and schedule for Plant Vogtle Units 3 and 4. 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, and currently expects to include its recommendation in its seventeenth VCM report to be filed with the Georgia PSC in late August 2017. On June 21, 2017, the Mississippi PSC directed Mississippi Power to pursue a settlement under which the Kemper IGCC would be operated as a natural gas plant rather than an IGCC plant and, 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 plant. 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 additional information. For additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy facilities, 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 – 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.

Integrated Coal Gasification Combined Cycle

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

In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation between Mississippi Power and the Mississippi Public Utilities Staff, authorizing rates that provide for the recovery of approximately $126 million annually related to the combined cycle and associated common facilities portion of Kemper IGCC assets previously placed in service. As required by the In-Service Asset Rate Order, on June 5, 2017,

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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.

The remainder of the plant includes the gasifiers and the gas clean-up facilities. 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. Most recently, 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 increased significantly since certification.

On June 21, 2017, the Mississippi PSC stated its intent to issue the Kemper Settlement Order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility. The Kemper Settlement Order provides that any related settlement agreement be filed within 45 days from the effective date of the Kemper Settlement Order. If a settlement agreement is filed, a hearing will be set 45 days from the date of the settlement's filing, and the appropriate scheduling order will be established.

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

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Litigation

On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice to appeal to the Mississippi Supreme Court.

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

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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 granted on May 4, 2017. On June 28, 2017, Treetop and other related parties filed a claim for arbitration requesting $500 million in damages.

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

Nuclear Construction

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

Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy

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

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

The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement (i) 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, with these amounts paid to the EPC Contractor, except that amounts accrued for Fluor Corporation (Fluor) were paid directly to Fluor; (ii) the EPC Contractor provided 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, made payments of $5.4 million per week for these services; (iii) Georgia Power had the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who had accounts past due with the EPC Contractor; (iv) the EPC Contractor used commercially reasonable efforts to provide information reasonably requested by Georgia Power as was necessary to continue construction and investigation of the

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completion status of Plant Vogtle Units 3 and 4; (v) the EPC Contractor rejected or accepted the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) Georgia Power did not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserved all rights and remedies under the Vogtle 3 and 4 Agreement and all related security and collateral under applicable law.

The Interim Assessment Agreement, as amended, expired on July 27, 2017. Georgia Power's aggregate liability for the Vogtle Owners under the Interim Assessment Agreement totaled approximately $650 million, of which $552 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $297 million.

Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor, 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 July 31, 2017, of the Vogtle Owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $400 million, of which $354 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $183 million.

On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered 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, 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 June 23, 2017, Toshiba released a revised outlook for fiscal year 2016, which reflected a negative shareholders' equity balance of approximately $5 billion as of March 31, 2017, and announced that its independent audit process was continuing. Toshiba has also announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Vogtle Owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's financial statements.

Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Services Agreement, which was amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Vogtle Owners certain project-related contracts, (iii) join the Vogtle Owners as counterparties to certain assumed project-related contracts, and (iv) reject the Vogtle 3 and 4 Agreement.

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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.

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

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. As of June 30, 2017, Georgia Power had recovered approximately $1.4 billion of financing costs.

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.

Under the terms of the Vogtle Cost Settlement Agreement, 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 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.

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

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Revised Cost and Schedule



Preliminary in-service dates
Unit 3	February 2021			–	March 2022
Unit 4	February 2022			–	March 2023
	(in billions)
Preliminary estimated cost to complete	$	3.9		–	$	4.6
CWIP as of June 30, 2017	4.5				4.5
Guarantee Obligations	(1.7		)		(1.7		)
Estimated capital costs	$	6.7		–	$	7.4
Vogtle Cost Settlement Agreement Revised Forecast	(5.7		)		(5.7		)
Estimated net additional capital costs	$	1.0		–	$	1.7

Georgia Power's estimates for cost to complete and schedule are based on preliminary analysis and remain subject to further refinement of labor productivity and consumable and commodity quantities and costs.

Georgia Power's estimated financing costs during the construction period total approximately $3.1 billion to $3.5 billion, of which approximately $1.4 billion had been incurred through June 30, 2017.

Georgia Power's preliminary cancellation cost estimate results indicate that its proportionate share of the estimated cancellation costs is approximately $400 million. As a result, as of June 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:



	Preliminary Cancellation Cost Estimate
	(in billions)
CWIP as of June 30, 2017	$	4.5
Financing costs collected, net of tax	1.4
Cancellation costs^(*)	0.4
Total	$	6.3


(*)	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, and currently expects to include its recommendation in its seventeenth VCM report to be filed with the Georgia PSC in late August 2017.

The ultimate outcome of these matters is dependent on the completion of the assessments described above, as well as the related regulatory treatment, and cannot be determined at this time.

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Other Matters

As of June 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 and a multi-advance credit facility among Georgia Power, the DOE, and the FFB. 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.

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

There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise if 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 if 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.

If 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.

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

Approximately $1.2 billion of positive cash flows is expected to result from bonus depreciation for the 2017 tax year, but may not all be realized in 2017 due to net operating loss projections for the 2017 tax year. Approximately $370 million of the 2017 benefit is dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2017. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount previously estimated as bonus depreciation would be claimed as a deduction under IRC Section 165. As of June 30, 2017, $82 million has been received through quarterly income tax refunds for bonus depreciation related to the Kemper IGCC, which may be subject to repayment. 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 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

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2008 through 2013 to also include such deductions. In December 2016, Southern Company and the IRS reached a proposed settlement, subject to approval of the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, Southern Company had unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million as of June 30, 2017. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount not allowed under IRC Section 174 would be claimed as a deduction under IRC Section 165, and would result in a reversal of the related unrecognized tax benefits, excluding 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. This matter is expected to be resolved in the next 12 months; however, the ultimate outcome of this matter cannot be determined at this time.

Other Matters

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

The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries 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.

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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its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper IGCC. The 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. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes.

On June 1, 2017, Judy Mesirov 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 current and former directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper IGCC. The 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. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages, disgorgement of profits, and equitable relief and, on her own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes.

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

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Company prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, Goodwill and Other Intangible Assets, Derivatives and Hedging Activities, and Contingent Obligations.

Kemper IGCC Rate Recovery

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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 for the June 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 the aggregate, since the Kemper IGCC project started, Mississippi Power has incurred charges of $5.96 billion ($3.94 billion after tax) through June 30, 2017. Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $3.0 billion ($2.1 billion after tax) and $81 million ($50 million after tax) in the second quarter 2017 and the second quarter 2016, respectively, and total pre-tax charges of $3.1 billion ($2.2 billion after tax) and $134 million ($83 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

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, 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.

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. 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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FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at June 30, 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 $2.7 billion for the first six months of 2017, an increase of $0.6 billion from the corresponding period in 2016. The increase in net cash provided from operating activities was primarily due to $1.2 billion of 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 and an increase in under-recovered fuel costs. Net cash used for investing activities totaled $4.9 billion for the first six 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 payments for renewable acquisitions. Net cash provided from financing activities totaled $1.6 billion for the first six months of 2017 primarily due to 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 six months of 2017 include an increase of $1.8 billion in property, plant, and equipment in service, net of depreciation 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; a decrease of $1.5 billion in CWIP primarily related to the estimated probable losses on the Kemper IGCC; a decrease of $0.5 billion in cash and cash equivalents primarily related to acquisition payments at Southern Power; a decrease of $1.4 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; an increase of $1.3 billion in long-term debt (excluding amounts due within a year) to fund the Southern Company system's continuous construction programs and for general corporate purposes; and an increase of $1.0 billion in notes payable primarily due to issuances of short-term bank debt for general corporate purposes.

At the end of the second quarter 2017, the market price of Southern Company's common stock was $47.88 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $23.38 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 second quarter 2017 was $0.58 per share compared to $0.56 per share in the second 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 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 $3.0 billion will be required through June 30, 2018 to fund maturities of long-term debt. See "Sources of Capital" 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

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 preliminary 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. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information.

In addition, 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 Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Eligible Project Costs incurred through June 30, 2017 would allow for borrowings of up to $3.1 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.6 billion; however, on July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) to clarify the operation of the Loan Guarantee Agreement pending Georgia Power's completion of its comprehensive schedule, cost-to-complete, and cancellation cost assessments (Cost Assessments) for Plant Vogtle Units 3 and 4. Under the terms of the LGA Amendment, Georgia Power will not request any advances under the Loan Guarantee Agreement unless and until such time as Georgia Power has completed the Cost Assessments and made a determination to continue construction of Plant Vogtle Units 3 and 4 and satisfied certain other conditions related to continuing construction. 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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 June 30, 2017, Southern Company's current liabilities exceeded current assets by $3.9 billion due to notes payable of $3.3 billion (comprised of approximately $0.9 billion at the parent company, $1.2 billion at Georgia Power, $0.1 billion at Gulf Power, $0.4 billion at Southern Power, and $0.6 billion at Southern Company Gas) and long-term debt that is due within one year of $3.0 billion (comprised of approximately $0.4 billion at the parent company, $0.4 billion at Alabama Power, $0.3 billion at Georgia Power, $1.0 billion at Mississippi Power, and $0.9 billion at Southern Power). 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 June 30, 2017, Southern Company and its subsidiaries had approximately $1.4 billion of cash and cash equivalents. Committed credit arrangements with banks at June 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	3		532		—		—		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	113		—		—		—		—		113		100		—		13		13		100
Southern Power Company	—		—		—		—		750		750		675		—		—		—		—
Southern Company Gas^(b)	—		—		—		—		1,900		1,900		1,849		—		—		—		—
Other	10		30		—		—		—		40		40		20		—		20		20
Southern Company Consolidated	$	156	$	757	$	25	$	30	$	7,200	$	8,168	$	8,011	$	65	$	13	$	33	$	195


(a)	Represents the Southern Company parent entity.


(b)	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.

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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 June 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 June 30, 2017 was approximately $1.6 billion. 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 June 30, 2017, the traditional electric operating companies had approximately $626 million of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.

Southern Company, the traditional electric operating companies (other than Mississippi Power), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Short-term borrowings are included in notes payable in the balance sheets.

Details of short-term borrowings were as follows:



	Short-term Debt at June 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	$	2,257	1.5	%	$	2,519	1.3	%	$	2,946
Short-term bank debt	1,017		2.0	%	321		2.0	%	1,017
Total	$	3,274	1.7	%	$	2,840	1.4	%


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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

transmission, interest rate management, and foreign currency risk management, and, at June 30, 2017, included contracts related to the construction of new generation at Plant Vogtle Units 3 and 4.

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



Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	39
At BBB- and/or Baa3	$	642
At BB+ and/or Ba1^(*)	$	2,555


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

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

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

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

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

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

On June 22, 2017, Moody's placed the ratings of Mississippi Power on review for downgrade.

Financing Activities

During the first six months of 2017, Southern Company issued approximately 7.8 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $352 million.

In addition, during the second quarter 2017, Southern Company issued approximately 1.3 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 $65 million, net of $553,000 in fees and commissions.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six 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	$	—	$	—	$	500		$	400
Alabama Power	550		200		—		—			—
Georgia Power	850		450		27		—			3
Gulf Power	300		85		—		6			—
Mississippi Power	—		—		—		40			893
Southern Power	—		—		—		3			3
Southern Company Gas^(c)	450		—		—		—			—
Other	—		—		—		—			8
Elimination^(d)	—		—		—		(40		)	(591		)
Southern Company Consolidated	$	2,450	$	735	$	27	$	509		$	716


(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.


(d)	Intercompany loans from Southern Company to Mississippi Power 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. The proceeds were used to repay short-term indebtedness and for other general corporate purposes.

Also in June 2017, Southern Company issued $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.

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.

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 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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

respectively, and 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 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.

Subsequent to June 30, 2017, Nicor Gas agreed to issue $400 million aggregate principal amount of First Mortgage Bonds in a private placement, $200 million of which is expected to be issued in each of August 2017 and 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.

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PART I

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

During the six months ended June 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 second 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.

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ALABAMA POWER COMPANY

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ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,333		$	1,316		$	2,560		$	2,510
Wholesale revenues, non-affiliates	68			67			133			130
Wholesale revenues, affiliates	32			9			65			31
Other revenues	51			52			108			105
Total operating revenues	1,484			1,444			2,866			2,776
Operating Expenses:
Fuel	303			295			601			564
Purchased power, non-affiliates	40			40			75			76
Purchased power, affiliates	34			55			62			88
Other operations and maintenance	375			355			743			747
Depreciation and amortization	183			175			364			347
Taxes other than income taxes	95			94			191			191
Total operating expenses	1,030			1,014			2,036			2,013
Operating Income	454			430			830			763
Other Income and (Expense):
Allowance for equity funds used during construction	8			6			16			16
Interest expense, net of amounts capitalized	(77		)	(74		)	(153		)	(147		)
Other income (expense), net	1			(4		)	(4		)	(11		)
Total other income and (expense)	(68		)	(72		)	(141		)	(142		)
Earnings Before Income Taxes	386			358			689			621
Income taxes	151			140			277			242
Net Income	235			218			412			379
Dividends on Preferred and Preference Stock	5			5			9			9
Net Income After Dividends on Preferred and Preference Stock	$	230		$	213		$	403		$	370

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)



	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2017		2016		2017		2016
	(in millions)				(in millions)
Net Income	$	235	$	218	$	412	$	379
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, and $1, respectively	1		1		2		2
Total other comprehensive income (loss)	1		1		2		—
Comprehensive Income	$	236	$	219	$	414	$	379

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

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)



	For the Six Months Ended June 30,
	2017			2016
	(in millions)
Operating Activities:
Net income	$	412		$	379
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	442			419
Deferred income taxes	192			175
Pension, postretirement, and other employee benefits	(24		)	(23		)
Other, net	4			(33		)
Changes in certain current assets and liabilities —
-Receivables	(58		)	64
-Fossil fuel stock	13			(32		)
-Other current assets	(75		)	(67		)
-Accounts payable	(154		)	(75		)
-Accrued taxes	52			102
-Accrued compensation	(74		)	(50		)
-Retail fuel cost over recovery	(65		)	(60		)
-Other current liabilities	7			8
Net cash provided from operating activities	672			807
Investing Activities:
Property additions	(738		)	(645		)
Nuclear decommissioning trust fund purchases	(117		)	(200		)
Nuclear decommissioning trust fund sales	117			200
Cost of removal, net of salvage	(54		)	(51		)
Change in construction payables	48			(27		)
Other investing activities	(15		)	(18		)
Net cash used for investing activities	(759		)	(741		)
Financing Activities:
Proceeds —
Senior notes	550			400
Capital contributions from parent company	327			237
Other long-term debt	—			45
Redemptions — Senior notes	(200		)	(200		)
Payment of common stock dividends	(357		)	(382		)
Other financing activities	(14		)	(17		)
Net cash provided from financing activities	306			83
Net Change in Cash and Cash Equivalents	219			149
Cash and Cash Equivalents at Beginning of Period	420			194
Cash and Cash Equivalents at End of Period	$	639		$	343
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $6 and $7 capitalized for 2017 and 2016, respectively)	$	140		$	131
Income taxes, net	88			(122		)
Noncash transactions — Accrued property additions at end of period	132			94

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

CONDENSED BALANCE SHEETS (UNAUDITED)



Assets	At June 30, 2017			At December 31, 2016
	(in millions)
Current Assets:
Cash and cash equivalents	$	639		$	420
Receivables —
Customer accounts receivable	357			348
Unbilled revenues	161			146
Other accounts and notes receivable	36			27
Affiliated	33			40
Accumulated provision for uncollectible accounts	(9		)	(10		)
Fossil fuel stock	191			205
Materials and supplies	443			435
Prepaid expenses	86			34
Other regulatory assets, current	135			149
Other current assets	7			11
Total current assets	2,079			1,805
Property, Plant, and Equipment:
In service	26,466			26,031
Less: Accumulated provision for depreciation	9,354			9,112
Plant in service, net of depreciation	17,112			16,919
Nuclear fuel, at amortized cost	333			336
Construction work in progress	668			491
Total property, plant, and equipment	18,113			17,746
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	67			66
Nuclear decommissioning trusts, at fair value	848			792
Miscellaneous property and investments	119			112
Total other property and investments	1,034			970
Deferred Charges and Other Assets:
Deferred charges related to income taxes	526			525
Deferred under recovered regulatory clause revenues	6			150
Other regulatory assets, deferred	1,209			1,157
Other deferred charges and assets	166			163
Total deferred charges and other assets	1,907			1,995
Total Assets	$	23,133		$	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

CONDENSED BALANCE SHEETS (UNAUDITED)



Liabilities and Stockholder's Equity	At June 30, 2017			At December 31, 2016
	(in millions)
Current Liabilities:
Securities due within one year	$	361		$	561
Accounts payable —
Affiliated	242			297
Other	317			433
Customer deposits	91			88
Accrued taxes —
Accrued income taxes	39			45
Other accrued taxes	97			42
Accrued interest	81			78
Accrued compensation	125			193
Other regulatory liabilities, current	15			85
Other current liabilities	63			76
Total current liabilities	1,431			1,898
Long-term Debt	7,082			6,535
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,842			4,654
Deferred credits related to income taxes	64			65
Accumulated deferred ITCs	113			110
Employee benefit obligations	269			300
Asset retirement obligations	1,543			1,503
Other cost of removal obligations	648			684
Other regulatory liabilities, deferred	84			100
Other deferred credits and liabilities	69			63
Total deferred credits and other liabilities	7,632			7,479
Total Liabilities	16,145			15,912
Redeemable Preferred Stock	85			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	2,950			2,613
Retained earnings	2,564			2,518
Accumulated other comprehensive loss	(29		)	(30		)
Total common stockholder's equity	6,707			6,323
Total Liabilities and Stockholder's Equity	$	23,133		$	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

SECOND QUARTER 2017 vs. SECOND 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

Alabama Power's net income after dividends on preferred and preference stock for the second quarter 2017 was $230 million compared to $213 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 an increase in other income (expense), net. These increases were partially offset by an increase in operations and maintenance expenses and a decrease in retail revenues associated with milder weather and lower customer usage in the second quarter 2017 compared to the corresponding period in 2016.

Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2017 was $403 million compared to $370 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 for year-to-date 2017 compared to the corresponding period in 2016.

Retail Revenues

In the second quarter 2017, retail revenues were $1.33 billion compared to $1.32 billion for the corresponding period in 2016. For year-to-date 2017, retail revenues were $2.56 billion compared to $2.51 billion for the corresponding period in 2016.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:



	Second Quarter 2017					Year-to-Date 2017
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	1,316				$	2,510
Estimated change resulting from –
Rates and pricing	75			5.7		154			6.2
Sales decline	(11		)	(0.8	)	(12		)	(0.5	)
Weather	(11		)	(0.8	)	(66		)	(2.6	)
Fuel and other cost recovery	(36		)	(2.8	)	(26		)	(1.1	)
Retail – current year	$	1,333		1.3	%	$	2,560		2.0	%

Revenues associated with changes in rates and pricing increased in the second 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 second quarter and year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjusted residential KWH sales decreased 1.1% and 0.2% for the second quarter and year-to-date 2017, respectively, primarily due to lower customer usage resulting from an increase in efficiency improvements in residential appliances and lighting, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 0.4% and 0.8% for the second quarter and year-to-date 2017, respectively, primarily due to lower customer usage. Industrial KWH sales increased 1.0% for the second quarter 2017 when compared to the corresponding period in 2016 as a result of an increase in demand resulting from changes in production levels primarily in the chemicals and mining sectors, partially offset by a decrease in demand from the paper, primary metals, pipelines, and lumber sectors. Industrial KWH sales remained flat year-to-date 2017 when compared to the corresponding period in 2016 as a result of an increase in demand resulting from changes in production levels primarily in the chemicals and mining sectors, offset by a decrease in demand from the pipelines, lumber, and stone, clay, and glass sectors.

Revenues resulting from changes in weather decreased in the second 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 second quarter 2017, the resulting decreases were 1.5% and 0.7% for residential and commercial sales revenues, respectively. For year-to-date 2017, the resulting decreases were 5.2% and 1.4% for residential and commercial sales revenues, respectively.

Fuel and other cost recovery revenues decreased in the second quarter 2017 and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to an increase in wholesale revenues to affiliates, which offsets retail fuel cost recovery. 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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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 second quarter 2017, wholesale revenues from sales to affiliates were $32 million compared to $9 million for the corresponding period in 2016. The increase was primarily due to a 175.0% increase in KWH sales as a result of lower cost Alabama Power-owned generation available to the Southern Company system and a 29.3% increase in the price of energy due to an increase in natural gas prices. For year-to-date 2017, wholesale revenues from sales to affiliates were $65 million compared to $31 million for the corresponding period in 2016. The increase was primarily due to an 83.5% increase in KWH sales as a result of supporting Southern Company system transmission reliability and a 15.5% increase in the price of energy due to an increase in natural gas prices.

Fuel and Purchased Power Expenses



	Second Quarter 2017 vs. Second Quarter 2016				Year-to-Date 2017 vs. Year-to-Date 2016
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	8		2.7	$	37		6.6
Purchased power – non-affiliates	—			—	(1		)	(1.3	)
Purchased power – affiliates	(21		)	(38.2)	(26		)	(29.5	)
Total fuel and purchased power expenses	$	(13	)		$	10

In the second quarter 2017, fuel and purchased power expenses were $377 million compared to $390 million for the corresponding period in 2016. The decrease was primarily due to a $55 million decrease in the volume of KWHs purchased. This decrease was partially offset by a $24 million net increase related to the average cost of purchased power and fuel and an $18 million increase related to the volume of KWHs generated.

For year-to-date 2017, fuel and purchased power expenses were $738 million compared to $728 million for the corresponding period in 2016. The increase was primarily due to a $58 million increase in the volume of KWHs generated and a $31 million net increase related to the average cost of purchased power and fuel. These increases were partially offset by a $79 million decrease in the volume of KWHs purchased.

Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate ECR" in Item 8 of the Form 10-K for additional information.

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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:



	Second Quarter 2017	Second Quarter 2016	Year-to-Date 2017	Year-to-Date 2016
Total generation (in billions of KWHs)	15	13	30	28
Total purchased power (in billions of KWHs)	1	3	2	4
Sources of generation (percent) —
Coal	47	53	48	46
Nuclear	25	23	26	25
Gas	20	20	20	19
Hydro	8	4	6	10
Cost of fuel, generated (in cents per net KWH) —
Coal	2.63	2.84	2.61	2.85
Nuclear	0.76	0.79	0.75	0.78
Gas	2.75	2.52	2.76	2.49
Average cost of fuel, generated (in cents per net KWH)^(a)	2.14	2.28	2.13	2.20
Average cost of purchased power (in cents per net KWH)^(b)	7.11	3.94	6.92	4.37


(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

For year-to-date 2017, fuel expense was $601 million compared to $564 million for the corresponding period in 2016. The increase was primarily due to increases of 11.0% and 8.4% in the volume of KWHs generated by coal and natural gas, respectively, a 10.8% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and a 28.1% decrease in the volume of KWHs generated by hydro facilities. The increase was partially offset by an 8.4% decrease in the average cost of coal per KWH generated.

Purchased Power – Affiliates

In the second quarter 2017, purchased power expense from affiliates was $34 million compared to $55 million for the corresponding period in 2016. The decrease was primarily related to a 61.1% decrease in the amount of energy purchased as a result of lower cost Alabama Power-owned generation, partially offset by a 60.3% increase in the average cost of purchased power per KWH as a result of higher natural gas prices.

For year-to-date 2017, purchased power expense from affiliates was $62 million compared to $88 million for the corresponding period in 2016. The decrease was primarily related to a 56.1% decrease in the amount of energy purchased due to an increase in generation as a result of supporting Southern Company system transmission reliability, partially offset by a 60.0% increase in the average cost of purchased power per KWH as a result of higher natural gas prices.

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

In the second quarter 2017, other operations and maintenance expenses were $375 million compared to $355 million for the corresponding period in 2016. The increase was primarily due to increases of $13 million in vegetation management costs, $7 million in nuclear generation plant improvement costs, and $3 million in employee benefit costs. The increase was partially offset by a $4 million decrease in scheduled other power generation outage costs.

Depreciation and Amortization

In the second quarter 2017, depreciation and amortization was $183 million compared to $175 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $364 million compared to $347 million for the corresponding period in 2016. These increases were primarily due to additional plant in service related to distribution, steam generation, and transmission assets. In addition, there was an increase in depreciation rates, effective January 1, 2017, associated with compliance-related steam projects, asset retirement obligation recovery, and other generation assets, partially offset by a decrease in distribution-related 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.

Other Income (Expense), Net

In the second quarter 2017, other income (expense), net was $1 million compared to $(4) million for the corresponding period in 2016. For year-to-date 2017, other income (expense), net was $(4) million compared to $(11) million for the corresponding period in 2016. The changes were primarily due to decreases in donations and increases in sales of non-utility property and unregulated lighting services in 2017.

Income Taxes

In the second quarter 2017, income taxes were $151 million compared to $140 million for the corresponding period in 2016. The increase was primarily due to higher pre-tax earnings.

For year-to-date 2017, income taxes were $277 million compared to $242 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.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 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 pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings. Current proposals related to potential federal tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Alabama Power's financial statements. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Environmental compliance costs are recovered through Rate CNP Compliance. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Statutes and Regulations

Water Quality

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Global Climate Issues

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

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

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

FERC Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the traditional electric operating companies' and Southern Power's market power proceeding and amendment to their market-rate tariff.

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

Retail Regulatory Matters

Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Notes 1 and 3 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.

Other Matters

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

The ultimate outcome of such pending or potential litigation against Alabama Power 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

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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-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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at June 30, 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 $672 million for the first six months of 2017, a decrease of $135 million as compared to the first six 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 $759 million for the first six months of 2017 primarily due to gross property additions related to distribution, environmental, transmission, and steam generation. Net cash provided from financing activities totaled $306 million for the first six months of 2017 primarily due to an issuance of long-term debt 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 six months of 2017 include increases of $547 million in long-term debt, primarily due to the issuance of additional senior notes, $367 million in property, plant, and equipment, primarily due to additions to distribution, steam generation, and transmission, $337 million in additional paid-in capital due to capital contributions from Southern Company, and $219 million in cash and cash equivalents, as well as a decrease of $200 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. Approximately $361 million will be required through June 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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in the expected environmental compliance program; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

Alabama Power plans to obtain the funds to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, term loans, external security issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.

Alabama Power's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.

At June 30, 2017, Alabama Power had approximately $639 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2017 were as follows:



Expires										Expires Within One Year
2017		2018		2022		Total		Unused		Term Out		No Term Out
(in millions)
$	3	$	532	$	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.

As reflected in the table above, in May 2017, Alabama Power amended its $800 million multi-year credit arrangement, which, among other things, extended the maturity date from 2020 to 2022.

Most of these bank credit arrangements, as well as Alabama Power's term loan arrangements, contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Alabama Power defaulted on indebtedness, the payment of which was then accelerated. At June 30, 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 million as of June 30, 2017. At June 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

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.

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	$	28	1.1	%	$	200


(*)	Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2017. No short-term debt was outstanding at June 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 June 30, 2017, Alabama Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

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

The maximum potential collateral requirements under these contracts at June 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	$	326

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.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

Subsequent to June 30, 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).

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.

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GEORGIA POWER COMPANY

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GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,904		$	1,907		$	3,593		$	3,624
Wholesale revenues, non-affiliates	40			40			79			82
Wholesale revenues, affiliates	9			10			17			15
Other revenues	95			94			191			202
Total operating revenues	2,048			2,051			3,880			3,923
Operating Expenses:
Fuel	445			439			815			815
Purchased power, non-affiliates	103			92			191			175
Purchased power, affiliates	138			111			310			250
Other operations and maintenance	399			439			781			896
Depreciation and amortization	223			214			444			425
Taxes other than income taxes	101			100			199			197
Total operating expenses	1,409			1,395			2,740			2,758
Operating Income	639			656			1,140			1,165
Other Income and (Expense):
Interest expense, net of amounts capitalized	(104		)	(99		)	(205		)	(193		)
Other income (expense), net	16			8			36			26
Total other income and (expense)	(88		)	(91		)	(169		)	(167		)
Earnings Before Income Taxes	551			565			971			998
Income taxes	199			211			355			371
Net Income	352			354			616			627
Dividends on Preferred and Preference Stock	5			5			9			9
Net Income After Dividends on Preferred and Preference Stock	$	347		$	349		$	607		$	618

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)



	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2017		2016		2017		2016
	(in millions)				(in millions)
Net Income	$	352	$	354	$	616	$	627
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		1
Total other comprehensive income (loss)	1		1		2		1
Comprehensive Income	$	353	$	355	$	618	$	628

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

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GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)



	For the Six Months Ended June 30,
	2017			2016
	(in millions)
Operating Activities:
Net income	$	616		$	627
Adjustments to reconcile net income to net cash provided from operating activities --
Depreciation and amortization, total	543			530
Deferred income taxes	159			157
Allowance for equity funds used during construction	(25		)	(24		)
Deferred expenses	41			39
Pension, postretirement, and other employee benefits	(45		)	(28		)
Settlement of asset retirement obligations	(62		)	(52		)
Other, net	(39		)	36
Changes in certain current assets and liabilities —
-Receivables	(150		)	(25		)
-Fossil fuel stock	(32		)	61
-Other current assets	(22		)	10
-Accounts payable	(153		)	6
-Accrued taxes	(194		)	(137		)
-Accrued compensation	(65		)	(44		)
-Retail fuel cost over recovery	(84		)	1
-Other current liabilities	(6		)	16
Net cash provided from operating activities	482			1,173
Investing Activities:
Property additions	(1,284		)	(1,058		)
Nuclear decommissioning trust fund purchases	(271		)	(386		)
Nuclear decommissioning trust fund sales	266			380
Cost of removal, net of salvage	(32		)	(34		)
Change in construction payables, net of joint owner portion	1			(75		)
Payments pursuant to LTSAs	(56		)	(14		)
Sale of property	63			—
Other investing activities	(12		)	17
Net cash used for investing activities	(1,325		)	(1,170		)
Financing Activities:
Increase in notes payable, net	37			39
Proceeds —
Capital contributions from parent company	380			239
Senior notes	850			650
FFB loan	—			300
Short-term borrowings	800			—
Redemptions and repurchases —
Pollution control revenue bonds	(27		)	(4		)
Senior notes	(450		)	(500		)
Payment of common stock dividends	(640		)	(653		)
Other financing activities	(19		)	(20		)
Net cash provided from financing activities	931			51
Net Change in Cash and Cash Equivalents	88			54
Cash and Cash Equivalents at Beginning of Period	3			67
Cash and Cash Equivalents at End of Period	$	91		$	121
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $11 and $10 capitalized for 2017 and 2016, respectively)	$	186		$	174
Income taxes, net	213			78
Noncash transactions — Accrued property additions at end of period	348			288

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

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GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)



Assets	At June 30, 2017			At December 31, 2016
	(in millions)
Current Assets:
Cash and cash equivalents	$	91		$	3
Receivables —
Customer accounts receivable	565			523
Unbilled revenues	251			224
Joint owner accounts receivable	199			57
Other accounts and notes receivable	62			81
Affiliated	22			18
Accumulated provision for uncollectible accounts	(3		)	(3		)
Fossil fuel stock	330			298
Materials and supplies	477			479
Prepaid expenses	55			105
Other regulatory assets, current	193			193
Other current assets	22			38
Total current assets	2,264			2,016
Property, Plant, and Equipment:
In service	34,410			33,841
Less: Accumulated provision for depreciation	11,502			11,317
Plant in service, net of depreciation	22,908			22,524
Nuclear fuel, at amortized cost	559			569
Construction work in progress	5,422			4,939
Total property, plant, and equipment	28,889			28,032
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	56			60
Nuclear decommissioning trusts, at fair value	874			814
Miscellaneous property and investments	51			46
Total other property and investments	981			920
Deferred Charges and Other Assets:
Deferred charges related to income taxes	675			676
Other regulatory assets, deferred	2,790			2,774
Other deferred charges and assets	589			417
Total deferred charges and other assets	4,054			3,867
Total Assets	$	36,188		$	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

CONDENSED BALANCE SHEETS (UNAUDITED)



Liabilities and Stockholder's Equity	At June 30, 2017			At December 31, 2016
	(in millions)
Current Liabilities:
Securities due within one year	$	261		$	460
Notes payable	1,228			391
Accounts payable —
Affiliated	367			438
Other	657			589
Customer deposits	269			265
Accrued taxes	212			407
Accrued interest	115			106
Accrued compensation	141			224
Asset retirement obligations, current	251			299
Other current liabilities	185			297
Total current liabilities	3,686			3,476
Long-term Debt	10,793			10,225
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	6,163			6,000
Deferred credits related to income taxes	118			121
Accumulated deferred ITCs	251			256
Employee benefit obligations	652			703
Asset retirement obligations, deferred	2,340			2,233
Other deferred credits and liabilities	206			199
Total deferred credits and other liabilities	9,730			9,512
Total Liabilities	24,209			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	7,274			6,885
Retained earnings	4,052			4,086
Accumulated other comprehensive loss	(11		)	(13		)
Total common stockholder's equity	11,713			11,356
Total Liabilities and Stockholder's Equity	$	36,188		$	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

SECOND QUARTER 2017 vs. SECOND 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.

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. 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.

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 also is dependent on the completion of the assessments described above, 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, including Georgia Power's preliminary cost-to-complete and cancellation cost assessments for Plant Vogtle Units 3 and 4.

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

RESULTS OF OPERATIONS

Net Income

Georgia Power's net income after dividends on preferred and preference stock for the second quarter 2017 was $347 million compared to $349 million for the corresponding period in 2016. For year-to-date 2017, net income after dividends on preferred and preference stock was $607 million compared to $618 million for the corresponding period in 2016. The decreases were primarily due to milder weather as compared to the corresponding periods in 2016, partially offset by lower non-fuel operations and maintenance expenses.

Retail Revenues

In the second quarter 2017, retail revenues were $1.90 billion compared to $1.91 billion for the corresponding period in 2016. For year-to-date 2017, retail revenues were $3.59 billion compared to $3.62 billion for the corresponding period in 2016.

Details of the changes in retail revenues were as follows:



	Second Quarter 2017					Year-to-Date 2017
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	1,907				$	3,624
Estimated change resulting from –
Rates and pricing	(7		)	(0.4	)	19			0.5
Sales growth (decline)	1			0.1		(11		)	(0.3	)
Weather	(38		)	(2.0	)	(110		)	(3.1	)
Fuel cost recovery	41			2.1		71			2.0
Retail – current year	$	1,904		(0.2	)%	$	3,593		(0.9	)%

Revenues associated with changes in rates and pricing decreased in the second quarter and increased year-to-date 2017 when compared to the corresponding periods in 2016. An increase in revenues related to the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff was more than offset in the second quarter 2017 by the rate pricing effect of decreased customer usage and lower contributions from commercial and industrial customers under a rate plan for variable demand-driven pricing. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Constructions" 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 were essentially flat in the second quarter and decreased year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjusted residential KWH sales increased 0.3%, weather-adjusted commercial KWH sales increased 0.4%, and weather-adjusted industrial KWH sales decreased

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

1.3% in the second quarter 2017 when compared to the corresponding period in 2016. For year-to-date 2017, weather-adjusted residential KWH sales increased 0.8%, weather-adjusted commercial KWH sales decreased 1.0%, and weather-adjusted industrial KWH sales decreased 2.2% when compared to the corresponding period in 2016. An increase of approximately 29,000 residential customers since June 30, 2016 contributed to the increase in weather-adjusted residential KWH sales. A decline in average customer usage resulting from an increase in energy saving initiatives and electronic commerce transactions contributed to the decrease in weather-adjusted commercial KWH sales, partially offset by an increase of approximately 2,000 commercial customers since June 30, 2016. Decreased demand in the chemicals, paper, and transportation sectors was the main contributor to the decrease in weather-adjusted industrial KWH sales, 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.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased $41 million and $71 million in the second quarter and year-to-date 2017, respectively, when compared to the corresponding periods in 2016 primarily due to higher natural gas prices, partially offset by lower energy sales resulting from milder weather as compared to the corresponding periods in 2016. 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.

Other Revenues

For year-to-date 2017, other revenues were $191 million compared to $202 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 an $8 million decrease in open access transmission tariff revenues, partially offset by a $7 million increase in outdoor lighting sales revenues primarily attributable to LED conversions and a $3 million increase in solar application fee revenue.

Fuel and Purchased Power Expenses



	Second Quarter 2017 vs. Second Quarter 2016			Year-to-Date 2017 vs. Year-to-Date 2016
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	6	1.4	$	—	—
Purchased power – non-affiliates	11		12.0	16		9.1
Purchased power – affiliates	27		24.3	60		24.0
Total fuel and purchased power expenses	$	44		$	76

In the second quarter 2017, total fuel and purchased power expenses were $686 million compared to $642 million in the corresponding period in 2016. The increase was primarily due to a $45 million increase in the average cost of fuel and purchased power primarily related to higher natural gas prices, slightly offset by a decrease related to the volume of KWHs generated and purchased due to milder weather, resulting in lower customer demand.

For year-to-date 2017, total fuel and purchased power expenses were $1.32 billion compared to $1.24 billion in the corresponding period in 2016. The increase was primarily due to an $89 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 $13 million

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

related to the volume of KWHs generated and purchased 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.

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



	Second Quarter 2017	Second Quarter 2016	Year-to-Date 2017	Year-to-Date 2016
Total generation (in billions of KWHs)	16	17	30	33
Total purchased power (in billions of KWHs)	6	6	13	12
Sources of generation (percent) —
Coal	36	36	32	33
Nuclear	25	24	25	24
Gas	37	38	41	40
Hydro	2	2	2	3
Cost of fuel, generated (in cents per net KWH) —
Coal	3.20	3.37	3.23	3.45
Nuclear	0.84	0.84	0.84	0.85
Gas	2.75	2.18	2.76	2.10
Average cost of fuel, generated (in cents per net KWH)	2.43	2.29	2.41	2.26
Average cost of purchased power (in cents per net KWH)^(*)	4.76	4.45	4.61	4.38


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

Fuel

In the second quarter 2017, fuel expense was $445 million compared to $439 million in the corresponding period in 2016. The increase was primarily due to a 26.2% increase in the average cost of natural gas per KWH generated, partially offset by a 6.1% decrease in the volume of KWHs generated by coal and natural gas. For year-to-date 2017, fuel expense remained flat compared to the corresponding period in 2016 primarily resulting from a 31.4% increase in the average cost of natural gas per KWH generated, offset by a 9.5% decrease in the volume of KWHs generated by coal and natural gas.

Purchased Power – Non-Affiliates

In the second quarter 2017, purchased power expense from non-affiliates was $103 million compared to $92 million in the corresponding period in 2016. For year-to-date 2017, purchased power expense from non-affiliates was $191 million compared to $175 million in the corresponding period in 2016. The increases were primarily due to increases in the volume of KWHs purchased of 13.4% and 11.6% in the second quarter and year-to-date 2017, respectively, due to unplanned outages at Georgia Power-owned generating units.

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

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Purchased Power – Affiliates

In the second quarter 2017, purchased power expense from affiliates was $138 million compared to $111 million in the corresponding period in 2016. The increase was primarily the result of an 11.1% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices and a 5.9% increase in the volume of KWHs purchased due to unplanned outages at Georgia Power-owned generating units and to support Southern Company system transmission reliability.

For year-to-date 2017, purchased power expense from affiliates was $310 million compared to $250 million in the corresponding period in 2016. The increase was primarily the result of a 10.1% increase in the volume of KWHs purchased due to unplanned outages at Georgia Power-owned generating units and to support Southern Company system transmission reliability and an 8.8% 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 second quarter 2017, other operations and maintenance expenses were $399 million compared to $439 million in the corresponding period in 2016. The decrease was primarily due to cost containment activities implemented in the third quarter 2016 that contributed to decreases of $14 million in generation maintenance costs and $9 million in transmission and distribution overhead line maintenance. Other factors include decreases of $9 million in customer accounts, service, and sales costs, $5 million in transmission station expenses, and $5 million in billing adjustments with integrated transmission system owners, partially offset by a $7 million increase in scheduled generation outage costs.

For year-to-date 2017, other operations and maintenance expenses were $781 million compared to $896 million in the corresponding period in 2016. The decrease was primarily due to cost containment activities implemented in the third quarter 2016 that contributed to decreases of $28 million in generation maintenance costs, $18 million in transmission and distribution maintenance costs, and $13 million in employee benefit costs. Other factors include a $19 million increase in gains from sales of integrated transmission system assets and a $14 million decrease in customer assistance expenses primarily in demand-side management costs related to the timing of new programs.

Depreciation and Amortization

In the second quarter 2017, depreciation and amortization was $223 million compared to $214 million in the corresponding period in 2016. The increase was primarily due to a $7 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 $444 million compared to $425 million in the corresponding period in 2016. The increase was primarily due to a $17 million increase related to additional plant in service and a $7 million decrease in amortization of regulatory liabilities related to other cost of removal obligations

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

that expired in December 2016, partially offset by a $5 million decrease in depreciation related to generating unit retirements in 2016.

Interest Expense, Net of Amounts Capitalized

In the second quarter 2017, interest expense, net of amounts capitalized was $104 million compared to $99 million in the corresponding period in 2016. For year-to-date 2017, interest expense, net of amounts capitalized was $205 million compared to $193 million in the corresponding period in 2016. The increases were primarily due to senior notes issuances 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.

Other Income (Expense), Net

In the second quarter 2017, other income (expense), net was $16 million compared to $8 million in the corresponding period in 2016. For year-to-date 2017, other income (expense), net was $36 million compared to $26 million in the corresponding period in 2016. The increases were primarily due to increases in gains on purchases of state tax credits.

Income Taxes

In the second quarter 2017, income taxes were $199 million compared to $211 million in the corresponding period in 2016. For year-to-date 2017, income taxes were $355 million compared to $371 million in the corresponding period in 2016. The decreases were primarily due to increased state ITCs and lower pre-tax earnings.

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. Completing the cost assessments and determining future actions 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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

driven by economic growth. The pace of economic growth and electricity demand 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.

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, it remains a separate, ongoing matter.

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

Renewables

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

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Integrated Resource Plan

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

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Regulatory Matters

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Revised Cost and Schedule



Preliminary in-service dates
Unit 3	February 2021			–	March 2022
Unit 4	February 2022			–	March 2023
	(in billions)
Preliminary estimated cost to complete	$	3.9		–	$	4.6
CWIP as of June 30, 2017	4.5				4.5
Guarantee Obligations	(1.7		)		(1.7		)
Estimated capital costs	$	6.7		–	$	7.4
Vogtle Cost Settlement Agreement Revised Forecast	(5.7		)		(5.7		)
Estimated net additional capital costs	$	1.0		–	$	1.7

Georgia Power's estimated financing costs during the construction period total approximately $3.1 billion to $3.5 billion, of which approximately $1.4 billion had been incurred through June 30, 2017.



	Preliminary Cancellation Cost Estimate
	(in billions)
CWIP as of June 30, 2017	$	4.5
Financing costs collected, net of tax	1.4
Cancellation costs^(*)	0.4
Total	$	6.3


(*)	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 is dependent on the completion of the assessments described above, as well as the related regulatory treatment, and cannot be determined at this time.

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GEORGIA POWER COMPANY

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Matters

As of June 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 and a multi-advance credit facility among Georgia Power, the DOE, and the FFB. 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.

The ultimate outcome of such pending or potential litigation against Georgia Power 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.

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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

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 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.

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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. Georgia 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 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.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power's financial condition remained stable at June 30, 2017. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $482 million for the first six months of 2017 compared to $1.17 billion for the corresponding period in 2016. The decrease was primarily due to the timing of vendor payments and an increase in under-recovered fuel costs. Net cash used for investing activities totaled $1.33 billion for the first six months of 2017 compared to $1.17 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 $931 million for the first six months of 2017 compared to $51 million in the corresponding period in 2016. The increase in cash provided from financing activities is primarily due to an increase in short-term borrowings, higher issuances of senior notes, and higher capital contributions received from Southern Company, partially offset by a decrease in borrowings from the FFB for construction of Plant Vogtle Units 3 and 4. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2017 include an increase in property, plant, and equipment of $857 million to comply with environmental standards and the construction of generation, transmission, and distribution facilities, an increase in notes payable of $837 million primarily due to issuances of short-term bank debt, an increase in paid-in capital of $389 million primarily due to capital contributions received from Southern Company, and an increase in long-term debt of $369 million primarily due to issuances of senior notes.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power's capital requirements for its construction program, including estimated capital expenditures for Plant Vogtle Units 3 and 4 and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $261 million will be required through June 30, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information. Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures, including Georgia Power's preliminary 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.

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 Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Eligible Project Costs incurred through June 30, 2017 would allow for borrowings of up to $3.1 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.6 billion; however, on July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) to clarify the operation of the Loan Guarantee Agreement pending Georgia Power's completion of its comprehensive schedule, cost-to-complete, and cancellation cost assessments (Cost Assessments) for Plant Vogtle Units 3 and 4. Under the terms of the LGA Amendment, Georgia Power will not request any advances under the Loan Guarantee Agreement unless and until such time as Georgia Power has completed the Cost Assessments and made a determination to continue construction of Plant Vogtle Units 3 and 4 and satisfied certain other conditions related to continuing construction. 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 June 30, 2017, Georgia Power's current liabilities exceeded current assets by $1.42 billion. Georgia Power's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt ($261 million at June 30, 2017) and the periodic use of short-term debt as a funding source ($1.2 billion at June 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 June 30, 2017, Georgia Power had approximately $91 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks at June 30, 2017 was $1.75 billion of which $1.73 billion was unused. In May 2017, Georgia Power amended its multi-year credit arrangement, which, among other things, extended the maturity date from 2020 to 2022.

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This bank credit arrangement, as well as Georgia Power's term loan arrangements, contains a covenant that limits debt levels and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross-acceleration provision to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, the payment of which was then accelerated. At June 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 June 30, 2017 was approximately $550 million. 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 June 30, 2017, Georgia Power had $436 million of pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Commercial paper is included in notes payable in the balance sheets.

Details of short-term borrowings were as follows:



	Short-term Debt at June 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	$	428	1.5	%	$	280	1.4	%	$	760
Short-term bank debt	800		2.0	%	227		2.0	%	800
Total	$	1,228	1.8	%	$	507	1.6	%


(*)	Average and maximum amounts are based upon daily balances during the three-month period ended June 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 June 30, 2017, Georgia Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, and transmission, and, at June 30, 2017, included contracts related to the construction of new generation at Plant Vogtle Units 3 and 4.

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



Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	87
Below BBB- and/or Baa3	$	1,210

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.

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

Financing Activities

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

In April 2017, Georgia Power purchased and held $27 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995. Georgia Power may reoffer these bonds to the public at a later date.

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, which mature on December 1, 2017, May 31, 2018, and June 28, 2018, respectively, and 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 addition to any financings that may be necessary to meet capital requirements and contractual obligations, Georgia Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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GULF POWER COMPANY

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GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	318		$	319		$	596		$	602
Wholesale revenues, non-affiliates	12			15			30			31
Wholesale revenues, affiliates	10			15			47			36
Other revenues	17			16			34			31
Total operating revenues	357			365			707			700
Operating Expenses:
Fuel	88			107			196			201
Purchased power, non-affiliates	35			32			67			62
Purchased power, affiliates	9			4			11			5
Other operations and maintenance	87			77			171			155
Depreciation and amortization	35			42			53			80
Taxes other than income taxes	28			29			55			58
Loss on Plant Scherer Unit 3	—			—			33			—
Total operating expenses	282			291			586			561
Operating Income	75			74			121			139
Other Income and (Expense):
Interest expense, net of amounts capitalized	(13		)	(12		)	(24		)	(25		)
Other income (expense), net	(1		)	(1		)	(2		)	(2		)
Total other income and (expense)	(14		)	(13		)	(26		)	(27		)
Earnings Before Income Taxes	61			61			95			112
Income taxes	24			24			38			44
Net Income	37			37			57			68
Dividends on Preference Stock	2			3			4			5
Net Income After Dividends on Preference Stock	$	35		$	34		$	53		$	63

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Net Income	$	37		$	37		$	57		$	68
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $(1), $(1), and $(3), respectively	(1		)	(1		)	(1		)	(4		)
Total other comprehensive income (loss)	(1		)	(1		)	(1		)	(4		)
Comprehensive Income	$	36		$	36		$	56		$	64

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

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GULF POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)



	For the Six Months Ended June 30,
	2017			2016
	(in millions)
Operating Activities:
Net income	$	57		$	68
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	56			83
Deferred income taxes	19			16
Loss on Plant Scherer Unit 3	33			—
Other, net	(4		)	(3		)
Changes in certain current assets and liabilities —
-Receivables	(25		)	(6		)
-Fossil fuel stock	4			34
-Other current assets	10			1
-Accrued taxes	7			17
-Accrued compensation	(17		)	(12		)
-Over recovered regulatory clause revenues	(19		)	5
-Other current liabilities	3			(7		)
Net cash provided from operating activities	124			196
Investing Activities:
Property additions	(97		)	(68		)
Cost of removal, net of salvage	(9		)	(4		)
Change in construction payables	(14		)	(7		)
Other investing activities	(3		)	(5		)
Net cash used for investing activities	(123		)	(84		)
Financing Activities:
Increase (decrease) in notes payable, net	(190		)	46
Proceeds —
Common stock issued to parent	175			—
Capital contributions from parent company	5			5
Senior notes	300			—
Redemptions —
Preference stock	(150		)	—
Senior notes	(85		)	(125		)
Payment of common stock dividends	(63		)	(60		)
Other financing activities	(4		)	(6		)
Net cash used for financing activities	(12		)	(140		)
Net Change in Cash and Cash Equivalents	(11		)	(28		)
Cash and Cash Equivalents at Beginning of Period	56			74
Cash and Cash Equivalents at End of Period	$	45		$	46
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $- and $- capitalized for 2017 and 2016, respectively)	$	22		$	28
Income taxes, net	7			(3		)
Noncash transactions — Accrued property additions at end of period	19			13

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

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GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)



Assets	At June 30, 2017			At December 31, 2016
	(in millions)
Current Assets:
Cash and cash equivalents	$	45		$	56
Receivables —
Customer accounts receivable	77			72
Unbilled revenues	70			55
Under recovered regulatory clause revenues	26			17
Other accounts and notes receivable	11			6
Affiliated	8			17
Accumulated provision for uncollectible accounts	(1		)	(1		)
Fossil fuel stock	67			71
Materials and supplies	57			55
Other regulatory assets, current	55			44
Other current assets	17			30
Total current assets	432			422
Property, Plant, and Equipment:
In service	5,156			5,140
Less: Accumulated provision for depreciation	1,427			1,382
Plant in service, net of depreciation	3,729			3,758
Construction work in progress	59			51
Total property, plant, and equipment	3,788			3,809
Deferred Charges and Other Assets:
Deferred charges related to income taxes	57			58
Other regulatory assets, deferred	510			512
Other deferred charges and assets	22			21
Total deferred charges and other assets	589			591
Total Assets	$	4,809		$	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

CONDENSED BALANCE SHEETS (UNAUDITED)



Liabilities and Stockholder's Equity	At June 30, 2017			At December 31, 2016
	(in millions)
Current Liabilities:
Securities due within one year	$	27		$	87
Notes payable	78			268
Accounts payable —
Affiliated	52			59
Other	46			54
Customer deposits	35			35
Accrued taxes	27			20
Accrued interest	9			8
Accrued compensation	23			40
Deferred capacity expense, current	22			22
Other regulatory liabilities, current	—			16
Other current liabilities	43			40
Total current liabilities	362			649
Long-term Debt	1,265			987
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	966			948
Employee benefit obligations	92			96
Deferred capacity expense	108			119
Asset retirement obligations, deferred	125			120
Other cost of removal obligations	218			249
Other regulatory liabilities, deferred	46			47
Other deferred credits and liabilities	74			71
Total deferred credits and other liabilities	1,629			1,650
Total Liabilities	3,256			3,286
Preference Stock	—			147
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — June 30, 2017: 7,392,717 shares
— December 31, 2016: 5,642,717 shares	678			503
Paid-in capital	596			589
Retained earnings	280			296
Accumulated other comprehensive income (loss)	(1		)	1
Total common stockholder's equity	1,553			1,389
Total Liabilities and Stockholder's Equity	$	4,809		$	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

SECOND QUARTER 2017 vs. SECOND QUARTER 2016

AND

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

OVERVIEW

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

Many factors affect the opportunities, challenges, and risks of Gulf Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, restoration following major storms, fuel, and capital expenditures. Gulf Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Gulf Power for the foreseeable future.

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

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

RESULTS OF OPERATIONS

Net Income

Gulf Power's net income after dividends on preference stock for the second quarter 2017 was $35 million compared to $34 million for the corresponding period in 2016. Gulf Power's net income after dividends on preference stock for year-to-date 2017 was $53 million compared to $63 million for the corresponding period in 2016. The decrease for year-to-date 2017 was primarily due to a write-down of $32.5 million ($20 million after tax) of Gulf Power's ownership of Plant Scherer Unit 3 resulting from the 2017 Rate Case Settlement Agreement and higher operations and maintenance expenses, partially offset by lower depreciation and higher wholesale revenue. See Note (B) to the

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.

Retail Revenues

In the second quarter 2017, retail revenues were $318 million compared to $319 million for the corresponding period in 2016. For year-to-date 2017, retail revenues were $596 million compared to $602 million for the corresponding period in 2016.

Details of the changes in retail revenues were as follows:



	Second Quarter 2017					Year-to-Date 2017
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	319				$	602
Estimated change resulting from –
Rates and pricing	5			1.6		7			1.2
Sales decline	(1		)	(0.3	)	(3		)	(0.5	)
Weather	—			—		(6		)	(1.0	)
Fuel and other cost recovery	(5		)	(1.6	)	(4		)	(0.7	)
Retail – current year	$	318		(0.3	)%	$	596		(1.0	)%

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

Revenues attributable to changes in sales decreased in the second quarter and year-to-date 2017 when compared to the corresponding periods in 2016. Weather-adjusted KWH sales to residential and commercial customers decreased 1.2% and 1.3%, respectively, for the second quarter 2017 and 1.3% and 1.0%, respectively, for year-to-date 2017 due to lower customer usage primarily resulting from efficiency improvements in appliances and lighting, partially offset by customer growth. KWH sales to industrial customers decreased 2.7% and 5.6% for the second quarter and year-to-date 2017, respectively, primarily due to changes in customers' operations. The year-to-date 2017 decrease also reflects increased customer co-generation.

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

Wholesale Revenues – Affiliates

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 second quarter 2017, wholesale revenues from sales to affiliates were $10 million compared to $15 million for the corresponding period in 2016. The decrease was primarily due to a 40.6% decrease in KWH sales due to decreased generation as a result of milder weather reducing Southern Company system loads.

For year-to-date 2017, wholesale revenues from sales to affiliates were $47 million compared to $36 million for the corresponding period in 2016. The increase was primarily due to a 17.2% increase in KWH sales as a result of supporting Southern Company system transmission reliability and a 10.0% increase in the price of energy due to higher natural gas prices.

Fuel and Purchased Power Expenses



	Second Quarter 2017 vs. Second Quarter 2016					Year-to-Date 2017 vs. Year-to-Date 2016
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	(19	)	(17.8	)	$	(5	)	(2.5	)
Purchased power – non-affiliates	3			9.4		5			8.1
Purchased power – affiliates	5			125.0		6			120.0
Total fuel and purchased power expenses	$	(11	)			$	6

In the second quarter 2017, total fuel and purchased power expenses were $132 million compared to $143 million for the corresponding period in 2016. The decrease was primarily the result of a $21 million net decrease related to the volume of KWHs generated and purchased due to milder weather in 2017 reducing demand, partially offset by an $11 million net increase due to the higher average cost of fuel associated with purchased power.

For year-to-date 2017, total fuel and purchased power expenses were $274 million compared to $268 million for the corresponding period in 2016. The increase was primarily the result of a $16 million net increase related to the higher average cost of fuel and purchased power resulting from higher natural gas prices, partially offset by a $10 million net decrease related to the volume of KWHs generated and purchased due to milder weather in 2017 reducing demand.

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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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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



	Second Quarter 2017	Second Quarter 2016	Year-to-Date 2017	Year-to-Date 2016
Total generation (in millions of KWHs)	1,898	2,064	4,220	3,880
Total purchased power (in millions of KWHs)	1,218	1,629	2,676	3,389
Sources of generation (percent) –
Coal	50	54	52	48
Gas	50	46	48	52
Cost of fuel, generated (in cents per net KWH) –
Coal	3.17	4.14	3.23	4.05
Gas	3.88	4.11	3.54	3.92
Average cost of fuel, generated (in cents per net KWH)	3.53	4.12	3.38	3.98
Average cost of purchased power (in cents per net KWH)^(*)	5.37	3.50	4.93	3.35


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

Fuel

In the second quarter 2017, fuel expense was $88 million compared to $107 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 and a 15.3% decrease in the volume of KWHs generated by Gulf Power's coal-fired generation resources due to milder weather reducing demand.

For year-to-date 2017, fuel expense was $196 million compared to $201 million for the corresponding period in 2016. The decrease was primarily due to a 15.1% decrease in the average cost of fuel resulting from lower coal and natural gas prices, partially offset by an 8.8% increase in the volume of KWHs generated by Gulf Power's coal-fired and gas-fired generation resources due to Southern Company system reliability requirements.

Purchased Power – Non-Affiliates

In the second quarter 2017, purchased power expense from non-affiliates was $35 million compared to $32 million for the corresponding period in 2016. The increase was primarily due to a 68.7% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices, partially offset by a 37.9% decrease in the volume of KWHs purchased due to a planned outage of an external generation resource under a PPA.

For year-to-date 2017, purchased power expense from non-affiliates was $67 million compared to $62 million for the corresponding period in 2016. The increase was primarily due to a 50.0% increase in the average cost per KWH purchased primarily resulting from higher natural gas prices, partially offset by a 25.6% decrease in the volume of KWHs purchased due to a planned outage of an external generation resource under a PPA.

Purchased Power – Affiliates

In the second quarter 2017, purchased power expense from affiliates was $9 million compared to $4 million for the corresponding period in 2016. The increase was primarily due to a 66.1% increase in the volume of KWHs purchased due to availability of power pool resources at lower cost compared to Gulf Power generation.

For year-to-date 2017, purchased power expense from affiliates was $11 million compared to $5 million for the corresponding period in 2016. The increase was primarily due to a 22.9% increase in the volume of KWHs

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purchased due to availability of power pool resources at lower cost compared to Gulf Power generation and a 67.1% increase in the average cost per KWH purchased primarily resulting from increased natural gas prices.

Other Operations and Maintenance Expenses

In the second quarter 2017, other operations and maintenance expenses were $87 million compared to $77 million for the corresponding period in 2016. For year-to-date 2017, other operations and maintenance expenses were $171 million compared to $155 million for the corresponding period in 2016. The increases were primarily due to higher expenses at generation facilities associated with routine and planned maintenance.

Depreciation and Amortization

In the second quarter 2017, depreciation and amortization was $35 million compared to $42 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $53 million compared to $80 million for the corresponding period in 2016. The decreases were primarily due to $8 million and $28 million more of a reduction in depreciation, as authorized in a settlement agreement approved by the Florida PSC in 2013 (2013 Rate Case Settlement Agreement), in the second 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.

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 pace of economic growth and electricity demand 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 Gulf Power's financial statements. For additional information relating to these issues, see RISK FACTORS in Item

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1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in retail rates or through long-term wholesale agreements on a timely basis or through market-based contracts. The State of Florida has statutory provisions that allow a utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Gulf Power's current long-term wholesale agreements contain provisions that permit charging the customer with costs incurred as a result of changes in environmental laws and regulations. The full impact of any such legislative or regulatory changes cannot be determined at this time. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Further, higher costs that are recovered through regulated rates or long-term wholesale agreements could contribute to reduced demand for electricity as well as impact the cost competitiveness of wholesale capacity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters," "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery," and "Other Matters" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Statutes and Regulations

Water Quality

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

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

Global Climate Issues

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

On 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.

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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, it remains a separate, ongoing matter.

Retail Regulatory Matters

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

Retail Base Rate Cases

The 2013 Rate Case Settlement Agreement authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction could not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. For 2014 and 2015, Gulf Power recognized reductions in depreciation of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016. In the first six months of 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. Under 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 consists 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 over 15 years effective January 1, 2018 and will implement new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3, which was recorded in the first quarter 2017. The remaining issues related to the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates have been resolved as a result of the 2017 Rate Case Settlement Agreement, including recoverability of certain costs associated with the ongoing ownership and operation of the unit through the environmental cost recovery clause rate approved by the Florida PSC in November 2016.

Cost Recovery Clauses

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting

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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.

Other Matters

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

The ultimate outcome of such pending or potential litigation against Gulf Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Gulf Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

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

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

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

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

On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit 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. 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.

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 June 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 $124 million for the first six months of 2017 compared to $196 million for the corresponding period in 2016. The $72 million decrease in net cash was primarily due to the timing of fossil fuel stock purchases, a federal income tax refund received in 2016, as well as decreases in cash flows associated with lower cost recovery clause rates. Net cash used for investing activities totaled $123 million in the first six months of 2017 primarily due to property additions to utility plant. Net cash used for financing activities totaled $12 million for the first six months of 2017 primarily due to the payment of short-term debt, redemptions of preference stock and long-term debt, and common stock dividend payments, partially offset by proceeds from

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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 six months of 2017 primarily reflect the financing activities described above. Other significant changes include a decrease in other cost of removal obligations, as authorized in the 2013 Settlement Agreement, and a decrease in property, plant, and equipment primarily due to the write-down of Gulf Power's ownership of Plant Scherer Unit 3. See "Financing Activities" herein and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, derivative obligations, purchase commitments, and trust funding requirements. Approximately $7 million will be required through June 30, 2018 to fund maturities of long-term debt. In addition, at June 30, 2017, $20 million of Gulf Power's total fixed rate pollution control revenue bonds required to be remarketed over the next 12 months are classified as securities due within one year. See "Financing Activities" herein for additional information.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in the expected environmental compliance programs; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

Gulf Power plans to obtain the funds required to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, external security issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Gulf Power in Item 7 of the Form 10-K for additional information.

Gulf Power's current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as significant seasonal fluctuations in cash needs. Gulf Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet short-term liquidity needs, including its commercial paper program which is supported by bank credit facilities.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At June 30, 2017, Gulf Power had approximately $45 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2017 were as follows:



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

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

Most of these bank credit arrangements contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) of Gulf Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Gulf Power defaulted on indebtedness, the payment of which was then accelerated. At June 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.

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 June 30, 2017 was approximately $82 million. In addition, at June 30, 2017, Gulf Power had approximately $140 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.

Gulf Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Gulf Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Gulf Power are loaned directly to Gulf Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Short-term borrowings are included in notes payable in the balance sheets.

Details of short-term borrowings were as follows:



	Short-term Debt at June 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	$	78	1.5	%	$	20	1.4	%	$	78
Short-term bank debt	—		—	%	53		1.7	%	100
Total	$	78	1.5	%	$	73	1.6	%


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

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Credit Rating Risk

At June 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.

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



Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	167
Below BBB- and/or Baa3	$	570

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.

Market Price Risk

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

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

The Florida PSC extended the moratorium on Gulf Power's fuel-hedging program through 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.

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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 550,000 shares ($55 million aggregate liquidation amount) of 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Series 2013A 5.60% Preference Stock.

In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm recovery, Gulf Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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CONDENSED STATEMENTS OF INCOME (UNAUDITED)



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	222		$	206		$	422		$	389
Wholesale revenues, non-affiliates	62			60			124			120
Wholesale revenues, affiliates	15			7			20			16
Other revenues	4			4			9			8
Total operating revenues	303			277			575			533
Operating Expenses:
Fuel	102			81			180			157
Purchased power, non-affiliates	2			1			3			1
Purchased power, affiliates	4			4			11			9
Other operations and maintenance	70			68			144			136
Depreciation and amortization	41			45			81			84
Taxes other than income taxes	26			25			52			50
Estimated loss on Kemper IGCC	3,012			81			3,120			134
Total operating expenses	3,257			305			3,591			571
Operating Loss	(2,954		)	(28		)	(3,016		)	(38		)
Other Income and (Expense):
Allowance for equity funds used during construction	36			30			71			59
Interest expense, net of amounts capitalized	(17		)	(15		)	(37		)	(31		)
Other income (expense), net	1			(1		)	1			(3		)
Total other income and (expense)	20			14			35			25
Loss Before Income Taxes	(2,934		)	(14		)	(2,981		)	(13		)
Income taxes (benefit)	(881		)	(17		)	(908		)	(27		)
Net Income (Loss)	(2,053		)	3			(2,073		)	14
Dividends on Preferred Stock	1			1			1			1
Net Income (Loss) After Dividends on Preferred Stock	$	(2,054	)	$	2		$	(2,074	)	$	13

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)



	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2017			2016		2017			2016
	(in millions)					(in millions)
Net Income (Loss)	$	(2,053	)	$	3	$	(2,073	)	$	14
Other comprehensive income (loss)
Qualifying hedges:
Changes in fair value, net of tax of $-, $-, $-, and $-, respectively	—			—		1			—
Total other comprehensive income (loss)	—			—		1			—
Comprehensive Income (Loss)	$	(2,053	)	$	3	$	(2,072	)	$	14

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

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CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)



	For the Six Months Ended June 30,
	2017			2016
	(in millions)
Operating Activities:
Net income (loss)	$	(2,073	)	$	14
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	94			82
Deferred income taxes	(860		)	(16		)
Allowance for equity funds used during construction	(71		)	(59		)
Estimated loss on Kemper IGCC	3,120			134
Other, net	(11		)	(8		)
Changes in certain current assets and liabilities —
-Receivables	(15		)	15
-Fossil fuel stock	21			6
-Other current assets	(10		)	31
-Accounts payable	(20		)	(12		)
-Accrued taxes	—			20
-Accrued compensation	(17		)	(12		)
-Over recovered regulatory clause revenues	(30		)	4
-Customer liability associated with Kemper refunds	—			(69		)
-Other current liabilities	7			7
Net cash provided from operating activities	135			137
Investing Activities:
Property additions	(337		)	(403		)
Construction payables	(19		)	(11		)
Government grant proceeds	—			137
Other investing activities	(5		)	(19		)
Net cash used for investing activities	(361		)	(296		)
Financing Activities:
Decrease in notes payable, net	(10		)	—
Proceeds —
Capital contributions from parent company	1,001			226
Long-term debt to parent company	40			200
Other long-term debt	—			900
Short-term borrowings	4			—
Redemptions —
Short-term borrowings	—			(475		)
Long-term debt to parent company	(591		)	(225		)
Other long-term debt	(300		)	(425		)
Other financing activities	(2		)	(3		)
Net cash provided from financing activities	142			198
Net Change in Cash and Cash Equivalents	(84		)	39
Cash and Cash Equivalents at Beginning of Period	224			98
Cash and Cash Equivalents at End of Period	$	140		$	137
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $53 and $49, net of $27 and $23 capitalized for 2017 and 2016, respectively)	$	26		$	26
Income taxes, net	(93		)	(122		)
Noncash transactions — Accrued property additions at end of period	59			94

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

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CONDENSED BALANCE SHEETS (UNAUDITED)



Assets	At June 30, 2017		At December 31, 2016
	(in millions)
Current Assets:
Cash and cash equivalents	$	140	$	224
Receivables —
Customer accounts receivable	33		29
Unbilled revenues	42		42
Income taxes receivable, current	544		544
Other accounts and notes receivable	25		14
Affiliated	20		15
Fossil fuel stock	20		100
Materials and supplies	44		76
Other regulatory assets, current	114		115
Other current assets	2		8
Total current assets	984		1,167
Property, Plant, and Equipment:
In service	4,826		4,865
Less: Accumulated provision for depreciation	1,283		1,289
Plant in service, net of depreciation	3,543		3,576
Construction work in progress	56		2,545
Total property, plant, and equipment	3,599		6,121
Other Property and Investments	22		12
Deferred Charges and Other Assets:
Deferred charges related to income taxes	61		361
Other regulatory assets, deferred	441		518
Accumulated deferred income taxes	404		—
Other deferred charges and assets	20		56
Total deferred charges and other assets	926		935
Total Assets	$	5,531	$	8,235

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

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CONDENSED BALANCE SHEETS (UNAUDITED)



Liabilities and Stockholder's Equity	At June 30, 2017			At December 31, 2016
	(in millions)
Current Liabilities:
Securities due within one year —
Parent	$	—		$	551
Other	1,028			78
Notes payable	17			23
Accounts payable —
Affiliated	54			62
Other	109			135
Customer deposits	16			16
Accrued taxes	97			99
Unrecognized tax benefits	385			383
Accrued interest	52			46
Accrued compensation	25			42
Asset retirement obligations, current	21			32
Over recovered regulatory clause liabilities	21			51
Other current liabilities	89			20
Total current liabilities	1,914			1,538
Long-term Debt	1,169			2,424
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	—			756
Employee benefit obligations	111			115
Asset retirement obligations, deferred	149			146
Other cost of removal obligations	173			170
Other regulatory liabilities, deferred	80			84
Other deferred credits and liabilities	29			26
Total deferred credits and other liabilities	542			1,297
Total Liabilities	3,625			5,259
Redeemable Preferred Stock	33			33
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 1,130,000 shares
Outstanding — 1,121,000 shares	38			38
Paid-in capital	4,527			3,525
Accumulated deficit	(2,689		)	(616		)
Accumulated other comprehensive loss	(3		)	(4		)
Total common stockholder's equity	1,873			2,943
Total Liabilities and Stockholder's Equity	$	5,531		$	8,235

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2017 vs. SECOND QUARTER 2016

AND

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

OVERVIEW

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

Many factors affect the opportunities, challenges, and risks of Mississippi Power's business of providing electric service. These factors include Mississippi Power's ability to maintain and grow energy sales and to operate in a constructive regulatory environment that provides timely recovery of prudently-incurred costs. These costs include those related to the Kemper County energy facility, projected long-term demand growth, reliability, fuel, and stringent environmental standards, as well as ongoing capital expenditures required for maintenance and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.

The Kemper IGCC was approved by the Mississippi PSC in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (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 combined cycle and associated common facilities portion of the Kemper IGCC were placed in service in August 2014.

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC (Kemper Settlement Order). The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC (Kemper IGCC Settlement Docket). The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility. The Kemper Settlement Order provides that any related settlement agreement be filed within 45 days from the effective date of the Kemper Settlement Order. If a settlement agreement is filed, a hearing will be set 45 days from the date of the settlement's filing, and the appropriate scheduling order will be established.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

previously contracted to SMEPA. Mississippi Power has calculated the revenue requirements resulting from these remaining costs, using reasonable assumptions for amortization periods, and expects them to be recovered through rates consistent with the Mississippi PSC's requested settlement conditions. The ultimate outcome will be determined by the Mississippi PSC in the Kemper IGCC Settlement Docket proceedings.

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

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

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

In addition to the rate recovery of the Kemper County energy facility, Mississippi Power continues to focus on several key performance indicators. In recognition that Mississippi Power's long-term financial success is dependent upon how well it satisfies its customers' needs, Mississippi Power's retail base rate mechanism, PEP, includes performance indicators that directly tie customer service indicators to Mississippi Power's allowed ROE. Mississippi Power also focuses on broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock.

RESULTS OF OPERATIONS

Net Income (Loss)

N/M - Not meaningful

In the second quarter and year-to-date 2017, Mississippi Power's net loss after dividends on preferred stock was $2.05 billion and $2.07 billion, respectively, compared to net income of $2 million and $13 million, respectively, for the corresponding periods in 2016. In the second quarter and year-to-date 2017, the decrease in net income was related to higher pre-tax charges associated with the Kemper IGCC of $3.0 billion ($2.1 billion after tax) and $3.1 billion ($2.2 billion after tax), respectively, compared to pre-tax charges of $81 million ($50 million after tax) and $134 million ($83 million after tax), respectively, for the corresponding periods in 2016. The changes in net income were partially offset by a decrease in depreciation and amortization and increases in retail revenues, AFUDC equity, and income tax benefits.

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

In the second quarter 2017, retail revenues were $222 million compared to $206 million for the corresponding period in 2016. For year-to-date 2017, retail revenues were $422 million compared to $389 million for the corresponding period in 2016.

Details of the changes in retail revenues were as follows:



	Second Quarter 2017					Year-to-Date 2017
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	206				$	389
Estimated change resulting from –
Rates and pricing	8			3.9		19			4.9
Sales growth (decline)	(2		)	(0.9	)	3			0.8
Weather	(2		)	(1.0	)	(7		)	(1.8	)
Fuel and other cost recovery	12			5.8		18			4.6
Retail – current year	$	222		7.8	%	$	422		8.5	%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2017 when compared to the corresponding periods in 2016 primarily due to an ECO Plan rate increase implemented in the third quarter 2016, partially offset by an ECO Plan rate decrease implemented in the second quarter 2017.

Revenues attributable to changes in sales decreased for the second quarter 2017 when compared to the corresponding period in 2016. Weather-adjusted KWH sales to residential customers decreased 2.7% due to lower customer usage. Weather-adjusted KWH sales to commercial customers decreased 0.8% due to lower customer usage, offset by customer growth. KWH sales to industrial customers decreased 1.3% primarily due to an unplanned outage by a large customer in 2017 and a decrease in the number of mid-size customers.

Revenues attributable to changes in sales increased for year-to-date 2017 when compared to the corresponding period in 2016. Weather-adjusted KWH sales to residential and commercial customers decreased 0.7% and 0.5%, respectively, due to lower customer usage. KWH sales to industrial customers decreased 0.4% primarily due to an unplanned outage by a larger customer in 2017 and a decrease in the number of mid-size customers.

Fuel and other cost recovery revenues increased in the second quarter and year-to-date 2017 when compared to the corresponding periods 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 – Non-Affiliates

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for

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energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. In addition, Mississippi Power provides service under long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Mississippi Power in Item 7 of the Form 10-K and – FUTURE EARNINGS POTENTIAL – "FERC Matters" herein for additional information.

In the second quarter and year-to-date 2017, wholesale revenues from sales to non-affiliates were $62 million and $124 million, respectively, compared to $60 million and $120 million for the corresponding periods in 2016. The increases were due to increases in energy revenues of $4 million and $5 million in the second quarter and year-to-date 2017, respectively, primarily resulting from higher fuel prices, partially offset by decreases in base and capacity revenues of $2 million and $1 million, respectively, primarily due to milder weather resulting in lower sales.

Wholesale Revenues – Affiliates

N/M - Not meaningful

In the second quarter 2017, wholesale revenues from sales to affiliates were $15 million compared to $7 million for the corresponding period in 2016. The increase was due to a $6 million increase in KWH sales and a $2 million increase primarily due to higher natural gas prices.

For year-to-date 2017, wholesale revenues from sales to affiliates were $20 million compared to $16 million for the corresponding period in 2016. The increase was primarily due to higher natural gas prices.

Fuel and Purchased Power Expenses



	Second Quarter 2017 vs. Second Quarter 2016			Year-to-Date 2017 vs. Year-to-Date 2016
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	21	25.9	$	23	14.6
Purchased power – non-affiliates	1		100.0	2		200.0
Purchased power – affiliates	—		—	2		22.2
Total fuel and purchased power expenses	$	22		$	27

In the second quarter 2017, total fuel and purchased power expenses were $108 million compared to $86 million for the corresponding period in 2016. The increase was due to a $17 million increase in natural gas prices and a $5 million increase in the volume of KWHs generated and purchased.

For year-to-date 2017, total fuel and purchased power expenses were $194 million compared to $167 million for the corresponding period in 2016. The increase was due to a $34 million increase in natural gas prices, partially offset by a $7 million decrease in the volume of KWHs generated and purchased.

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

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



	Second Quarter 2017	Second Quarter 2016	Year-to-Date 2017	Year-to-Date 2016
Total generation (in millions of KWHs)	3,927	3,728	7,088	7,315
Total purchased power (in millions of KWHs)^(*)	121	188	362	449
Sources of generation (percent) –
Coal	7	5	8	8
Gas	93	95	92	92
Cost of fuel, generated (in cents per net KWH) –
Coal	3.61	5.49	3.46	4.16
Gas	2.73	2.17	2.69	2.16
Average cost of fuel, generated (in cents per net KWH)	2.79	2.33	2.76	2.32
Average cost of purchased power (in cents per net KWH)^(*)	4.74	2.55	3.80	2.33


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

Fuel

In the second quarter 2017, total fuel expense was $102 million compared to $81 million for the corresponding period in 2016. The increase was due to a 20% increase in the average cost of fuel per KWH generated, primarily due to a 26% higher cost of natural gas, and a 6% increase in the volume of KWHs generated.

For year-to-date 2017, total fuel expense was $180 million compared to $157 million for the corresponding period in 2016. The increase was due to a 19% increase in the average cost of fuel per KWH generated primarily due to a 25% higher cost of natural gas, partially offset by a 3% decrease in the volume of KWHs generated.

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

For year-to-date 2017, other operations and maintenance expenses were $144 million compared to $136 million for the corresponding period in 2016. The increase was primarily associated with the Kemper IGCC in-service assets.

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

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Depreciation and Amortization

In the second quarter 2017, depreciation and amortization was $41 million compared to $45 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $81 million compared to $84 million for the corresponding period in 2016. The decreases were primarily related to changes in amortization and deferrals associated with regulatory assets.

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

Estimated Loss on Kemper IGCC

N/M - Not meaningful

Prior to the project suspension on June 28, 2017, estimated probable losses on the Kemper IGCC totaled $196 million and $305 million in the second quarter and year-to-date 2017, respectively, compared to $81 million and $134 million in the second quarter and year-to-date 2016, respectively. These losses reflected revisions of estimated costs expected to be incurred on the construction of the Kemper IGCC prior to project suspension 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.

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 Settlement Order, 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, which includes estimated costs associated with the gasification portions of the plant and lignite mine.

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 second quarter 2017, AFUDC equity was $36 million compared to $30 million for the corresponding period in 2016. For year-to-date 2017, AFUDC equity was $71 million compared to $59 million for the corresponding period in 2016. The increases resulted from a higher AFUDC rate and an increase in Kemper IGCC CWIP subject to AFUDC prior to project suspension.

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

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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

In the second quarter 2017, interest expense, net of amounts capitalized was $17 million compared to $15 million, for the corresponding period in 2016. For year-to-date 2017, interest expense, net of amounts capitalized was $37 million compared to $31 million for the corresponding period in 2016. The increases were primarily associated with the Kemper IGCC in-service assets.

Income Taxes (Benefit)

N/M - Not meaningful

In the second quarter 2017, income tax benefit was $881 million compared to $17 million for the corresponding period in 2016. For year-to-date 2017, income tax benefit was $908 million compared to $27 million for the corresponding period in 2016. The changes were primarily due to the estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion and the related state valuation allowances.

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

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Mississippi Power's future earnings potential. The level of Mississippi Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Mississippi Power's business of providing electric service. These factors include Mississippi Power's ability to recover its prudently-incurred costs, including those related to the remainder of the Kemper County energy facility not included in current rates, in a timely manner during a time of increasing costs and its ability to prevail against legal challenges associated with the Kemper County energy facility. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions. Earnings are subject to a variety of other factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Mississippi Power's service territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings.

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transition rules and cannot be determined at this time, but could have a material impact on Mississippi Power's financial statements.

For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Environmental Matters

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

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 these matters cannot be determined at this time.

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FERC Matters

Municipal and Rural Associations Tariff

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

In March 2016, Mississippi Power reached a settlement agreement with its wholesale customers, which was subsequently approved by the FERC, for an increase in wholesale base revenues under the MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking under the In-Service Asset Rate Order. This regulatory treatment primarily includes (i) recovery of the Kemper IGCC assets currently operational and providing service to customers and other related costs, (ii) 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 June 30, 2017, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $7 million compared to $13 million at December 31, 2016. Over-recovered wholesale MB fuel costs included in the balance sheets were immaterial at June 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, it remains a separate, ongoing matter.

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

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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 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

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. The ultimate outcome of this matter cannot be determined at this time.

Energy Efficiency

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

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 June 30, 2017, the amount of over-recovered retail fuel costs included on the condensed balance sheet was $14 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.

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

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and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed approximately 61 miles of CO₂ pipeline infrastructure for the transport of captured CO₂ for use in enhanced oil recovery.

Kemper IGCC Schedule and Cost Estimate

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

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Mississippi Power's Kemper IGCC 2010 project estimate, cost estimate at the time of project suspension (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 June 30, 2017, all of which include 100% of the costs for the Kemper IGCC, are as follows:



Cost Category	2010 Project Estimate^(a)		Cost Estimate at Suspension^(b)			June 30, 2017 Actual Costs
	(in billions)
Plant Subject to Cost Cap^(c)(e)	$	2.40	$	5.95		$	5.68
Lignite Mine and Equipment	0.21		0.23			0.23
CO₂ Pipeline Facilities	0.14		0.11			0.11
AFUDC^(d)	0.17		0.85			0.85
Combined Cycle and Related Assets Placed in Service – Incremental^(e)	—		0.05			0.05
General Exceptions	0.05		0.10			0.08
Deferred Costs^(e)	—		0.23			0.23
Additional DOE Grants	—		(0.14		)	(0.14		)
Total Kemper IGCC	$	2.97	$	7.38		$	7.09


(a)	Represents the certificated cost estimate adjusted to include the certificated estimate for the CO₂ pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions.


(b)	Represents actual costs through June 30, 2017 and projected costs at the time of project suspension, including estimated post-in-service costs which were 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 Cost Estimate at Suspension 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 Cost Estimate at Suspension 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 included in current rates and are being recognized through income; however, such costs remained in the Cost Estimate at Suspension and are reflected in the Actual Costs at June 30, 2017. The equity return associated with assets placed in service and other non-CWIP accounts deferred for regulatory purposes, as well as the wholesale portion of debt carrying costs, whether deferred or recognized through income, was not included in the Cost Estimate at Suspension or in the Actual Costs at June 30, 2017. At June 30, 2017, such deferred amounts totaled $33 million and $1 million, respectively.

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

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ultimately canceled, additional pre-tax 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 $3.0 billion for the second quarter 2017 and $3.1 billion for the six months ended June 30, 2017.

As of June 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, of which $1.2 billion is included in plant in service, $14 million in materials and supplies, $22 million in other regulatory assets, current, and $95 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 Mississippi Power's results of operations, financial condition, and liquidity.

Kemper IGCC Settlement Docket

On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established the Kemper IGCC Settlement Docket. The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility. The Kemper Settlement Order provides that any related settlement agreement be filed within 45 days from the effective date of the Kemper Settlement Order. If a settlement agreement is filed, a hearing will be set 45 days from the date of the settlement's filing, and the appropriate scheduling order will be established.

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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 is 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 is placed in service. This supplemental filing included approximately $68 million in additional estimated operations and maintenance costs expected to be required to support the operations of the Kemper IGCC during that period.

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

Economic Viability Analysis

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

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

2015 Rate Case

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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. 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 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. With implementation of the new rates on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.

In 2011, the Mississippi PSC authorized Mississippi Power to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date. In connection with the implementation of the In-Service Asset Order and wholesale rates, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs that previously were deferred and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of June 30, 2017, the balance associated with these regulatory assets was $117 million, of which $22 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, with the first occurring as of May 31, 2016. At June 30, 2017, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $10 million.

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

2013 MPSC Rate Order

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

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

Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continued to record AFUDC on the Kemper IGCC. Between the original May 2014 estimated in-service date and the June 2017 project suspension date, Mississippi Power recorded $493 million of AFUDC on the Kemper IGCC subject to the $2.88 billion cost cap and Cost Cap Exception amounts, of which $459 million related to the gasification portions of the Kemper IGCC.

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

Lignite Mine and CO₂ Pipeline Facilities

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

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

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

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

Termination of Proposed Sale of Undivided Interest

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

Litigation

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represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On June 23, 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. On July 7, 2017, the plaintiffs filed notice to appeal to the Court.

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 granted on May 4, 2017. On June 28, 2017, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a claim for arbitration requesting $500 million in damages.

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

Baseload Act

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

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Mississippi Power in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information on bonus depreciation, investment tax credits, and the Section 174 research and experimental deduction.

Bonus Depreciation

Approximately $370 million of positive cash flows is expected to result from bonus depreciation for the 2017 tax year, but may not all be realized in 2017 due to net operating loss projections for the 2017 tax year, and is dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2017. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount previously estimated as bonus depreciation would be claimed as a deduction under IRC Section 165. As of June 30, 2017, $82 million has been received through quarterly income tax refunds for bonus depreciation related to the Kemper IGCC, which may be subject to repayment. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined

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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 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, subject to approval of the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million as of June 30, 2017. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount not allowed under IRC Section 174 would be claimed as a deduction under IRC Section 165, and would result in a reversal of the related unrecognized tax benefits, excluding 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. This matter is expected to be resolved in the next 12 months; however, the ultimate outcome of this matter cannot be determined at this time.

Other Matters

Mississippi Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as 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 Mississippi Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Mississippi Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Mississippi Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Mississippi Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of

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Mississippi Power in Item 7 of the Form 10-K for a complete discussion of Mississippi Power's critical accounting policies and estimates related to Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, AFUDC, Unbilled Revenues, and Contingent Obligations.

Kemper IGCC Rate Recovery

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

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

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Recently Issued Accounting Standards

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

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

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

On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. 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.

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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 six months ended June 30, 2017 were negatively affected by revisions to the cost estimate for the Kemper IGCC.

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

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

Net cash provided from operating activities totaled $135 million for the first six months of 2017, a decrease of $2 million as compared to the corresponding period in 2016. The decrease in cash provided from operating activities is primarily due to lower taxes related to the Kemper IGCC, the timing of payments for ad valorem taxes and materials and supplies, and the timing of payments received from affiliates and customers, partially offset by the completion of Mirror CWIP refunds in 2016. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" herein for additional information. Net cash used for investing activities totaled $361 million for the first six months of 2017 primarily due to gross property additions related to the Kemper IGCC. Net cash provided from financing activities totaled $142 million for the first six months of 2017 primarily due to capital contributions from Southern Company, offset by redemptions of long-term debt. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2017 include an increase in paid-in capital of $1.0 billion due to capital contributions from Southern Company, a portion of which was used to repay $300 million of securities due within one year, $591 million of long-term debt, and $10 million of short-term debt. Long-term debt decreased primarily due to the reclassification of $1.2 billion in unsecured term loans to securities due within one year. Other significant changes include decreases of $2.5 billion in construction work in progress, $1.1 billion in total common stockholder's equity, $352 million in accumulated deferred income taxes, and $300 million in deferred charges related to income taxes. All of these changes primarily result from the Kemper IGCC estimated loss. See 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.

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, scheduled maturities of long-term debt, as well as related interest, leases, purchase commitments, derivative

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obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. Approximately $935 million will be required through June 30, 2018 to fund maturities of long-term debt and $17 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 $561 million for 2017, $192 million for 2018, $182 million for 2019, $235 million for 2020, $199 million for 2021, and $245 million for 2022. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or future state plans that would limit CO₂ emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital.

Sources of Capital

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

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

As of June 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $930 million primarily due to $935 million in long-term debt that matures within the next 12 months and $107 million of short-term debt. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans, as market conditions permit, as well as, under certain circumstances, commercial paper and/or equity contributions and/or loans from Southern Company to fund Mississippi Power's short-term capital needs. Specifically, Mississippi Power has been informed by Southern Company that in the event sufficient funds are not available from external sources, Southern Company intends to provide Mississippi Power with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued

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Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Going Concern" herein.

At June 30, 2017, Mississippi Power had approximately $140 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2017 were as follows:



Expires						Executable Term Loans				Expires Within One Year
2017		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)
$	113	$	113	$	100	$	—	$	13	$	13	$	100

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

Most of these bank credit arrangements, as well as Mississippi Power's term loan agreement, contain covenants that limit debt levels and typically contain cross acceleration to other indebtedness (including guarantee obligations) of Mississippi Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2017, Mississippi Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.

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

A portion of the $100 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2017 was approximately $40 million. In addition, at June 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 June 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	$	17	2.9%	$	29	3.1%	$	36


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

Credit Rating Risk

At June 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.

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

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sales, fuel transportation and storage, energy price risk management, and transmission. At June 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 $243 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.

Financing Activities

In March 2017, Mississippi Power issued a $9 million short-term bank note bearing interest at 5% per annum, which was repaid in April 2017.

In February 2017, Mississippi Power amended $551 million in promissory notes to Southern Company extending the maturity dates of the notes from December 1, 2017 to July 31, 2018. In the second quarter 2017, Mississippi Power borrowed an additional $40 million under a promissory note issued to Southern Company.

In June 2017, Southern Company made equity contributions totaling $1.0 billion to Mississippi Power. Mississippi Power used a portion of the proceeds to (i) prepay $300 million of the outstanding principal amount under its $1.2 billion unsecured term loan, which matures on March 30, 2018; (ii) repay all of the $591 million outstanding principal amount of promissory notes to Southern Company; and (iii) repay a $10 million short-term bank loan.

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AND SUBSIDIARY COMPANIES

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	436		$	264		$	783		$	480
Wholesale revenues, affiliates	90			107			190			204
Other revenues	3			2			6			4
Total operating revenues	529			373			979			688
Operating Expenses:
Fuel	139			96			271			187
Purchased power, non-affiliates	29			21			54			35
Purchased power, affiliates	11			2			16			8
Other operations and maintenance	97			86			190			162
Depreciation and amortization	129			81			247			154
Taxes other than income taxes	12			6			24			13
Total operating expenses	417			292			802			559
Operating Income	112			81			177			129
Other Income and (Expense):
Interest expense, net of amounts capitalized	(48		)	(22		)	(97		)	(43		)
Other income (expense), net	2			1			(2		)	1
Total other income and (expense)	(46		)	(21		)	(99		)	(42		)
Earnings Before Income Taxes	66			60			78			87
Income taxes (benefit)	(38		)	(41		)	(90		)	(65		)
Net Income	104			101			168			152
Less: Net income attributable to noncontrolling interests	22			12			17			13
Net Income Attributable to Southern Power	$	82		$	89		$	151		$	139

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)



	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2017			2016			2017			2016
	(in millions)						(in millions)
Net Income	$	104		$	101		$	168		$	152
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $24, $(15), $20, and $(15), respectively	40			(24		)	32			(24		)
Reclassification adjustment for amounts included in net income, net of tax of $(27), $8, $(30), and $8, respectively	(45		)	13			(48		)	14
Total other comprehensive income (loss)	(5		)	(11		)	(16		)	(10		)
Comprehensive Income	99			90			152			142
Less: Comprehensive income attributable to noncontrolling interests	22			12			17			13
Comprehensive Income Attributable to Southern Power	$	77		$	78		$	135		$	129

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)



	For the Six Months Ended June 30,
	2017			2016
	(in millions)
Operating Activities:
Net income	$	168		$	152
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	264			159
Deferred income taxes	91			(71		)
Amortization of investment tax credits	(28		)	(15		)
Deferred revenues	(34		)	(31		)
Income taxes receivable, non-current	(58		)	—
Other, net	(1		)	9
Changes in certain current assets and liabilities —
-Receivables	(58		)	(76		)
-Prepaid income taxes	33			(147		)
-Other current assets	20			5
-Accounts payable	(45		)	4
-Accrued taxes	4			62
-Other current liabilities	(8		)	—
Net cash provided from operating activities	348			51
Investing Activities:
Business acquisitions	(1,020		)	(502		)
Property additions	(145		)	(1,281		)
Change in construction payables	(167		)	(137		)
Payments pursuant to LTSAs	(68		)	(43		)
Investment in restricted cash	(16		)	(646		)
Distribution of restricted cash	27			649
Other investing activities	(2		)	(25		)
Net cash used for investing activities	(1,391		)	(1,985		)
Financing Activities:
Increase in notes payable, net	189			695
Proceeds —
Senior notes	—			1,241
Capital contributions from parent company	—			300
Distributions to noncontrolling interests	(40		)	(11		)
Capital contributions from noncontrolling interests	73			179
Purchase of membership interests from noncontrolling interests	—			(129		)
Payment of common stock dividends	(158		)	(136		)
Other financing activities	(21		)	(13		)
Net cash provided from financing activities	43			2,126
Net Change in Cash and Cash Equivalents	(1,000		)	192
Cash and Cash Equivalents at Beginning of Period	1,099			830
Cash and Cash Equivalents at End of Period	$	99		$	1,022
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $4 and $21 capitalized for 2017 and 2016, respectively)	$	113		$	42
Income taxes, net	(117		)	115
Noncash transactions — Accrued property additions at end of period	19			108

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

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Assets	At June 30, 2017		At December 31, 2016
	(in millions)
Current Assets:
Cash and cash equivalents	$	99	$	1,099
Receivables —
Customer accounts receivable	158		102
Other accounts receivable	37		34
Affiliated	65		57
Fossil fuel stock	15		15
Materials and supplies	349		337
Prepaid income taxes	41		74
Other current assets	26		39
Total current assets	790		1,757
Property, Plant, and Equipment:
In service	13,731		12,728
Less: Accumulated provision for depreciation	1,689		1,484
Plant in service, net of depreciation	12,042		11,244
Construction work in progress	344		398
Total property, plant, and equipment	12,386		11,642
Other Property and Investments:
Intangible assets, net of amortization of $35 and $22 at June 30, 2017 and December 31, 2016, respectively	423		436
Total other property and investments	423		436
Deferred Charges and Other Assets:
Prepaid LTSAs	61		101
Accumulated deferred income taxes	536		594
Income taxes receivable, non-current	69		11
Other deferred charges and assets — affiliated	28		13
Other deferred charges and assets — non-affiliated	410		615
Total deferred charges and other assets	1,104		1,334
Total Assets	$	14,703	$	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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Liabilities and Stockholders' Equity	At June 30, 2017		At December 31, 2016
	(in millions)
Current Liabilities:
Securities due within one year	$	909	$	560
Notes payable	398		209
Accounts payable —
Affiliated	68		88
Other	93		278
Accrued taxes —
Accrued income taxes	35		148
Other accrued taxes	21		7
Accrued interest	25		36
Acquisitions payable	—		461
Contingent consideration	11		46
Other current liabilities	67		70
Total current liabilities	1,627		1,903
Long-term Debt	4,816		5,068
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	174		152
Accumulated deferred ITCs	1,914		1,839
Asset retirement obligations	69		64
Other deferred credits and liabilities	238		304
Total deferred credits and other liabilities	2,395		2,359
Total Liabilities	8,838		9,330
Redeemable Noncontrolling Interests	51		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
Retained earnings	717		724
Accumulated other comprehensive income	19		35
Total common stockholder's equity	4,407		4,430
Noncontrolling interests	1,407		1,245
Total stockholders' equity	5,814		5,675
Total Liabilities and Stockholders' Equity	$	14,703	$	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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SECOND QUARTER 2017 vs. SECOND 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. 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 six months ended June 30, 2017, Southern Power acquired or completed the construction of, and placed in service, approximately 498 MWs of solar and wind facilities. In addition, Southern Power continued developing its portfolio of wind projects as well as the construction to expand the Mankato natural gas facility by 345 MWs of capacity. Subsequent to June 30, 2017, Southern Power acquired and commenced construction of Cactus Flats, a 148-MW wind facility. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.

At June 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

Net income attributable to Southern Power for the second quarter 2017 was $82 million compared to $89 million for the corresponding period in 2016. The decrease was primarily due to increased interest expense from debt issuances to fund acquisitions and construction and an increase in net income attributable to noncontrolling interests, significantly offset by additional operating income related to new generating facilities.

Net income attributable to Southern Power for year-to-date 2017 was $151 million compared to $139 million for the corresponding period in 2016. The increase was primarily due to additional operating income from new generating facilities, as well as increased federal income tax benefits from wind PTCs, partially offset by increased interest expense from debt issuances to fund acquisitions and construction. 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 "Construction Projects" of Southern Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein.

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Operating Revenues

Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas and biomass generating facilities, and PPA energy revenues, which include sales from Southern Power's natural gas, biomass, solar, and wind facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into the wholesale market and, to the extent the generation assets are part of the IIC, as approved by the FERC, it may sell power into the power pool.

Natural Gas and Biomass Capacity and Energy Revenue

Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment.

Energy is generally sold at variable cost or is indexed to published gas indices. Energy revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.

Solar and Wind Energy Revenue

Southern Power's electricity 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 sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, and other factors.

See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein for additional information regarding Southern Power's PPAs.

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



	Second Quarter 2017		Second Quarter 2016		Year-to-Date 2017		Year-to-Date 2016
	(in millions)
PPA capacity revenues	$	149	$	133	$	298	$	258
PPA energy revenues	270		168		466		285
Total PPA revenues	419		301		764		543
Non-PPA revenues	107		70		209		141
Other revenues	3		2		6		4
Total operating revenues	$	529	$	373	$	979	$	688

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In the second quarter 2017, total operating revenues were $529 million, reflecting a $156 million, or 42%, increase from the corresponding period in 2016. The increase in operating revenues was primarily due to the following:


•	PPA capacity revenues increased $16 million, or 12%, primarily due to new PPAs related to natural gas facilities and additional customer load requirements.


•	PPA energy revenues increased $102 million, or 61%, primarily due to an $85 million increase in sales from new solar and wind facilities and a $20 million increase in sales from new natural gas PPAs and additional customer load requirements.


•	Non-PPA revenues increased $37 million, or 53%, due to a $23 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, as well as a $14 million increase in the price of energy primarily due to increased natural gas prices.

For year-to-date 2017, total operating revenues were $979 million, reflecting a $291 million, or 42%, increase from the corresponding period in 2016. The increase in operating revenues was primarily due to the following:


•	PPA capacity revenues increased $40 million, or 16%, primarily due to new PPAs related to natural gas facilities and additional customer load requirements.


•	PPA energy revenues increased $181 million, or 64%, primarily due to a $137 million increase in sales from new solar and wind facilities and a $37 million increase in sales from new natural gas PPAs and additional customer load requirements.


•	Non-PPA revenues increased $68 million, or 48%, due to a $48 million increase in the volume of KWHs sold primarily from uncovered natural gas capacity through short-term opportunity sales, as well as a $20 million increase in the price of energy primarily due to increased natural gas prices.

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:



	Second Quarter 2017	Second Quarter 2016	Year-to-Date 2017	Year-to-Date 2016
	(in billions of KWHs)
Generation	10.9	9.1	20.6	16.7
Purchased power	1.2	0.9	2.2	1.5
Total generation and purchased power	12.1	10.0	22.8	18.2

Total generation and purchased power, excluding solar, wind, and tolling agreements	5.6	5.7	10.5	11.0

Southern Power's PPAs for natural gas and biomass generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the power pool for capacity owned directly by Southern Power.

Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by

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Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.

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



	Second Quarter 2017 vs. Second Quarter 2016			Year-to-Date 2017 vs. Year-to-Date 2016
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	43	44.8	$	84	44.9
Purchased power	17		73.9	27		62.8
Total fuel and purchased power expenses	$	60		$	111

In the second quarter 2017, total fuel and purchased power expenses increased $60 million, or 50.4%, compared to the corresponding period in 2016. Fuel expense increased $43 million primarily due to a $51 million increase in the average cost of natural gas per KWH generated, partially offset by an $8 million decrease in the volume of KWHs generated, excluding solar, wind, and tolling agreements. Purchased power expense increased $17 million primarily due to a $10 million increase in the volume of KWHs purchased and a $6 million increase associated with the average cost of purchased power.

For year-to-date 2017, total fuel and purchased power expenses increased $111 million, or 48.3%, compared to the corresponding period in 2016. Fuel expense increased $84 million primarily due to a $105 million increase in the average cost of natural gas per KWH generated, partially offset by a $22 million decrease in the volume of KWHs generated, excluding solar, wind, and tolling agreements. Purchased power expense increased $27 million due to a $19 million increase in the volume of KWHs purchased and an $8 million increase associated with the average cost of purchased power.

Other Operations and Maintenance Expenses

In the second quarter 2017, other operations and maintenance expenses were $97 million compared to $86 million for the corresponding period in 2016. The increase was primarily due to a $19 million increase associated with new solar, wind, and gas facilities and a $5 million increase associated with employee compensation and expenses in support of Southern Power's overall growth strategy, partially offset by a $9 million decrease in scheduled outage maintenance expenses and a $5 million decrease in non-outage operations and maintenance expenses.

For year-to-date 2017, other operations and maintenance expenses were $190 million compared to $162 million for the corresponding period in 2016. The increase was primarily due to a $35 million increase associated with new solar, wind, and gas facilities and a $10 million increase associated with employee compensation and expenses in support of Southern Power's overall growth strategy, partially offset by a $16 million decrease in scheduled outage maintenance expenses and a $4 million decrease in non-outage operations and maintenance expenses.

Depreciation and Amortization

In the second quarter 2017, depreciation and amortization was $129 million compared to $81 million for the corresponding period in 2016. For year-to-date 2017, depreciation and amortization was $247 million compared to

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$154 million for the corresponding period in 2016. The increases were primarily due to new solar, wind, and gas facilities placed in service.

Interest Expense, net of Amounts Capitalized

In the second quarter 2017, interest expense, net of amounts capitalized was $48 million compared to $22 million for the corresponding period in 2016. The increase was primarily due to an increase of $16 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 a $9 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities.

For year-to-date 2017, interest expense, net of amounts capitalized was $97 million compared to $43 million for the corresponding period in 2016. The increase was primarily due to an increase of $36 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 a $17 million decrease in capitalized interest associated with completing construction of and placing in service solar facilities.

Other Income (Expense), Net

In the second quarter 2017, other income (expense), net was $2 million compared to $1 million for the corresponding period in 2016. For year-to-date 2017, other income (expense), net was $(2) million compared to $1 million for the corresponding period in 2016. The changes include increases of $99 million and $116 million from currency losses arising from translation of €1.1 billion euro-denominated fixed-rate notes into U.S. dollars for the second 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.

Income Taxes (Benefit)

In the second quarter 2017, income tax benefit was $38 million compared to $41 million for the corresponding period in 2016. The decrease was primarily due to a $29 million decrease in ITC benefits, partially offset by a $27 million increase in wind PTC benefits.

For year-to-date 2017, income tax benefit was $90 million compared to $65 million for the corresponding period in 2016. The increase was primarily due to a $57 million increase in wind PTC benefits, a $4 million increase resulting from state apportionment rate changes, and a $4 million increase related to lower pre-tax earnings, partially offset by a $41 million decrease in ITC benefits.

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.

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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.

Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, as well as renewable portfolio standards, which may impact future earnings.

Other factors that could influence future earnings include weather, demand, cost of generation from facilities within the power pool, and operational limitations. For additional information relating to these factors, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.

Power Sales Agreements

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

At June 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.

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.

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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 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.

Acquisitions

During the six months ended June 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. Acquisition-related costs were expensed as incurred and were not material. See Note (I) to the Condensed Financial Statements under "Southern Power" herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for additional information.



Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Percentage Ownership		Actual COD	PPA Counterparties	PPA Contract Period
Bethel	Wind	276	Castro County, TX	100	%	January 2017	Google Energy, LLC	12 years

The aggregate amounts of revenue and net income, excluding impacts from PTCs, recognized by Southern Power related to the Bethel facility included in the condensed consolidated statements of income for year-to-date 2017 were immaterial. The Bethel facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service; therefore, supplemental pro forma information for the comparable 2016 period is not meaningful and has been omitted.

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2033. The facility is expected to be placed in service in mid-2018. The ultimate outcome of this matter cannot be determined at this time.

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 six months ended June 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 June 30, 2017, total costs of construction incurred for these projects were $421 million, of which $49 million remained in CWIP for the Mankato facility acquired in 2016. Total aggregate construction costs, excluding the acquisition costs, are expected to be $170 million to $190 million for the Mankato facility. The ultimate outcome of this matter cannot be determined at this time.



Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Counterparties	PPA Contract Period
Projects Completed During the Six Months Ended June 30, 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

Project Under Construction as of June 30, 2017
Mankato	Natural Gas	345	Mankato, MN	Second quarter 2019	Northern States Power Company	20 years

Development Projects

In December 2016, as part of Southern Power's renewable development strategy, SRP 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

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U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

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

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 lawsuit against Roserock, Array Technologies, Inc., Canadian Solar (USA), Inc., XL, and North American Elite in the U.S. District Court for the Western District of Texas alleging, among other things, breach of contract, and requesting foreclosure of mechanic's liens against Roserock. On July 18, 2017, the U.S. District Court for the Western District of Texas consolidated the two pending lawsuits. Southern Power intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Power prepares its consolidated financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Power in Item 7 of the Form 10-K for a complete discussion of Southern Power's critical accounting policies and estimates related to Revenue Recognition, Impairment of Long-Lived Assets and Intangibles, Acquisition Accounting, and ITCs.

Recently Issued Accounting Standards

While Southern Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. However, given Southern Power's core activities of selling

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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 related contracts includes the evaluation of identified revenue streams tied to longer-term contractual arrangements, such as certain capacity and energy payments under PPAs that are expected to be excluded from the scope of ASC 606 and included in the scope of the current leasing guidance (ASC 840).

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

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

Net cash provided from operating activities totaled $348 million for the first six months of 2017 compared to $51 million for the first six months of 2016. The increase in net cash provided from operating activities was primarily due to an increase in 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 $1.4 billion for the first six months of 2017 primarily due to payments for renewable acquisitions and the construction of generating facilities. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information. Net cash provided from financing activities totaled $43 million for the first six months of 2017 primarily due to notes payable and contributions from noncontrolling interests, partially offset by dividends to Southern Company and distributions to noncontrolling interests. Cash flows from financing activities may vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2017 include a $1.0 billion decrease in cash and cash equivalents and a $798 million increase in property, plant, and equipment in-service primarily related to acquisitions, as well as a $54 million decrease in CWIP primarily due to East Pecos and Lamesa being placed in service, partially offset by equipment purchased for wind construction projects. 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

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commitments. Approximately $909 million will be required to repay maturities of long-term debt through June 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, 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 June 30, 2017, Southern Power's current liabilities exceeded current assets by $837 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 June 30, 2017, Southern Power had cash and cash equivalents of approximately $99 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, and operating cash flows.

Southern Power's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities, for general corporate purposes, and to finance maturing debt. Commercial paper is included in notes payable on the condensed consolidated balance sheet at June 30, 2017.

Details of commercial paper were as follows:



	Short-term Debt at June 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	$	398	1.5	%	$	328	1.3	%	$	419


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

At June 30, 2017, Southern Power had a committed credit facility (Facility) of $750 million, of which $75 million has been used for letters of credit and $675 million remains unused. In May 2017, Southern Power amended the Facility, which, among other things, extended the maturity date from 2020 to 2022 and increased Southern Power's borrowing ability under this Facility to $750 million from $600 million. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. Subject to applicable market conditions, Southern Power expects to renew or replace the Facility, as

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needed, prior to expiration. In connection therewith, Southern Power may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements of Southern Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

The Facility, as well as Southern Power's term loan agreement, contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 65% and contains a cross-default provision that is restricted only to indebtedness of Southern Power. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of Southern Power to the extent such debt is non-recourse to Southern Power, and capitalization excludes the capital stock or other equity attributable to such subsidiary. Southern Power is currently in compliance with all covenants in the Facility.

In December 2016, Southern Power entered into an agreement for a $120 million continuing letter of credit facility for standby letters of credit expiring in 2019. At June 30, 2017, the total amount available under this letter of credit facility was $62 million.

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

Credit Rating Risk

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

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

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



Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	38
At BBB- and/or Baa3	$	392
At BB+ and/or Ba1^(*)	$	1,127


(*)	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

Southern Power did not issue or redeem any securities during the six months ended June 30, 2017.

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In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)



	Successor			Predecessor			Successor			Predecessor
	For the Three Months Ended June 30,			For the Three Months Ended June 30,			For the Six Months Ended June 30,			For the Six Months Ended June 30,
	2017			2016			2017			2016
	(in millions)			(in millions)			(in millions)			(in millions)
Operating Revenues:
Natural gas revenues (includes revenue taxes of $19, $17, $67, and $57 for the periods presented, respectively)	$	684		$	539		$	2,214		$	1,841
Other revenues	32			32			62			64
Total operating revenues	716			571			2,276			1,905
Operating Expenses:
Cost of natural gas	232			184			951			755
Cost of other sales	6			7			13			14
Other operations and maintenance	213			213			467			454
Depreciation and amortization	125			104			244			206
Taxes other than income taxes	44			37			114			99
Merger-related expenses	—			53			—			56
Total operating expenses	620			598			1,789			1,584
Operating Income (Loss)	96			(27		)	487			321
Other Income and (Expense):
Earnings from equity method investments	29			1			68			2
Interest expense, net of amounts capitalized	(48		)	(48		)	(94		)	(96		)
Other income (expense), net	3			2			7			5
Total other income and (expense)	(16		)	(45		)	(19		)	(89		)
Earnings (Loss) Before Income Taxes	80			(72		)	468			232
Income taxes (benefit)	31			(24		)	180			87
Net Income (Loss)	49			(48		)	288			145
Less: Net income attributable to noncontrolling interest	—			3			—			14
Net Income (Loss) Attributable to Southern Company Gas	$	49		$	(51	)	$	288		$	131

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

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)



	Successor			Predecessor			Successor			Predecessor
	For the Three Months Ended June 30,			For the Three Months Ended June 30,			For the Six Months Ended June 30,			For the Six Months Ended June 30,
	2017			2016			2017			2016
	(in millions)			(in millions)			(in millions)			(in millions)
Net Income (Loss)	$	49		$	(48	)	$	288		$	145
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1), $(7), $(2), and $(23), respectively	(1		)	(12		)	(2		)	(41		)
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $-, and $-, respectively	—			2			—			1
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $-, $2, $-, and $4, respectively	—			2			(1		)	5
Total other comprehensive income (loss)	(1		)	(8		)	(3		)	(35		)
Comprehensive Income (Loss)	48			(56		)	285			110
Less: Comprehensive income attributable to noncontrolling interest	—			3			—			14
Comprehensive Income (Loss) Attributable to Southern Company Gas	$	48		$	(59	)	$	285		$	96

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)



	Successor			Predecessor
	For the Six Months Ended June 30,			For the Six Months Ended June 30,
	2017			2016
	(in millions)			(in millions)
Operating Activities:
Net income	$	288		$	145
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	244			206
Deferred income taxes	144			8
Stock based compensation expense	19			20
Hedge settlements	—			(26		)
Mark-to-market adjustments	(49		)	162
Other, net	(53		)	(77		)
Changes in certain current assets and liabilities —
-Receivables	420			181
-Natural gas for sale, net of temporary LIFO liquidation	223			273
-Prepaid income taxes	24			151
-Other current assets	(12		)	37
-Accounts payable	(102		)	43
-Accrued taxes	(8		)	41
-Accrued compensation	(12		)	(21		)
-Other current liabilities	25			(30		)
Net cash provided from operating activities	1,151			1,113
Investing Activities:
Property additions	(684		)	(509		)
Cost of removal, net of salvage	(25		)	(32		)
Change in construction payables, net	23			(7		)
Investment in unconsolidated subsidiaries	(111		)	(14		)
Other investing activities	16			3
Net cash used for investing activities	(781		)	(559		)
Financing Activities:
Decrease in notes payable, net	(631		)	(896		)
Proceeds —
First mortgage bonds	—			250
Capital contributions from parent company	57			—
Senior notes	450			350
Redemptions and repurchases — First mortgage bonds	—			(125		)
Distributions to noncontrolling interest	—			(19		)
Payment of common stock dividends	(221		)	(128		)
Other financing activities	(6		)	10
Net cash used for financing activities	(351		)	(558		)
Net Change in Cash and Cash Equivalents	19			(4		)
Cash and Cash Equivalents at Beginning of Period	19			19
Cash and Cash Equivalents at End of Period	$	38		$	15
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $7 and $3 capitalized for 2017 and 2016, respectively)	$	105		$	119
Income taxes, net	20			(100		)
Noncash transactions — Accrued property additions at end of period	84			41

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)



Assets	At June 30, 2017			At December 31, 2016
	(in millions)
Current Assets:
Cash and cash equivalents	$	38		$	19
Receivables —
Energy marketing receivables	482			623
Customer accounts receivable	270			364
Unbilled revenues	69			239
Other accounts and notes receivable	63			76
Accumulated provision for uncollectible accounts	(35		)	(27		)
Materials and supplies	24			26
Natural gas for sale	477			631
Prepaid expenses	69			80
Assets from risk management activities, net of collateral	114			128
Other regulatory assets, current	72			81
Other current assets	20			10
Total current assets	1,663			2,250
Property, Plant, and Equipment:
In service	14,850			14,508
Less: Accumulated depreciation	4,550			4,439
Plant in service, net of depreciation	10,300			10,069
Construction work in progress	779			496
Total property, plant, and equipment	11,079			10,565
Other Property and Investments:
Goodwill	5,967			5,967
Equity investments in unconsolidated subsidiaries	1,610			1,541
Other intangible assets, net of amortization of $80 and $34 at June 30, 2017 and December 31, 2016, respectively	320			366
Miscellaneous property and investments	21			21
Total other property and investments	7,918			7,895
Deferred Charges and Other Assets:
Other regulatory assets, deferred	963			973
Other deferred charges and assets	186			170
Total deferred charges and other assets	1,149			1,143
Total Assets	$	21,809		$	21,853

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)



Liabilities and Stockholder's Equity	At June 30, 2017		At December 31, 2016
	(in millions)
Current Liabilities:
Securities due within one year	$	22	$	22
Notes payable	626		1,257
Energy marketing trade payables	534		597
Accounts payable	327		348
Customer deposits	134		153
Accrued taxes —
Accrued income taxes	23		26
Other accrued taxes	63		68
Accrued interest	50		48
Accrued compensation	45		58
Liabilities from risk management activities, net of collateral	20		62
Other regulatory liabilities, current	146		102
Accrued environmental remediation, current	63		69
Temporary LIFO liquidation	69		—
Other current liabilities	113		108
Total current liabilities	2,235		2,918
Long-term Debt	5,677		5,259
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	2,091		1,975
Employee benefit obligations	432		441
Other cost of removal obligations	1,638		1,616
Accrued environmental remediation, deferred	353		357
Other regulatory liabilities, deferred	50		51
Other deferred credits and liabilities	91		127
Total deferred credits and other liabilities	4,655		4,567
Total Liabilities	12,567		12,744
Common Stockholder's Equity:
Common stock, par value $0.01 per share —
Authorized — 100 million shares
Outstanding — 100 shares	—		—
Paid in capital	9,164		9,095
Retained earnings (accumulated deficit)	55		(12		)
Accumulated other comprehensive income	23		26
Total common stockholder's equity	9,242		9,109
Total Liabilities and Stockholder's Equity	$	21,809	$	21,853

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

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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 constructive regulatory environments, to maintain and grow natural gas sales, and to effectively manage and secure timely recovery of costs. Southern Company Gas has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Southern Company Gas for the foreseeable future.

Merger and Acquisition Activities

On July 1, 2016, Southern Company Gas completed the Merger, which was accounted for by Southern Company using the acquisition method of accounting whereby the assets acquired and liabilities assumed were recognized at fair value as of the acquisition date. Pushdown accounting was applied to create a new cost basis for Southern Company Gas assets, liabilities, and equity as of the acquisition date. Accordingly, the successor financial statements reflect a new basis of accounting and successor and predecessor period financial results (separated by a heavy black line) are presented, but are not comparable. As a result of the application of acquisition accounting, certain discussions herein include disclosure of the predecessor and successor periods. See Note (I) to the Condensed Financial Statements herein for additional information relating to the Merger.

In September 2016, Southern Company Gas paid approximately $1.4 billion to acquire a 50% equity interest in SNG. On March 31, 2017, Southern Company Gas made an additional $50 million contribution to maintain its 50% equity interest in SNG. Southern Company Gas recorded equity investment income of $24 million and $58 million from this investment in the second quarter and year-to-date 2017, respectively. See Note (J) to the Condensed Financial Statements herein and Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K for additional information.

In October 2016, Southern Company Gas completed its purchase of Piedmont's 15% interest in SouthStar, which eliminated the noncontrolling interest associated with SouthStar. See Note 4 to the financial statements of Southern Company Gas under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.

Operating Metrics

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

Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. With the exception of Southern Company Gas' utilities in Illinois and Florida, Southern Company Gas has various regulatory mechanisms, such as weather normalization mechanisms, which limit its exposure to weather changes within typical ranges in each of its utilities' respective service territory. However, the utility customers in Illinois and the gas marketing services customers primarily in Georgia 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

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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 number of customers at gas distribution operations and energy customers at gas marketing services can be impacted by natural gas prices, economic conditions, and competition from alternative fuels. Gas marketing services' customers are primarily located in Georgia and Illinois.

Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas. Wholesale gas services' physical sales volumes represent the daily average natural gas volumes sold to its customers.

Seasonality of Results

During the months of November through March, 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 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

Net income attributable to Southern Company Gas for the successor second quarter 2017 and net loss attributable to Southern Company Gas for the predecessor second quarter 2016 were $49 million and $51 million, respectively. Net income attributable to Southern Company Gas for the successor year-to-date 2017 and the predecessor year-to-date 2016 was $288 million and $131 million, respectively.

As a result of purchasing the remaining interest in SouthStar in October 2016, all net income was attributable to Southern Company Gas in the successor period. Net income for the successor second quarter 2017 was negatively impacted by $5 million due to the pushdown of acquisition accounting related to the Merger and included $10 million in after-tax earnings from the SNG investment, net of related interest expense. Also reflected in net income was an increase of $12 million, after tax, from additional infrastructure replacement programs at gas distribution operations, net of increased depreciation and a base rate increase at Atlanta Gas Light effective March 1, 2017. The successor second quarter 2017 also included $11 million in after-tax losses from commercial activity and $8 million in after-tax mark-to-market gains at wholesale gas services.

Net loss attributable to Southern Company Gas for the predecessor second quarter 2016 included $39 million in after-tax Merger-related expenses, as well as $5 million in after-tax losses from commercial activity at wholesale gas services and $50 million in net after-tax mark-to-market losses at wholesale gas services and gas marketing services due to changes in natural gas price volatility in the period.

Net income attributable to Southern Company Gas for the successor year-to-date 2017 was negatively impacted by $2 million due to the pushdown of acquisition accounting related to the Merger and included $25 million in after-tax earnings from the SNG investment, net of related interest expense. The successor year-to-date 2017 included an increase of $19 million, after tax, from additional infrastructure replacement programs at gas distribution operations, net of increased depreciation and a base rate increase at Atlanta Gas Light effective March 1, 2017. The successor year-to-date 2017 also included $41 million in after-tax gains from commercial activity at wholesale gas services, $27 million in net after-tax mark-to-market gains at wholesale gas services and gas marketing services, and a reduction of $9 million, after tax, resulting from warmer-than-normal weather, net of hedging.

Net income attributable to Southern Company Gas for the predecessor year-to-date 2016 included $41 million in after-tax Merger-related expenses and $21 million in after-tax mark-to-market gains from commercial activity at

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wholesale gas services. Also reflected in net income was $38 million in net after-tax mark-to-market losses at wholesale gas services and gas marketing services and a decrease of $5 million, after tax, resulting from warmer-than-normal weather, net of hedging.

Natural Gas Revenues

Natural gas revenues for the successor second quarter 2017 and the predecessor second quarter 2016 were $684 million and $539 million, respectively. Natural gas revenues for the successor year-to-date 2017 and the predecessor year-to-date 2016 were $2.2 billion and $1.8 billion, respectively.

Natural gas revenues for the successor second quarter 2017 included recovery of $232 million in cost of natural gas and $12 million in net losses from wholesale gas services. Also included in natural gas revenues were $26 million in additional revenues generated from gas distribution operations as a result of continued investment in infrastructure replacement programs and a $2 million decrease attributable to warmer-than-normal weather, net of hedging.

Natural gas revenues for the predecessor second quarter 2016 reflected recovery of $184 million in cost of natural gas and $95 million in net losses from wholesale gas services, primarily due to mark-to-market losses on storage, transportation, and forward commodity derivatives.

Natural gas revenues for the successor year-to-date 2017 included recovery of $951 million in cost of natural gas and $119 million in net revenues from wholesale gas services. Also included in natural gas revenues was $45 million in additional revenues generated from gas distribution operations as a result of continued investment in infrastructure replacement programs and a $15 million decrease attributable to warmer-than-normal weather, net of hedging.

Natural gas revenues for the predecessor year-to-date 2016 reflected recovery of $755 million in cost of natural gas and $32 million in net losses from wholesale gas services. Also included in natural gas revenues was a $7 million decrease attributable to warmer-than-normal weather, net of hedging.

See "Segment Information" herein for additional information on wholesale gas services' revenues and losses.

Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, recoverable natural gas revenues generally equal the cost of natural gas and do not affect net income from gas distribution operations. See "Cost of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.

Heating Season is the period from November through March when 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.



	Second Quarter			2017 vs. 2016		2017 vs. normal		Year-to-Date			2017 vs. 2016		2017 vs. normal
	Normal^(a)	2017	2016	(warmer)		(warmer)		Normal^(a)	2017	2016	(warmer)		(warmer)
Illinois^(b)	639	555	639	(13	)%	(13	)%	3,760	3,110	3,340	(7	)%	(17	)%
Georgia	137	75	114	(34	)%	(45	)%	1,636	1,000	1,448	(31	)%	(39	)%


(a)	Normal represents the 10-year average from January 1, 2007 through June 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 617 for the second quarter and 3,519 for the first six months from 1998 through 2007.

For the successor second quarter 2017 and the predecessor second quarter 2016, the weather-related negative pre-tax income impact was limited to $2 million in each period.

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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 $5 million ($3 million after tax) and $7 million ($5 million after tax) for the successor year-to-date 2017 and the predecessor year-to-date 2016, respectively. Southern Company Gas also hedged its exposure at gas marketing services to warmer-than-normal weather in Georgia; therefore, the weather-related negative pre-tax income impact on gas marketing services was limited to $10 million ($6 million after tax) for the successor year-to-date 2017 and there was no impact for the predecessor year-to-date 2016.

The following table provides the number of customers served by Southern Company Gas at June 30, 2017 and 2016:



	June 30,
	2017		2016		2017 vs. 2016
	(in thousands, except market share %)				(% change)
Gas distribution operations	4,573		4,544		0.6	%
Gas marketing services
Energy customers^(*)	768		630		21.9	%
Market share of energy customers in Georgia	29.1	%	29.3	%
Service contracts	1,188		1,197		(0.8	)%


(*)	Includes approximately 140,000 customers as of June 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 in 2017, as it expects continued improvement in the new housing market and low natural gas prices.

Gas marketing services' market share in Georgia decreased slightly at June 30, 2017 compared to June 30, 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

Cost of natural gas was $232 million for the successor second quarter 2017 and $184 million for the predecessor second quarter 2016, which primarily reflected an increase of 63% in natural gas prices during the successor second quarter 2017 compared to the corresponding period in 2016, partially offset by lower demand for natural gas driven by warmer-than-normal weather.

Cost of natural gas was $951 million for the successor year-to-date 2017 and $755 million for the predecessor year-to-date 2016, which primarily reflected an increase of 61% in natural gas prices during the successor 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. 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.



	Second Quarter		2017 vs. 2016		Year-to-Date		2017 vs. 2016
	2017	2016	% Change		2017	2016	% Change
Gas distribution operations (mmBtu in millions)
Firm	102	107	(4.7	)%	365	396	(7.8	)%
Interruptible	23	22	4.5	%	48	49	(2.0	)%
Total	125	129	(3.1	)%	413	445	(7.2	)%
Gas marketing services (mmBtu in millions)
Firm:
Georgia	4	4	—	%	17	21	(19.0	)%
Illinois	2	2	—	%	7	8	(12.5	)%
Other emerging markets	3	2	50.0	%	8	7	14.3	%
Interruptible:
Large commercial and industrial	3	4	(25.0	)%	7	8	(12.5	)%
Total	12	12	—	%	39	44	(11.4	)%
Wholesale gas services (mmBtu in millions/day)
Daily physical sales	6.2	7.2	(13.9	)%	6.4	7.6	(15.8	)%

Other Operations and Maintenance Expenses

Other operations and maintenance expenses were $213 million for both the successor second quarter 2017 and the predecessor second quarter 2016.

Other operations and maintenance expenses were $467 million for the successor year-to-date 2017 and $454 million for the predecessor year-to-date 2016. Other operations and maintenance expense for the successor year-to-date period reflected increased compensation expenses and pipeline and maintenance expenses, partially offset by low bad debt expense.

Depreciation and Amortization

Depreciation and amortization was $125 million for the successor second quarter 2017 and $104 million for the predecessor second quarter 2016. The successor second quarter 2017 included $9 million of additional net amortization of intangible assets as a result of fair value adjustments in acquisition accounting at gas midstream operations and gas distribution operations, as well as $7 million in additional depreciation at gas distribution operations due to a $1.1 billion increase in gross property, plant, and equipment since June 30, 2016.

Depreciation and amortization was $244 million for the successor year-to-date 2017 and $206 million for the predecessor year-to-date 2016. The successor year-to-date 2017 included $19 million of additional net amortization of intangible assets as a result of fair value adjustments in acquisition accounting at gas midstream operations and gas distribution operations, as well as $13 million in additional depreciation at gas distribution operations due to additional assets placed in service.

Taxes Other Than Income Taxes

For the successor second quarter 2017 and the predecessor second quarter 2016, taxes other than income taxes were $44 million and $37 million, respectively. For the successor year-to-date 2017 and the predecessor year-to-date

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2016, taxes other than income taxes were $114 million and $99 million, respectively. Taxes other than income taxes consist primarily of revenue tax expenses, property taxes, and payroll taxes. Taxes other than income taxes in the successor periods reflected increased revenue-based taxes due to higher revenues at gas distribution operations.

Earnings from Equity Method Investments

For the successor second quarter 2017, earnings from equity method investments were $29 million, which consisted of $24 million in earnings from SNG and $5 million in earnings from all other investments. For the predecessor second quarter 2016, earnings from equity method investments were not material.

For the successor year-to-date 2017, earnings from equity method investments were $68 million, which consisted of $58 million in earnings from SNG and $10 million in earnings from all other investments. For the predecessor year-to-date 2016, earnings from equity method investments were not material.

See Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K and Note (J) to the Condensed Financial Statements under "Southern Company Gas – Equity Method Investments" herein for additional information.

Interest Expense, Net of Amounts Capitalized

For both the successor second quarter 2017 and the predecessor second quarter 2016, interest expense, net of amounts capitalized was $48 million. The successor second quarter 2017 reflects a $10 million reduction resulting from the fair value adjustment of long-term debt in acquisition accounting, partially offset by $6 million of additional interest expense on new debt issuances in 2017 and 2016.

For the successor year-to-date 2017 and the predecessor year-to-date 2016, interest expense, net of amounts capitalized was $94 million and $96 million, respectively. The successor year-to-date 2017 reflects a $19 million reduction resulting from the fair value adjustment of long-term debt in acquisition accounting, partially offset by $12 million of additional interest expense on new debt issuances in 2017 and 2016.

Income Taxes (Benefit)

For the successor second quarter 2017 and the predecessor second quarter 2016, income taxes (benefit) were $31 million and $(24) million, respectively, driven by pre-tax earnings.

For the successor year-to-date 2017 and the predecessor year-to-date 2016, income taxes were $180 million and $87 million, respectively, driven by pre-tax earnings and the non-deductibility of certain Merger-related expenses.

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 (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 second quarter and 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 second quarter and 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 are provided herein.

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Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues minus cost of natural gas, cost of other sales, and revenue tax expense. Adjusted operating margin excludes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, and Merger-related expenses, which are included in the calculation of operating income as calculated in accordance with GAAP and reflected in the consolidated statements of income. The presentation of adjusted operating margin is believed to provide useful information regarding the contribution resulting from customer growth at gas distribution operations since the cost of natural gas and revenue tax expense can vary significantly and are generally billed directly to customers. Southern Company Gas further believes that utilizing adjusted operating margin at gas marketing services, wholesale gas services, and gas midstream operations allows it to focus on a direct measure of adjusted operating margin before overhead costs. The applicable reconciliation of operating income to adjusted operating margin is provided herein.

EBIT and adjusted operating margin should not be considered alternatives to, or more meaningful indicators of, Southern Company Gas' operating performance than consolidated net income attributable to Southern Company Gas or operating income as determined in accordance with GAAP. In addition, Southern Company Gas' adjusted operating margin may not be comparable to similarly titled measures of other companies.



	Successor			Predecessor			Successor			Predecessor
	Second Quarter 2017			Second Quarter 2016			Year-to-Date 2017			Year-to-Date 2016
	(in millions)			(in millions)			(in millions)			(in millions)
Operating Income	$	96		$	(27	)	$	487		$	321
Other operating expenses^(a)	382			407			825			815
Revenue taxes^(b)	(18		)	(17		)	(65		)	(56		)
Adjusted Operating Margin	$	460		$	363		$	1,247		$	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.



	Successor		Predecessor			Successor		Predecessor
	Second Quarter 2017		Second Quarter 2016			Year-to-Date 2017		Year-to-Date 2016
	(in millions)		(in millions)			(in millions)		(in millions)
Consolidated Net Income (Loss) Attributable to Southern Company Gas	$	49	$	(51	)	$	288	$	131
Net income attributable to noncontrolling interest ^(*)	—		3			—		14
Income taxes	31		(24		)	180		87
Interest expense, net of amounts capitalized	48		48			94		96
EBIT	$	128	$	(24	)	$	562	$	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.

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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
	Second Quarter 2017									Second Quarter 2016
	Adjusted Operating			Operating			Net			Adjusted Operating			Operating
	Margin^(*)			Expenses^(*)			Income			Margin^(*)			Expenses^(*)			EBIT
	(in millions)									(in millions)
Gas distribution operations	$	409		$	283		$	54		$	386		$	269		$	118
Gas marketing services	57			48			4			66			37			29
Wholesale gas services	(13		)	14			(17		)	(96		)	16			(112		)
Gas midstream operations	7			13			9			6			12			(5		)
All other	3			9			(1		)	2			58			(55		)
Intercompany eliminations	(3		)	(3		)	—			(1		)	(2		)	1
Consolidated	$	460		$	364		$	49		$	363		$	390		$	(24	)


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



	Successor								Predecessor
	Year-to-Date 2017								Year-to-Date 2016
	Adjusted Operating			Operating			Net		Adjusted Operating			Operating
	Margin^(*)			Expenses^(*)			Income		Margin^(*)			Expenses^(*)			EBIT
	(in millions)								(in millions)
Gas distribution operations	$	951		$	596		$	171	$	911		$	560		$	353
Gas marketing services	162			101			35		190			81			109
Wholesale gas services	118			29			51		(36		)	33			(68		)
Gas midstream operations	16			25			25		15			24			(6		)
All other	5			14			6		4			65			(60		)
Intercompany eliminations	(5		)	(5		)	—		(4		)	(4		)	—
Consolidated	$	1,247		$	760		$	288	$	1,080		$	759		$	328


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

Gas Distribution Operations

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

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Successor Second Quarter 2017

Net income of $54 million includes $409 million in adjusted operating margin, $283 million in operating expenses, and $2 million in other income (expense), net, which resulted in EBIT of $128 million. Net income also includes $40 million in interest expense and $34 million in income tax expense. Adjusted operating margin reflects $26 million in additional revenue from the continued investment in infrastructure replacement programs, a base rate increase at Atlanta Gas Light effective March 1, 2017, and a $1 million positive impact of weather, net of hedging, despite warmer-than-normal weather. Operating expenses reflect additional depreciation due to continued investment in infrastructure programs and increased pipeline compliance and maintenance activities.

Predecessor Second Quarter 2016

EBIT of $118 million includes $386 million in adjusted operating margin, $269 million in operating expenses, and $1 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 $1 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect depreciation associated with additional assets placed in service.

Successor Year-to-Date 2017

Net income of $171 million includes $951 million in adjusted operating margin, $596 million in operating expenses, and $6 million in other income (expense), net, which resulted in EBIT of $361 million. Net income also includes $80 million in interest expense and $110 million in income tax expense. Adjusted operating margin reflects $45 million in additional revenue from continued investment in infrastructure replacement programs and a base rate increase at Atlanta Gas Light effective March 1, 2017. Also included in adjusted operating margin was increased customer growth, partially offset by a $5 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect a $13 million increase in depreciation associated with additional assets placed in service, as well as increased compensation expense, legal expenses, and pipeline compliance and maintenance activities.

Predecessor Year-to-Date 2016

EBIT of $353 million includes $911 million in adjusted operating margin, $560 million in operating expenses, and $2 million in other income (expense), net. Adjusted operating margin reflects revenue from continued investment in infrastructure replacement programs and increased usage and customer growth, partially offset by a $7 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect depreciation associated with additional assets placed in service.

Gas Marketing Services

Gas marketing services consists of several businesses that provide energy-related products and services to natural gas markets, including warranty sales. Gas marketing services is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts. Operating expenses primarily reflect employee costs, marketing, and bad debt expenses.

Successor Second Quarter 2017

Net income of $4 million includes $57 million in adjusted operating margin and $48 million in operating expenses, which resulted in EBIT of $9 million. Net income also includes $2 million in interest expense and $3 million in income tax expense. Adjusted operating margin reflects a $3 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect $10 million in additional amortization of intangible assets due to fair value adjustments to certain assets and liabilities in the application of acquisition accounting.

Predecessor Second Quarter 2016

EBIT of $29 million includes $66 million in adjusted operating margin and $37 million in operating expenses. Adjusted operating margin reflects $7 million in unrealized hedge gains and a $1 million negative impact of

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weather, net of hedging. Earnings in the predecessor period include $3 million attributable to noncontrolling interest.

Successor Year-to-Date 2017

Net income of $35 million includes $162 million in adjusted operating margin and $101 million in operating expenses, which resulted in EBIT of $61 million. Net income also includes $3 million in interest expense and $23 million in income tax expense. Adjusted operating margin 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 $10 million negative impact of warmer-than-normal weather, net of hedging and $7 million in unrealized hedge losses. Operating expenses also reflect $20 million in additional amortization of intangible assets due to fair value adjustments to certain assets and liabilities in the application of acquisition accounting.

Predecessor Year-to-Date 2016

EBIT of $109 million includes $190 million in adjusted operating margin and $81 million in operating expenses. Adjusted operating margin reflects $9 million in unrealized hedge gains. Earnings in the predecessor period include $14 million attributable to noncontrolling interest.

Wholesale Gas Services

Wholesale gas services is involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services, and wholesale gas marketing. Southern Company Gas has positioned the business to generate positive economic earnings on an annual basis even under low volatility market conditions that can result from a number of factors. When market price volatility increases, wholesale gas services is well positioned to capture significant value and generate stronger results. Operating expenses primarily reflect employee compensation and benefits.

Successor Second Quarter 2017

Net loss of $17 million includes $(13) million in adjusted operating margin and $14 million in operating expenses, which resulted in a loss before interest and taxes of $27 million. Also included in net loss is $1 million in interest expense and $11 million in income tax benefit.

Predecessor Second Quarter 2016

Loss before interest and taxes of $112 million includes $(96) million in adjusted operating margin and $16 million in operating expenses.

Successor Year-to-Date 2017

Net income of $51 million includes $118 million in adjusted operating margin and $29 million in operating expenses, which resulted in EBIT of $89 million. Net income also includes $3 million in interest expense and $35 million in income tax expense.

Predecessor Year-to-Date 2016

Loss before interest and taxes of $68 million includes $(36) million in adjusted operating margin, $33 million in operating expenses, and $1 million in other income (expense), net.

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



	Successor			Predecessor			Successor			Predecessor
	Second Quarter 2017			Second Quarter 2016			Year-to-Date 2017			Year-to-Date 2016
	(in millions)			(in millions)			(in millions)			(in millions)
Commercial activity recognized	$	(18	)	$	(8	)	$	69		$	34
Gain (loss) on storage derivatives	17			(36		)	18			(38		)
Gain (loss) on transportation and forward commodity derivatives	(2		)	(52		)	37			(31		)
LOCOM adjustments, net of current period recoveries	(1		)	—			(1		)	(1		)
Impact of purchase accounting adjustments	(9		)	—			(5		)	—
Adjusted Operating Margin	$	(13	)	$	(96	)	$	118		$	(36	)

Change in Commercial Activity

The commercial activity at wholesale gas services includes recognition of storage and transportation values that were generated in prior periods, which reflect the impact of prior period hedge gains and losses as associated physical transactions occur. Warmer-than-normal weather during the 2016/2017 Heating Season, lower power generation volumes, and build-out of new U.S. pipeline infrastructure, along with increases in natural gas supply, caused low volatility and a tightening of locational or transportation spreads in 2017, negatively impacting the amount of commercial activity revenues generated relative to demand fees for contracted pipeline transportation and storage capacity, and minimum sharing under asset management agreements. However, as natural gas prices and forward storage or time spreads increased, wholesale gas services was able to capture higher storage values that it expects to recognize as commercial activity revenues when natural gas is physically withdrawn from storage. Southern Company Gas anticipates continued low volatility in certain areas of wholesale gas services' portfolio.

Change in Storage and Transportation Derivatives

Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the U.S. The volatility of natural gas commodity prices has a significant impact on Southern Company Gas' customer rates, long-term competitive position against other energy sources, and the ability of wholesale gas services to capture value from locational and seasonal spreads. In 2017 and 2016, there was little price volatility; however, the potential exists for market fundamentals indicating some level of increased volatility that would benefit Southern Company Gas' portfolio of pipeline transportation capacity. Additionally, during the first six months of 2017, forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions resulted in storage derivative gains. Transportation and forward commodity derivative gains are primarily the result of narrowing transportation basis spreads due to some reduction in supply constraints resulting from new U.S. pipeline infrastructure and increases in natural gas supply and warmer-than-normal weather, which impacted forward prices at natural gas receipt and delivery points, primarily in the Northeast and Midwest regions.

Withdrawal Schedule and Physical Transportation Transactions

The expected natural gas withdrawals from storage and expected offset to prior hedge losses/gains associated with the transportation portfolio of wholesale gas services are presented in the following table, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Wholesale gas services' expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt, and delivery 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 June 30,

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2017. A portion of wholesale gas services' storage inventory and transportation capacity is economically hedged with futures contracts, which results in the realization of substantially fixed net operating revenues.



	Storage withdrawal schedule
	Total storage (WACOG $2.75)	Expected net operating gains^(a)		Physical transportation transactions – expected net operating losses^(b)
	(in mmBtu in millions)	(in millions)		(in millions)
2017	36.5	$	5	$	(10	)
2018 and thereafter	30.9	12		(27		)
Total at June 30, 2017	67.4	$	17	$	(37	)


(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 that were previously recognized.

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

Gas Midstream Operations

Gas midstream operations consists primarily of gas pipeline investments, with storage and fuels also aggregated into this segment. Gas pipeline investments consist of the 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 Second Quarter 2017

Net income of $9 million includes $7 million in adjusted operating margin, $13 million in operating expenses, $28 million in earnings from equity method investments, which consists primarily of equity in earnings from the investment in SNG, and $1 million in other income (expense), net, which resulted in EBIT of $23 million. Also included in net income are $8 million in interest expense and $6 million in income tax expense.

Predecessor Second Quarter 2016

Loss before interest and taxes of $5 million includes $6 million in adjusted operating margin, $12 million in operating expenses, and $1 million of other income (expense), net.

Successor Year-to-Date 2017

Net income of $25 million includes $16 million in adjusted operating margin, $25 million in operating expenses, $66 million in earnings from equity method investments, which consists primarily of equity in earnings from the investment in SNG, and $2 million in other income (expense), net, which resulted in EBIT of $59 million. Also included in net income are $17 million in interest expense and $17 million in income tax expense.

Predecessor Year-to-Date 2016

Loss before interest and taxes of $6 million includes $15 million in adjusted operating margin, $24 million in operating expenses, and $3 million of other income (expense), net.

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All Other

All other includes Southern Company Gas' investment in Triton, AGL Services Company, and Southern Company Gas Capital, as well as various corporate operating expenses that are not allocated to the reportable segments and interest income (expense) associated with affiliate financing arrangements. There were no Merger-related expenses for the successor second quarter or year-to-date 2017. For the predecessor second quarter 2016 and year-to-date 2016, Merger-related expenses included in operating expenses were $53 million and $56 million, respectively.

Segment Reconciliations

Reconciliations of consolidated net income attributable to Southern Company Gas to EBIT for the successor second quarter and year-to-date 2017, and operating income to adjusted operating margin for all periods presented, are in the following tables. See Note (K) to the Condensed Financial Statements herein for additional information.



	Successor
	Second Quarter 2017
	Gas Distribution Operations		Gas Marketing Services		Wholesale Gas Services			Gas Midstream Operations		All Other			Intercompany Elimination		Consolidated
	(in millions)
Consolidated Net Income	$	54	$	4	$	(17	)	$	9	$	(1	)	$	—	$	49
Income taxes	34		3		(11		)	6		(1		)	—		31
Interest expense, net of amounts capitalized	40		2		1			8		(3		)	—		48
EBIT	$	128	$	9	$	(27	)	$	23	$	(5	)	$	—	$	128



	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	$	171	$	35	$	51	$	25	$	6		$	—	$	288
Income taxes	110		23		35		17		(5		)	—		180
Interest expense, net of amounts capitalized	80		3		3		17		(9		)	—		94
EBIT	$	361	$	61	$	89	$	59	$	(8	)	$	—	$	562



	Successor
	Second Quarter 2017
	Gas Distribution Operations			Gas Marketing Services		Wholesale Gas Services			Gas Midstream Operations			All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	126		$	9	$	(27	)	$	(6	)	$	(6	)	$	—		$	96
Other operating expenses^(a)	301			48		14			13			9			(3		)	382
Revenue tax expense^(b)	(18		)	—		—			—			—			—			(18		)
Adjusted Operating Margin	$	409		$	57	$	(13	)	$	7		$	3		$	(3	)	$	460

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	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)	$	355		$	61	$	89	$	(9	)	$	(9	)	$	—		$	487
Other operating expenses^(a)	661			101		29		25			14			(5		)	825
Revenue tax expense^(b)	(65		)	—		—		—			—			—			(65		)
Adjusted Operating Margin	$	951		$	162	$	118	$	16		$	5		$	(5	)	$	1,247



	Predecessor
	Second Quarter 2016
	Gas Distribution Operations			Gas Marketing Services		Wholesale Gas Services			Gas Midstream Operations			All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	117		$	29	$	(112	)	$	(6	)	$	(56	)	$	1		$	(27	)
Other operating expenses^(a)	286			37		16			12			58			(2		)	407
Revenue tax expense^(b)	(17		)	—		—			—			—			—			(17		)
Adjusted Operating Margin	$	386		$	66	$	(96	)	$	6		$	2		$	(1	)	$	363



	Predecessor
	Year-to-Date 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.

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

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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 pace of economic growth and natural gas demand 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 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 will require Southern Company Gas to adjust existing accumulated deferred income tax liabilities to reflect an increased tax rate, and any portion not recoverable through rates will impact earnings. Southern Company Gas is currently evaluating these changes. The ultimate impact of this legislation cannot be determined at this time, but could have a material impact on Southern Company Gas' financial statements.

Volatility of natural gas prices has a significant impact on Southern Company Gas' customer rates, long-term competitive position against other energy sources, and the ability of its gas marketing services and wholesale gas services segments to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability.

Over the longer-term, volatility is expected to be low to moderate and locational and/or transportation spreads are expected to decrease as new pipelines are built to reduce the existing supply constraints in the shale areas of the Northeast U.S. To the extent these pipelines are delayed or not built, volatility could increase. Additional economic factors may contribute to this environment, including a significant drop in oil and natural gas prices, which could lead to consolidation of natural gas producers or reduced levels of natural gas production. Further, if economic conditions continue to improve, including the new housing market, the demand for natural gas may increase, which may cause natural gas prices to rise and drive higher volatility in the natural gas markets on a longer-term basis.

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

In September 2016, Southern Company Gas acquired a 50% equity interest in SNG. See OVERVIEW – "Merger and Acquisition Activities" and 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. As part of its business strategy, Southern Company Gas regularly considers and evaluates joint development arrangements as well as acquisitions and dispositions of businesses and assets.

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 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.

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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.

Regulatory Matters

See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information regarding Southern Company Gas' regulatory matters.

Riders

Nicor Gas has established a variable tax cost adjustment rider, which was approved by the Illinois Commission effective July 16, 2017. This rider provides for recovery of the invested capital tax imposed on Nicor Gas through an annual true-up and reconciliation mechanism. Accordingly, this rider will not have a significant effect on Southern Company Gas' net income.

Natural Gas Cost Recovery

Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company 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, 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 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.

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Pending Base Rate Cases

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 is based on a projected 12-month test year beginning September 1, 2017 and a ROE of 10.25%. The requested increase includes $13 million related to the recovery of investments under the Steps to Advance Virginia's Energy (SAVE) program. The Virginia Commission is expected to rule on the requested increase in the first quarter 2018. Rate adjustments are expected to be 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

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 $75 million of qualifying assets during the first six 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 facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, Atlanta Gas Light invested $94 million during the first six months of 2017.

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.

The recovery of and return on current and future capital investments under 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 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 $12 million during the first six months of 2017.

Virginia Natural Gas

In March 2016, the Virginia Commission approved an extension to the SAVE program, under which Virginia Natural Gas invested $14 million during the first six months of 2017.

Florida City Gas

The Florida PSC approved Florida City Gas' Safety, Access, and Facility Enhancement program in 2015. Under the program, Florida City Gas invested $7 million during the first six months of 2017.

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Other Matters

Southern Company Gas is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the ordinary course of business. The ultimate outcome of such pending or potential litigation against Southern Company Gas 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

While Southern Company Gas expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Southern Company Gas' revenue, including energy provided to customers, is from tariff offerings that provide natural gas without a defined contractual term, as well as longer-term contractual agreements, including non-derivative natural gas asset management and optimization arrangements. Southern Company Gas expects that the revenue from contracts with these customers will not result in a significant shift in the timing of revenue recognition for such sales.

Southern Company Gas' ongoing evaluation of other revenue streams and related contracts includes unregulated sales to customers. Some revenue arrangements, such as energy-related derivatives and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on Southern Company Gas' financial statements. In addition, the power

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and utilities industry continues to evaluate other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company Gas expects CIAC to be out of the scope of ASC 606.

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

On 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. 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.

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 second quarter and year-to-date 2017 and the predecessor second quarter and year-to-date 2016. See OVERVIEW – "Merger and Acquisition Activities" and 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 Gas' financial condition remained stable at June 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 June 30, 2017, the amount of subsidiary retained earnings and net income available to dividend totaled $739 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 operating activities totaled $1.2 billion for the successor first six months of 2017 and $1.1 billion for the predecessor first six months of 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 $781 million for the successor first six 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 $559 million for the predecessor first six months of 2016, primarily due to gross property additions related to capital expenditures for infrastructure replacement programs at gas distribution operations.

Net cash used for financing activities totaled $351 million for the successor first six months of 2017, primarily due to net repayments of commercial paper borrowings and common stock dividend payments to Southern Company, partially offset by proceeds from debt issuances and capital contributions from Southern Company. Net cash used for financing activities totaled $558 million for the predecessor first six months of 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. 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 at June 30, 2017 include an increase of $514 million in total property, plant, and equipment primarily due to capital expenditures for infrastructure replacement programs, an increase in long-term debt of $418 million primarily due to $450 million of senior notes issued in May 2017, and decreases of $223 million in natural gas for sale, including temporary LIFO liquidation due to the use of natural gas stored during the first six months of 2017, and $631 million in notes payable related primarily to net repayments of commercial paper borrowings at Nicor Gas. Other significant balance sheet changes include decreases of $141 million and $63 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. Approximately $22 million will be required through June 30, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

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The regulatory infrastructure programs and other construction programs are subject to periodic review and revision, and actual costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in FERC rules and regulations; state regulatory approvals; changes in legislation; the cost and efficiency of labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the consolidated financial statements of Southern Company Gas in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for information regarding additional factors that may impact infrastructure investment expenditures.

Sources of Capital

Southern Company Gas plans to obtain the funds to meet its future capital needs through operating cash flows, short-term debt borrowings under its commercial paper programs, external securities issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company Gas in Item 7 of the Form 10-K for additional information.

At June 30, 2017, Southern Company Gas' current liabilities exceeded current assets by $572 million primarily as a result of $626 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.

At June 30, 2017, Southern Company Gas had approximately $38 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2017 were as follows:



	Expires
Company	2022		Unused
	(in millions)
Southern Company Gas Capital	$	1,200	$	1,149
Nicor Gas	700		700
Total	$	1,900	$	1,849

Additionally, Pivotal Utility Holdings is party to a series of loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida under which five series of gas facility revenue bonds totaling $200 million have been issued.

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

As reflected in the table above, 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.

The Facility included in the table above 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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

June 30, 2017, each of the applicable companies was in compliance with such covenant. The Facility does not contain a material adverse change clause at the time of borrowings.

Subject to applicable market conditions, the applicable company expects to renew or replace the Facility as needed, prior to expiration. In connection therewith, the applicable company may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

Southern Company Gas makes short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Commercial paper borrowings are included in notes payable in the balance sheets.

Details of short-term borrowings were as follows:



	Short-term Debt at June 30, 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	$	581	1.5	%	$	558	1.3	%	$	750
Nicor Gas	45		1.4		143		1.2		308
Short-term loans:
Southern Company Gas	—		—		—		4.0		40
Total	$	626	1.5	%	$	701	1.3	%


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

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 June 30, 2017 were $9 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 June 30, 2017, the non-principal components totaled $537 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 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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Subsequent to June 30, 2017, Atlanta Gas Light Company repaid at maturity $22 million of Series C medium-term notes.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company Gas plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

Market Price Risk

Other than the items discussed below, there were no material changes to Southern Company Gas' disclosures about market price risk during the successor second 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. 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			Successor			Predecessor
	Second Quarter			Second Quarter			Year-to-Date			Year-to-Date
	2017			2016			2017			2016
	(in millions)			(in millions)			(in millions)			(in millions)
Contracts outstanding at beginning of period, assets (liabilities), net	$	64		$	(44	)	$	12		$	75
Contracts realized or otherwise settled	(20		)	8			(16		)	(77		)
Current period changes^(a)	7			(48		)	55			(82		)
Contracts outstanding at the end of period, assets (liabilities), net	51			(84		)	51			(84		)
Netting of cash collateral	71			120			71			120
Cash collateral and net fair value of contracts outstanding at end of period^(b)	$	122		$	36		$	122		$	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 $11 million at June 30, 2017 and $5 million at June 30, 2016.

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



				Fair Value Measurements
				Successor – June 30, 2017
	Total Fair Value			Maturity
	Total Fair Value			Year 1		Years 2 & 3			Years 4 and thereafter
	(in millions)
Level 1^(a)	$	(12	)	$	5	$	(14	)	$	(3	)
Level 2^(b)	63			27		30			6
Fair value of contracts outstanding at end of period^(c)	$	51		$	32	$	16		$	3


(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 $71 million at June 30, 2017.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS

FOR

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

(UNAUDITED)

INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS



Note		Page Number
A	Introduction	189
B	Contingencies and Regulatory Matters	194
C	Fair Value Measurements	216
D	Stockholders' Equity	220
E	Financing	222
F	Retirement Benefits	226
G	Income Taxes	232
H	Derivatives	234
I	Acquisitions	249
J	Joint Ownership Agreements	252
K	Segment and Related Information	254

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

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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 June 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 six months ended June 30, 2017 and financial condition as of June 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.

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(UNAUDITED)

Recently Issued Accounting Standards

While the registrants expect most of their revenue to be included in the scope of ASC 606, they have not fully completed the evaluation of all revenue arrangements. The majority of Southern Company's, the traditional electric operating companies', and Southern Company Gas' revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined contractual term, as well as longer-term contractual commitments, including PPAs and non-derivative natural gas asset management and optimization arrangements. The majority of Southern Power's revenues includes longer-term PPAs for generation capacity and energy. The registrants expect the adoption of ASC 606 will not result in a significant shift from the current timing of revenue recognition for such transactions.

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

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

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(UNAUDITED)

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, the traditional 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.

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 six months ended June 30, 2017, transportation costs under these agreements for Alabama Power, Georgia Power, Southern Power, and Southern Company Gas were approximately $4 million, $51 million, $13 million, and $16 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 six months ended June 30, 2017, natural gas purchases made by Georgia Power and Southern Power from Southern Company Gas' subsidiaries were approximately $9 million and $56 million, respectively.

Goodwill and Other Intangible Assets

At June 30, 2017 and December 31, 2016, goodwill was as follows:



	Goodwill
	At June 30, 2017		At December 31, 2016
	(in millions)
Southern Company	$	6,271	$	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.

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(UNAUDITED)

Other intangible assets were as follows:



	At June 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	$	(57	)	$	231	$	268	$	(32	)	$	236
Trade names	159		(11		)	148		158		(5		)	153
Patents	4		—			4		4		—			4
Backlog	5		(1		)	4		5		(1		)	4
Storage and transportation contracts	64		(21		)	43		64		(2		)	62
Software and other	4		(1		)	3		2		—			2
PPA fair value adjustments	456		(35		)	421		456		(22		)	434
Total other intangible assets subject to amortization	$	980	$	(126	)	$	854	$	957	$	(62	)	$	895
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	$	75	$	—		$	75	$	75	$	—		$	75
Total other intangible assets	$	1,055	$	(126	)	$	929	$	1,032	$	(62	)	$	970

Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	456	$	(35	)	$	421	$	456	$	(22	)	$	434

Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	221	$	(53	)	$	168	$	221	$	(30	)	$	191
Trade names	115		(6		)	109		115		(2		)	113
Wholesale gas services
Storage and transportation contracts	64		(21		)	43		64		(2		)	62
Total other intangible assets subject to amortization	$	400	$	(80	)	$	320	$	400	$	(34	)	$	366

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(UNAUDITED)

Amortization associated with other intangible assets was as follows:



	Three Months Ended		Six Months Ended
	June 30, 2017
	(in millions)
Southern Company	$	29	$	65
Southern Power	$	6	$	13
Southern Company Gas	$	20	$	46

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 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 reserve to approximately $40 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' inventory decrement at June 30, 2017 is expected to be restored prior to year end. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's or Southern Company Gas' net income.

Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower of weighted average cost or current market price, with cost determined on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Southern Company Gas had no material LOCOM adjustment in any period presented.

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(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 May 15, 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia, that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper IGCC. The 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. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys'

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(UNAUDITED)

fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes.

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 has filed a petition for writ of certiorari with the Georgia Supreme Court. 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 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.

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(UNAUDITED)

Southern Company Gas

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 $12 million and $17 million as of June 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 $51 million and $44 million as of June 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 $416 million and $426 million as of June 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.

FERC Matters

Municipal and Rural Associations Tariff

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(UNAUDITED)

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.

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.

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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	June 30, 2017		December 31, 2016
		(in millions)
Rate CNP Compliance^(*)	Deferred under recovered regulatory clause revenues	$	6	$	9
Rate CNP PPA	Over recovered regulatory clause revenues	1		—
	Deferred under recovered regulatory clause revenues	—		142
Retail Energy Cost Recovery	Other regulatory liabilities, current	11		76
Natural Disaster Reserve	Other regulatory liabilities, deferred	56		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 to a deferred regulatory asset account.

Georgia Power

Rate Plans

See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of the Form 10-K for additional information.

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See "Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" and Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also see "Fuel Cost Recovery" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" and Georgia Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery.

Integrated Resource Plan

See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Integrated Resource Plan" and "Retail Regulatory Matters – Integrated Resource Plan," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan.

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of recovery for costs incurred of approximately $50 million will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.

As of June 30, 2017, Georgia Power's under recovered fuel balance totaled $61 million and is included in 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.

Nuclear Construction

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

Vogtle 3 and 4 Agreement and EPC Contractor Bankruptcy

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Contractor for subcontractors and vendors for services performed or goods provided, with these amounts paid to the EPC Contractor, except that amounts accrued for Fluor Corporation (Fluor) were paid directly to Fluor; (ii) the EPC Contractor provided 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, made payments of $5.4 million per week for these services; (iii) Georgia Power had the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who had accounts past due with the EPC Contractor; (iv) the EPC Contractor used commercially reasonable efforts to provide information reasonably requested by Georgia Power as was necessary to continue construction and investigation of the completion status of Plant Vogtle Units 3 and 4; (v) the EPC Contractor rejected or accepted the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) Georgia Power did not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserved all rights and remedies under the Vogtle 3 and 4 Agreement and all related security and collateral under applicable law.

On June 9, 2017, Georgia Power and the other Vogtle Owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (Guarantee Obligations), of which Georgia Power's proportionate share is approximately $1.7 billion, and that the Guarantee Obligations exist regardless of whether Plant Vogtle Units 3 and 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations, 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.

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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.

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

Regulatory Matters

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

Revised Cost and Schedule



Preliminary in-service dates
Unit 3	February 2021			–	March 2022
Unit 4	February 2022			–	March 2023
	(in billions)
Preliminary estimated cost to complete	$	3.9		–	$	4.6
CWIP as of June 30, 2017	4.5				4.5
Guarantee Obligations	(1.7		)		(1.7		)
Estimated capital costs	$	6.7		–	$	7.4
Vogtle Cost Settlement Agreement Revised Forecast	(5.7		)		(5.7		)
Estimated net additional capital costs	$	1.0		–	$	1.7

Georgia Power's estimated financing costs during the construction period total approximately $3.1 billion to $3.5 billion, of which approximately $1.4 billion had been incurred through June 30, 2017.



	Preliminary Cancellation Cost Estimate
	(in billions)
CWIP as of June 30, 2017	$	4.5
Financing costs collected, net of tax	1.4
Cancellation costs^(*)	0.4
Total	$	6.3


(*)	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, and currently expects to include its recommendation in its seventeenth VCM report to be filed with the Georgia PSC in late August 2017.

The ultimate outcome of these matters is dependent on the completion of the assessments described above, as well as the related regulatory treatment, and cannot be determined at this time.

Other Matters

As of June 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 and a multi-advance credit facility among Georgia Power, the DOE, and the FFB. See Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (E) under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events, and conditions to borrowing.

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

Gulf Power

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's rates and charges for service to retail customers.

Retail Base Rate Cases

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

In 2013, the Florida PSC approved a settlement agreement (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 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 six months of 2017, Gulf Power recognized the remaining allowable reductions in depreciation totaling $34.0 million.

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

Cost Recovery Clauses

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. The balance of each regulatory clause recovery on the balance sheet follows:



Regulatory Clause	Balance Sheet Line Item	June 30, 2017		December 31, 2016
		(in millions)
Fuel Cost Recovery	Under recovered regulatory clause revenues	$	7	$	—
Fuel Cost Recovery	Other regulatory liabilities, current	—		15
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	5		—
Environmental Cost Recovery	Under recovered regulatory clause revenues	12		13
Energy Conservation Cost Recovery	Under recovered regulatory clause revenues	2		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.

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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.

Environmental Compliance Overview Plan

Fuel Cost Recovery

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's retail fuel cost recovery.

At June 30, 2017, the amount of over-recovered retail fuel costs included on Mississippi Power's condensed balance sheet was $14 million compared to $37 million at December 31, 2016.

Ad Valorem Tax Adjustment

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Ad Valorem Tax Adjustment" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's ad valorem tax adjustments.

Southern Company Gas

Natural Gas Cost Recovery

Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company's 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

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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.

Pending Base Rate Cases

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

Regulatory Infrastructure Programs

Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs. See Note 3 to the financial statements of Southern Company and Southern Company Gas under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" and "Regulatory Matters – Regulatory Infrastructure Programs," respectively, in Item 8 of the Form 10-K for additional information.

Nicor Gas

Atlanta Gas Light

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Elizabethtown Gas

Virginia Natural Gas

In March 2016, the Virginia Commission approved an extension to the SAVE program, under which Virginia Natural Gas invested $14 million during the first six months of 2017.

Florida City Gas

The Florida PSC approved Florida City Gas' Safety, Access, and Facility Enhancement program in 2015. Under the program, Florida City Gas invested $7 million during the first six months of 2017.

Integrated Coal Gasification Combined Cycle

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

Kemper IGCC Overview

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

Kemper IGCC Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014. The remainder of the plant includes the gasifiers and the gas clean-up facilities. 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

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gasifiers on a sustained basis. Most recently, 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 increased significantly since certification.

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Cost Category	2010 Project Estimate^(a)		Cost Estimate at Suspension^(b)			June 30, 2017 Actual Costs
	(in billions)
Plant Subject to Cost Cap^(c)(e)	$	2.40	$	5.95		$	5.68
Lignite Mine and Equipment	0.21		0.23			0.23
CO₂ Pipeline Facilities	0.14		0.11			0.11
AFUDC^(d)	0.17		0.85			0.85
Combined Cycle and Related Assets Placed in Service – Incremental^(e)	—		0.05			0.05
General Exceptions	0.05		0.10			0.08
Deferred Costs^(e)	—		0.23			0.23
Additional DOE Grants^(f)	—		(0.14		)	(0.14		)
Total Kemper IGCC	$	2.97	$	7.38		$	7.09


(a)	Represents the certificated cost estimate adjusted to include the certificated estimate for the CO₂ pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions.


(b)	Represents actual costs through June 30, 2017 and projected costs at the time of project suspension, including estimated post-in-service costs which were 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 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 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 Cost Estimate at Suspension 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)

(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).

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Rate Recovery of Kemper IGCC Costs

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

Kemper IGCC Settlement Docket

On June 21, 2017, the Mississippi PSC stated its intent to issue an order (which occurred on July 6, 2017) directing Mississippi Power to pursue a settlement under which the Kemper County energy facility would be operated as a natural gas plant, rather than an IGCC plant, and address all issues associated with the Kemper IGCC. The Kemper Settlement Order established a new docket for the purposes of pursuing a global settlement of costs of the Kemper IGCC (Kemper IGCC Settlement Docket). The Mississippi PSC requested any such proposed settlement agreement reflect: (i) at a minimum, no rate increase to Mississippi Power customers (with a rate reduction focused on residential customers encouraged); (ii) removal of all cost risk to customers associated with the Kemper IGCC gasifier and related assets; and (iii) modification or amendment of the CPCN for the Kemper IGCC to allow only for ownership and operation of a natural gas facility. The Kemper Settlement Order provides that any related settlement agreement be filed within 45 days from the effective date of the Kemper Settlement Order. If a settlement agreement is filed, a hearing will be set 45 days from the date of the settlement's filing, and the appropriate scheduling order will be established.

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Prudence

Economic Viability Analysis

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and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis.

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

2015 Rate Case

On 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 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 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. With implementation of the new rates on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.

2013 MPSC Rate Order

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

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

Lignite Mine and CO₂ Pipeline Facilities

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

Termination of Proposed Sale of Undivided Interest

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Subsequently, Mississippi Power issued a promissory note in the aggregate principal amount of approximately $301 million to Southern Company, which was repaid in June 2017.

Litigation

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

Baseload Act

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

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Experimental Deduction" for additional information on bonus depreciation, investment tax credits, and the Section 174 research and experimental deduction.

Bonus Depreciation

Approximately $370 million of positive cash flows is expected to result from bonus depreciation for the 2017 tax year, but may not all be realized in 2017 due to net operating loss projections for the 2017 tax year, and is dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2017. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount previously estimated as bonus depreciation would be claimed as a deduction under IRC Section 165. As of June 30, 2017, $82 million has been received through quarterly income tax refunds for bonus depreciation related to the Kemper IGCC, which may be subject to repayment. 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, subject to approval of the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, Southern Company and Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million as of June 30, 2017. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount not allowed under IRC Section 174 would be claimed as a deduction under IRC Section 165, and would result in a reversal of the related unrecognized tax benefits, excluding interest. See Note (G) for additional information. This matter is expected to be resolved in the next 12 months; however, the ultimate outcome of this matter cannot be determined at this time.

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(C)	FAIR VALUE MEASUREMENTS

As of June 30, 2017, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:



	Fair Value Measurements Using:
As of June 30, 2017:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives^(a)(b)	$	193	$	179	$	—	$	—	$	372
Interest rate derivatives	—		11		—		—		11
Foreign currency derivatives	—		56		—		—		56
Nuclear decommissioning trusts^(c)	728		966		—		25		1,719
Cash equivalents	834		—		—		—		834
Other investments	9		—		1		—		10
Total	$	1,764	$	1,212	$	1	$	25	$	3,002
Liabilities:
Energy-related derivatives^(a)(b)	$	205	$	161	$	—	$	—	$	366
Interest rate derivatives	—		23		—		—		23
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		20		—		20
Total	$	205	$	207	$	20	$	—	$	432

Alabama Power
Assets:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9
Nuclear decommissioning trusts:^(d)
Domestic equity	411		79		—		—		490
Foreign equity	56		54		—		—		110
U.S. Treasury and government agency securities	—		29		—		—		29
Corporate bonds	22		145		—		—		167
Mortgage and asset backed securities	—		18		—		—		18
Private Equity	—		—		—		25		25
Other	—		6		—		—		6
Cash equivalents	493		—		—		—		493
Total	$	982	$	340	$	—	$	25	$	1,347
Liabilities:
Energy-related derivatives	$	—	$	11	$	—	$	—	$	11

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	Fair Value Measurements Using:
As of June 30, 2017:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	15	$	—	$	—	$	15
Interest rate derivatives	—		1		—		—		1
Nuclear decommissioning trusts:^{(d) (e)}
Domestic equity	225		1		—		—		226
Foreign equity	—		147		—		—		147
U.S. Treasury and government agency securities	—		198		—		—		198
Municipal bonds	—		72		—		—		72
Corporate bonds	—		169		—		—		169
Mortgage and asset backed securities	—		41		—		—		41
Other	14		7		—		—		21
Cash equivalents	50		—		—		—		50
Total	$	289	$	651	$	—	$	—	$	940
Liabilities:
Energy-related derivatives	$	—	$	14	$	—	$	—	$	14
Interest rate derivatives	—		3		—		—		3
Total	$	—	$	17	$	—	$	—	$	17

Gulf Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	—	$	1
Cash equivalents	21		—		—		—		21
Total	$	21	$	1	$	—	$	—	$	22
Liabilities:
Energy-related derivatives	$	—	$	29	$	—	$	—	$	29

Mississippi Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	—	$	2
Interest rate derivatives	—		3		—		—		3
Cash equivalents	100		—		—		—		100
Total	$	100	$	5	$	—	$	—	$	105
Liabilities:
Energy-related derivatives	$	—	$	10	$	—	$	—	$	10

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	Fair Value Measurements Using:
As of June 30, 2017:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Southern Power
Assets:
Energy-related derivatives	$	—	$	14	$	—	$	—	$	14
Foreign currency derivatives	—		56		—		—		56
Total	$	—	$	70	$	—	$	—	$	70
Liabilities:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		20		—		20
Total	$	—	$	32	$	20	$	—	$	52

Southern Company Gas
Assets:
Energy-related derivatives^(a)(b)	$	193	$	138	$	—	$	—	$	331
Liabilities:
Energy-related derivatives^(a)(b)	$	205	$	86	$	—	$	—	$	291


(a)	Excludes $11 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value.


(b)	Excludes cash collateral of $71 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 June 30, 2017, approximately $38 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 $55 million and $118 million, respectively, for the three and six months ended June 30, 2017, and by $47 million and $67 million, respectively, for the three and six months ended June 30, 2016. Alabama Power recorded an increase in fair value of $28 million and $62 million, respectively, for the three and six months ended June 30, 2017 and $29 million and $40 million, respectively, for the three and six months ended June 30, 2016 as a change in regulatory liabilities related to its AROs. Georgia Power recorded increases in fair value of $27 million and $56 million, respectively, for the three and six months ended June 30, 2017 and $18 million and $27 million, respectively, for the three and six months ended June 30, 2016 as a change in its regulatory asset related to its AROs.

Valuation Methodologies

The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using

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observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (H) for additional information on how these derivatives are used.

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available. See Note 1 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is obligated to make generation-based payments to the seller over a period ranging from 10 to 30 years, beginning at the commercial operation date. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate, and is evaluated periodically. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.

"Other investments" include investments that are not traded in the open market. The fair value of these investments has been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.

As of June 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 June 30, 2017:	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company	$	25	$	22	Not Applicable	Not Applicable
Alabama Power	$	25	$	22	Not Applicable	Not Applicable

Private equity funds include a fund-of-funds that invests in high-quality private equity funds across several market sectors, funds that invest in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated. Liquidations are expected to occur at various times over the next 10 years.

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



	Carrying Amount		Fair Value
	(in millions)
Long-term debt, including securities due within one year:
Southern Company	$	46,631	$	48,228
Alabama Power	$	7,440	$	8,041
Georgia Power	$	10,888	$	11,585
Gulf Power	$	1,292	$	1,336
Mississippi Power	$	2,125	$	2,071
Southern Power	$	5,725	$	5,878
Southern Company Gas	$	5,699	$	6,031

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 June 30, 2017	Three Months Ended June 30, 2016	Six Months Ended June 30, 2017	Six Months Ended June 30, 2016
	(in millions)
As reported shares	998	934	996	925
Effect of options and performance share award units	7	6	7	6
Diluted shares	1,005	940	1,003	931

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 six months ended June 30, 2017 and 2016.

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Changes in Stockholders' Equity

The following table presents year-to-date changes in stockholders' equity of Southern Company:



	Number of Common Shares			Common Stockholders' Equity			Preferred and Preference Stock of Subsidiaries						Total Stockholders' Equity
	Issued	Treasury		Common Stockholders' Equity			Preferred and Preference Stock of Subsidiaries			Noncontrolling Interests^(*)			Total Stockholders' Equity
	(in thousands)			(in millions)
Balance at December 31, 2016	991,213	(819	)	$	24,758		$	609		$	1,245		$	26,612
Consolidated net income (loss) attributable to Southern Company	—	—		(723		)	—			—			(723		)
Other comprehensive income (loss)	—	—		(11		)	—			—			(11		)
Stock issued	9,129	—		417			—			—			417
Stock-based compensation	—	—		72			—			—			72
Cash dividends on common stock	—	—		(1,134		)	—			—			(1,134		)
Preference stock redemption	—	—		—			(150		)	—			(150		)
Contributions from noncontrolling interests	—	—		—						71			71
Distributions to noncontrolling interests	—	—		—			—			(40		)	(40		)
Net income attributable to noncontrolling interests	—	—		—			—			16			16
Reclassification from redeemable noncontrolling interests	—	—		—			—			114			114
Other	—	(49	)	(7		)	3			1			(3		)
Balance at June 30, 2017	1,000,342	(868	)	$	23,372		$	462		$	1,407		$	25,241

Balance at December 31, 2015	915,073	(3,352	)	$	20,592		$	609		$	781		$	21,982
Consolidated net income attributable to Southern Company	—	—		1,112			—			—			1,112
Other comprehensive income (loss)	—	—		(117		)	—			—			(117		)
Stock issued	27,297	2,599		1,383			—			—			1,383
Stock-based compensation	—	—		67			—			—			67
Cash dividends on common stock	—	—		(1,023		)	—			—			(1,023		)
Contributions from noncontrolling interests	—	—		—			—			169			169
Distributions to noncontrolling interests	—	—		—			—			(10		)	(10		)
Purchase of membership interests from noncontrolling interests	—	—		—			—			(129		)	(129		)
Net income attributable to noncontrolling interests	—	—		—			—			11			11
Other	—	(19	)	1			—			—			1
Balance at June 30, 2016	942,370	(772	)	$	22,015		$	609		$	822		$	23,446

(*)

Related to Southern Power Company and excludes redeemable noncontrolling interests. In April 2017, approximately $114 million was reclassified from redeemable noncontrolling interests to noncontrolling interests, included in stockholder's equity, due to the expiration of SunPower Corp's option to require Southern Power to purchase its membership interests in one of the solar partnerships. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

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(E)	FINANCING

Going Concern

As of June 30, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $930 million primarily due to approximately $935 million that will be required through June 30, 2018 to fund maturities of long-term debt and $17 million that will be required to fund maturities of short-term debt. In addition, Mississippi Power has $40 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilities and $50 million of fixed rate pollution control revenue bonds that are required to be remarketed over the next 12 months. Mississippi Power intends to utilize operating cash flows, lines of credit, and bank term loans, as market conditions permit, as well as, under certain circumstances, commercial paper and/or equity contributions and/or loans from Southern Company to fund Mississippi Power's short-term capital needs. Specifically, Mississippi Power has been informed by Southern Company that in the event sufficient funds are not available from external sources, Southern Company intends to provide Mississippi Power with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (B) under "Integrated Coal Gasification Combined Cycle."

DOE Loan Guarantee Borrowings

See Note 6 to the financial statements of Southern Company and Georgia Power in Item 8 of the Form 10-K for additional information regarding Georgia Power's loan guarantee agreement (Loan Guarantee Agreement) with the DOE and related multi-advance term loan facility (FFB Credit Facility) with the FFB.

On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) in connection with the DOE's consent to Georgia Power's entry into the Services Agreement and the related intellectual property licenses (IP Licenses). The purpose of the amendment is to clarify the operation of the Loan Guarantee Agreement pending Georgia Power's completion of its comprehensive schedule, cost-to-complete, and cancellation cost assessments being prepared as a result of the bankruptcy of the EPC Contractor (Cost Assessments).

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 Assessments and made a determination to continue construction of Plant Vogtle Units 3 and 4, (ii) delivered to the DOE an updated project schedule, construction budget, and other information, (iii) entered into one or more agreements with a construction contractor or contractors that will be primarily responsible for construction of Plant Vogtle Units 3 and 4 and such agreements have been approved by the DOE (together with the Services Agreement and the IP Licenses, the Replacement EPC Arrangements), and (iv) entered into a further amendment to the Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements.

Upon satisfaction of the conditions described above, advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.

In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, accuracy of project-related representations and warranties, delivery of updated project-related information, absence of liens on Georgia Power's ownership interest in Plant Vogtle Units 3 and 4 other than permitted liens, evidence of compliance

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with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs.

Under the Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default.

In the event certain mandatory prepayment events occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Services Agreement or rejection of the Services Agreement in bankruptcy if Georgia Power does not maintain access to intellectual property rights under the IP Licenses; (ii) a decision by Georgia Power not to continue construction of Plant Vogtle Units 3 and 4; (iii) a failure by Georgia Power to complete the Cost Assessments or enter into Replacement EPC Arrangements by December 31, 2017; (iv) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (v) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facility. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. In addition, under certain circumstances Georgia Power may be required to make additional prepayments in connection with its receipt of payments under the Guarantee Settlement Agreement or from the EPC Contractor under the Vogtle 3 and 4 Agreement. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Credit Facility, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.

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 June 30, 2017 was approximately $1.6 billion (comprised of approximately $890 million at Alabama Power, $550 million at Georgia Power, $82 million at Gulf Power, and $40 million at Mississippi Power). In June 2017, Georgia Power remarketed $318 million of variable rate pollution control bonds in index rate modes, reducing the liquidity support utilized under Georgia Power's bank credit arrangement. In addition, at June 30, 2017, the traditional electric operating companies had approximately $626 million (comprised of approximately $436 million at Georgia Power, $140 million at Gulf Power, and $50 million at Mississippi Power) of pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months. See Note 6 to the financial statements of each registrant under "Bank Credit Arrangements" in Item 8 of the Form 10-K and "Financing Activities" herein for additional information.

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The following table outlines the committed credit arrangements by company as of June 30, 2017:



	Expires														Executable Term Loans				Expires Within One Year
Company	2017		2018		2019		2020		2022		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)
Southern Company^(a)	$	—	$	—	$	—	$	—	$	2,000	$	2,000	$	2,000	$	—	$	—	$	—	$	—
Alabama Power	3		532		—		—		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	113		—		—		—		—		113		100		—		13		13		100
Southern Power Company	—		—		—		—		750		750		675		—		—		—		—
Southern Company Gas^(b)	—		—		—		—		1,900		1,900		1,849		—		—		—		—
Other	10		30		—		—		—		40		40		20		—		20		20
Southern Company Consolidated	$	156	$	757	$	25	$	30	$	7,200	$	8,168	$	8,011	$	65	$	13	$	33	$	195


(a)	Represents the Southern Company parent entity.


(b)	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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Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six 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	$	—	$	—	$	500		$	400
Alabama Power	550		200		—		—			—
Georgia Power	850		450		27		—			3
Gulf Power	300		85		—		6			—
Mississippi Power	—		—		—		40			893
Southern Power	—		—		—		3			3
Southern Company Gas^(c)	450		—		—		—			—
Other	—		—		—		—			8
Elimination^(d)	—		—		—		(40		)	(591		)
Southern Company Consolidated	$	2,450	$	735	$	27	$	509		$	716


(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.


(d)	Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements.

Southern Company

Alabama Power

Georgia Power

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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 550,000 shares ($55 million aggregate liquidation amount) of Gulf Power's 6.00% Series Preference Stock, 450,000 shares ($45 million aggregate liquidation amount) of Gulf Power's Series 2007A 6.45% Preference Stock, and 500,000 shares ($50 million aggregate liquidation amount) of Gulf Power's Series 2013A 5.60% Preference Stock.

Mississippi Power

In March 2017, Mississippi Power issued a $9 million short-term bank note bearing interest at 5% per annum, which was repaid in April 2017.

In 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.

Southern Company Gas


(F)	RETIREMENT BENEFITS

Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at Southern Company Gas, as discussed below, and PowerSecure. The Southern Company qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No mandatory contributions to the Southern Company qualified pension plan are anticipated for the year ending December 31, 2017. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric

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operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.

In addition, Southern Company Gas has a qualified defined benefit, trusteed, pension plan covering certain eligible employees, which was closed in 2012 to new employees. This qualified pension plan is funded in accordance with requirements of ERISA. No mandatory contributions to the Southern Company Gas qualified pension plan are anticipated for the year ending December 31, 2017. Southern Company Gas also provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company Gas provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. Southern Company Gas also has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.

See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Company Gas in Item 8 of the Form 10-K for additional information.

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Components of the net periodic benefit costs for the three and six months ended June 30, 2017 and 2016 are presented in the following tables.



Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended June 30, 2017
Service cost	$	74		$	16		$	18		$	4		$	3
Interest cost	113			24			35			5			5
Expected return on plan assets	(225		)	(49		)	(70		)	(9		)	(10		)
Amortization:
Prior service costs	3			—			1			—			1
Net (gain)/loss	41			11			14			1			2
Net periodic pension cost (income)	$	6		$	2		$	(2	)	$	1		$	1
Six Months Ended June 30, 2017
Service cost	$	147		$	32		$	37		$	7		$	7
Interest cost	227			48			69			10			10
Expected return on plan assets	(449		)	(98		)	(141		)	(19		)	(20		)
Amortization:
Prior service costs	6			1			2			—			1
Net (gain)/loss	81			21			28			3			4
Net periodic pension cost (income)	$	12		$	4		$	(5	)	$	1		$	2
Three Months Ended June 30, 2016
Service cost	$	62		$	15		$	18		$	3		$	3
Interest cost	101			24			34			4			5
Expected return on plan assets	(187		)	(46		)	(65		)	(8		)	(8		)
Amortization:
Prior service costs	3			—			2			1			—
Net (gain)/loss	37			10			13			1			1
Net periodic pension cost	$	16		$	3		$	2		$	1		$	1
Six Months Ended June 30, 2016
Service cost	$	124		$	29		$	35		$	6		$	6
Interest cost	201			48			68			9			10
Expected return on plan assets	(374		)	(92		)	(129		)	(17		)	(17		)
Amortization:
Prior service costs	7			1			3			1			—
Net (gain)/loss	75			20			27			3			3
Net periodic pension cost	$	33		$	6		$	4		$	2		$	2

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Pension Plans	Southern Company Gas
	(in millions)
Successor – Three Months Ended June 30, 2017
Service cost	$	5
Interest cost	10
Expected return on plan assets	(17		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	5
Net periodic pension cost	$	2
Successor – Six Months Ended June 30, 2017
Service cost	$	11
Interest cost	20
Expected return on plan assets	(35		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	10
Net periodic pension cost	$	5


Predecessor – Three Months Ended June 30, 2016
Service cost	$	7
Interest cost	11
Expected return on plan assets	(17		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	7
Net periodic pension cost	$	7
Predecessor – Six Months Ended June 30, 2016
Service cost	$	13
Interest cost	21
Expected return on plan assets	(33		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	13
Net periodic pension cost	$	13

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Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended June 30, 2017
Service cost	$	6		$	2		$	1		$	1		$	1
Interest cost	20			4			8			—			1
Expected return on plan assets	(17		)	(8		)	(6		)	(1		)	(1		)
Amortization:
Prior service costs	1			1			1			—			—
Net (gain)/loss	5			1			1			—			—
Net periodic postretirement benefit cost	$	15		$	—		$	5		$	—		$	1
Six Months Ended June 30, 2017
Service cost	$	12		$	3		$	3		$	1		$	1
Interest cost	40			9			15			1			2
Expected return on plan assets	(33		)	(14		)	(12		)	(1		)	(1		)
Amortization:
Prior service costs	3			2			1			—			—
Net (gain)/loss	7			1			3			—			—
Net periodic postretirement benefit cost	$	29		$	1		$	10		$	1		$	2
Three Months Ended June 30, 2016
Service cost	$	6		$	2		$	1		$	1		$	1
Interest cost	17			4			7			—			1
Expected return on plan assets	(14		)	(7		)	(5		)	(1		)	(1		)
Amortization:
Prior service costs	1			1			1			—			—
Net (gain)/loss	4			1			2			—			—
Net periodic postretirement benefit cost	$	14		$	1		$	6		$	—		$	1
Six Months Ended June 30, 2016
Service cost	$	11		$	3		$	3		$	1		$	1
Interest cost	35			9			15			1			2
Expected return on plan assets	(28		)	(13		)	(11		)	(1		)	(1		)
Amortization:
Prior service costs	3			2			1			—			—
Net (gain)/loss	7			1			4			—			—
Net periodic postretirement benefit cost	$	28		$	2		$	12		$	1		$	2

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Postretirement Benefits	Southern Company Gas
	(in millions)
Successor – Three Months Ended June 30, 2017
Service cost	$	—
Interest cost	2
Expected return on plan assets	(1		)
Amortization:
Prior service costs	—
Net (gain)/loss	1
Net periodic postretirement benefit cost	$	2
Successor – Six Months Ended June 30, 2017
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


Predecessor – Three Months Ended June 30, 2016
Service cost	$	—
Interest cost	2
Expected return on plan assets	(1		)
Amortization:
Prior service costs	—
Net (gain)/loss	1
Net periodic postretirement benefit cost	$	2
Predecessor – Six Months Ended June 30, 2016
Service cost	$	1
Interest cost	5
Expected return on plan assets	(3		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	2
Net periodic postretirement benefit cost	$	4

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(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 June 30, 2017 compared to $1.8 billion as of December 31, 2016.

The federal ITC carryforwards begin expiring in 2032 but are expected to be fully utilized by 2022. The PTC carryforwards begin expiring in 2036 but are expected to be utilized by 2022. The expected utilization of tax credit carryforwards could be further delayed by numerous factors. These factors include the acquisition of additional renewable projects, increased generation at existing wind facilities, carrying back the federal net operating loss, and potential tax reform legislation, as well as additional deductions in the event of an asset abandonment. The ultimate outcome of these matters cannot be determined at this time.

Valuation Allowances

At June 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		63
Balance at June 30, 2017	$	46	$	19	$	81

Southern Company had valuation allowances, net of the federal benefit, of $81 million at June 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 (benefit) rate was (28.6)% for the six months ended June 30, 2017 compared to 29.4% for the corresponding period in 2016. The effective tax rate decrease was primarily due to the estimated probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion. Other factors include an increase in tax benefits from wind PTCs and state apportionment rate changes, partially offset by a decrease in tax benefits from ITCs and an increase in state valuation allowances.

Southern Company recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Company uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.

Mississippi Power

Mississippi Power's effective tax (benefit) rate was (30.5)% for the six months ended June 30, 2017 compared to (208.1)% for the corresponding period in 2016. The effective tax rate increase was primarily due to the estimated

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probable losses on the Kemper IGCC, net of the non-deductible AFUDC equity portion and the related state valuation allowances.

Southern Power

Southern Power's effective tax (benefit) rate was (114.7)% for the six months ended June 30, 2017 compared to (74.0)% for the corresponding period in 2016. The effective tax rate decrease 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.

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.

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 six months ended June 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	3		1		10
Tax positions from prior periods	—		1		7
Balance as of June 30, 2017	$	468	$	19	$	501

The tax positions from current and prior periods primarily relate to state tax benefits and charitable contribution carryforwards that will be 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. 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 June 30, 2017						As of December 31, 2016
	Mississippi Power		Southern Power		Southern Company		Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	4	$	19	$	37	$	20
Tax positions not impacting the effective tax rate	464		—		464		464
Balance of unrecognized tax benefits	$	468	$	19	$	501	$	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 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

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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. Southern Company is a participant in the Compliance Assurance Process of the IRS. In addition, the pre-Merger Southern Company Gas 2014 federal tax return is currently under audit. The audits for Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.

Section 174 Research and Experimental Deduction

Southern Company 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.

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 IRC Section 174. In December 2016, Southern Company and the IRS reached a proposed settlement, subject to approval of the U.S. Congress Joint Committee on Taxation, resolving a methodology for these deductions. Due to the uncertainty related to this tax position, Southern Company and Mississippi Power had unrecognized tax benefits associated with these R&E deductions totaling approximately $464 million and associated interest of $36 million as of June 30, 2017. If the suspension of the Kemper IGCC start-up activities results in an abandonment, any amount not allowed under IRC Section 174 would be claimed as a deduction under IRC Section 165, and would result in a reversal of the related unrecognized tax benefits, excluding interest. 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 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

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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 January 1, 2021 in connection with the 2017 Rate Case Settlement Agreement. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.

Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in the statements of income.

Energy-related derivative contracts are accounted for under one of three methods:

•

Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.


•	Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.


•	Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

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At June 30, 2017, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:



	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)
Southern Company^(*)	472	2021	2024
Alabama Power	70	2020	—
Georgia Power	160	2020	—
Gulf Power	35	2020	—
Mississippi Power	41	2021	—
Southern Power	25	2017	—
Southern Company Gas^(*)	141	2019	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 3.5 billion mmBtu and short natural gas positions of 3.4 billion mmBtu as of June 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 31 million mmBtu for Southern Company, 10 million mmbtu for Georgia Power and Southern Power, 5 million mmbtu for Alabama Power, and 3 million mmBtu for Gulf Power and Mississippi Power.

For cash flow hedges of energy-related derivatives, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending June 30, 2018 are $6 million for Southern Power and immaterial for all other registrants.

Interest Rate Derivatives

Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

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At June 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 June 30, 2017
	(in millions)					(in millions)
Cash Flow Hedges of Existing Debt
Mississippi Power	$	900	1-month LIBOR	0.79%	March 2018	$	3
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
Southern Company^(*)	1,500		2.35%	1-month LIBOR + 0.87%	July 2021	(14		)
Georgia Power	250		5.40%	3-month LIBOR + 4.02%	June 2018	—
Georgia Power	500		1.95%	3-month LIBOR + 0.76%	December 2018	(2		)
Georgia Power	200		4.25%	3-month LIBOR + 2.46%	December 2019	1
Southern Company Consolidated	$	3,900				$	(11	)


(*)	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 June 30, 2018 are $(21) million for Southern Company and immaterial for all other registrants. Southern Company and certain subsidiaries have deferred gains and losses expected to be amortized into earnings through 2046.

Foreign Currency Derivatives

Southern Company and certain subsidiaries may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time that the hedged transactions affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

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At June 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 June 30, 2017
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	18
Southern Power	564		3.78%	500		1.85%	June 2026	15
Total	$	1,241		€	1,100			$	33

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 June 30, 2018 are $(23) million for Southern Company and Southern Power.

Derivative Financial Statement Presentation and Amounts

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. The fair value amounts of derivative assets and liabilities on the balance sheet are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.

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The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:



	As of June 30, 2017						As of December 31, 2016
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Southern Company
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Liabilities from risk management activities, net of collateral	$	23		$	35		$	73		$	27
Other deferred charges and assets/Other deferred credits and liabilities	8			31			25			33
Total derivatives designated as hedging instruments for regulatory purposes	$	31		$	66		$	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	$	13		$	10		$	23		$	7
Interest rate derivatives:
Other current assets/Liabilities from risk management activities, net of collateral	11			1			12			1
Other deferred charges and assets/Other deferred credits and liabilities	—			22			1			28
Foreign currency derivatives:
Other current assets/Liabilities from risk management activities, net of collateral	—			23			—			25
Other deferred charges and assets/Other deferred credits and liabilities	56			—			—			33
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	80		$	56		$	36		$	94
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Liabilities from risk management activities, net of collateral	$	237		$	202		$	489		$	483
Other deferred charges and assets/Other deferred credits and liabilities	102			86			66			81
Interest rate derivatives:
Other current assets/Liabilities from risk management activities, net of collateral	—			—			1			—
Total derivatives not designated as hedging instruments	$	339		$	288		$	556		$	564
Gross amounts recognized	$	450		$	410		$	690		$	718
Gross amounts offset^(*)	$	(219	)	$	(290	)	$	(462	)	$	(524	)
Net amounts recognized in the Balance Sheets	$	231		$	120		$	228		$	194

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

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

Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	10		$	4		$	30		$	1
Other deferred charges and assets/Other deferred credits and liabilities	5			10			14			7
Total derivatives designated as hedging instruments for regulatory purposes	$	15		$	14		$	44		$	8
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	1		$	1		$	2		$	—
Other deferred charges and assets/Other deferred credits and liabilities	—			2			—			3
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	1		$	3		$	2		$	3
Gross amounts recognized	$	16		$	17		$	46		$	11
Gross amounts offset	$	(9	)	$	(9	)	$	(8	)	$	(8	)
Net amounts recognized in the Balance Sheets	$	7		$	8		$	38		$	3

Gulf Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Liabilities from risk management activities	$	1		$	16		$	4		$	12
Other deferred charges and assets/Other deferred credits and liabilities	—			13			1			17
Total derivatives designated as hedging instruments for regulatory purposes	$	1		$	29		$	5		$	29
Gross amounts recognized	$	1		$	29		$	5		$	29
Gross amounts offset	$	(1	)	$	(1	)	$	(4	)	$	(4	)
Net amounts recognized in the Balance Sheets	$	—		$	28		$	1		$	25

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

Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	6		$	2		$	6
Other deferred charges and assets/Other deferred credits and liabilities	1			4			2			5
Total derivatives designated as hedging instruments for regulatory purposes	$	2		$	10		$	4		$	11
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	3		$	—		$	2		$	—
Other deferred charges and assets/Other deferred credits and liabilities	—			—			1			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	3		$	—		$	3		$	—
Gross amounts recognized	$	5		$	10		$	7		$	11
Gross amounts offset	$	(2	)	$	(2	)	$	(3	)	$	(3	)
Net amounts recognized in the Balance Sheets	$	3		$	8		$	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		$	8		$	18		$	4
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			25
Other deferred charges and assets/Other deferred credits and liabilities	56			—			—			33
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	69		$	31		$	18		$	62
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	1		$	3		$	1
Interest rate derivatives:
Other current assets/Other current liabilities	—			—			1			—
Total derivatives not designated as hedging instruments	$	1		$	1		$	4		$	1
Gross amounts recognized	$	70		$	32		$	22		$	63
Gross amounts offset	$	(2	)	$	(2	)	$	(5	)	$	(5	)
Net amounts recognized in the Balance Sheets	$	68		$	30		$	17		$	58

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

Southern Company Gas
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	4		$	2		$	24		$	3
Other deferred charges and assets/Other deferred credits and liabilities	—			—			1			—
Total derivatives designated as hedging instruments for regulatory purposes	$	4		$	2		$	25		$	3
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	—		$	2		$	4		$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	236		$	201		$	486		$	482
Other deferred charges and assets/Other deferred credits and liabilities	102			86			66			81
Total derivatives not designated as hedging instruments	$	338		$	287		$	552		$	563
Gross amounts of recognized	$	342		$	291		$	581		$	569
Gross amounts offset^(*)	$	(196	)	$	(267	)	$	(435	)	$	(497	)
Net amounts recognized in the Balance Sheets	$	146		$	24		$	146		$	72


(*)	Gross amounts offset include cash collateral held on deposit in broker margin accounts of $71 million and $62 million as of June 30, 2017 and December 31, 2016, respectively.

At June 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 June 30, 2017
Derivative Category and Balance Sheet Location	Southern Company^(b)			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas^(b)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(24	)	$	(3	)	$	—		$	(15	)	$	(5	)	$	(1	)
Other regulatory assets, deferred	(23		)	(2		)	(5		)	(13		)	(3		)	—
Other regulatory liabilities, current^(a)	13			3			6			—			—			4
Total energy-related derivative gains (losses)	$	(34	)	$	(2	)	$	1		$	(28	)	$	(8	)	$	3


(a)	Georgia Power includes other regulatory liabilities, current in other current liabilities.


(b)	Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $1 million at June 30, 2017.

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Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2016
Derivative Category and Balance Sheet Location	Southern Company^(c)			Alabama Power			Georgia Power		Gulf Power			Mississippi Power			Southern Company Gas^(c)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(16	)	$	(1	)	$	—	$	(9	)	$	(5	)	$	(1	)
Other regulatory assets, deferred	(19		)	—			—		(16		)	(3		)	—
Other regulatory liabilities, current^(a)	56			8			29		1			1			17
Other regulatory liabilities, deferred^(b)	12			4			7		—			—			1
Total energy-related derivative gains (losses)	$	33		$	11		$	36	$	(24	)	$	(7	)	$	17


(a)	Georgia Power includes other regulatory liabilities, current in other current liabilities.


(b)	Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.


(c)	Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $8 million at December 31, 2016.

For the three months ended June 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	$	(9	)	$	—		Depreciation and amortization	$	(2	)	$	—
Interest rate derivatives	(1		)	6			Interest expense, net of amounts capitalized	(5		)	(4		)
Foreign currency derivatives	71			(39		)	Interest expense, net of amounts capitalized	(5		)	(1		)
							Other income (expense), net^(*)	79			(20		)
Total	$	61		$	(33	)		$	67		$	(25	)
Alabama Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(2	)	$	(2	)
Georgia Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Gulf Power
Interest rate derivatives	$	(1	)	$	(2	)	Interest expense, net of amounts capitalized	$	—		$	—
Southern Power
Energy-related derivatives	$	(7	)	$	—		Depreciation and amortization	$	(2	)	$	—
Foreign currency derivatives	71			(39		)	Interest expense, net of amounts capitalized	(5		)	(1		)
							Other income (expense), net^(*)	79			(20		)
Total	$	64		$	(39	)		$	72		$	(21	)


(*)	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.

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For Southern Company Gas, the pre-tax effect of energy related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings for the successor three months ended June 30, 2017 and the predecessor three months ended 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
Derivatives in Cash Flow Hedging Relationships	Three Months Ended June 30, 2017			Three Months Ended June 30, 2016			Statements of Income Location	Three Months Ended June 30, 2017		Three Months Ended June 30, 2016
	(in millions)			(in millions)				(in millions)		(in millions)
Energy-related derivatives	$	(2	)	$	—		Cost of natural gas	$	—	$	(1	)
Interest rate derivatives	—			(19		)	Interest expense, net of amounts capitalized	—		(1		)
Total	$	(2	)	$	(19	)		$	—	$	(2	)

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For the six months ended June 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	$	(20	)	$	—		Depreciation and amortization	$	(6	)	$	—
Interest rate derivatives	(1		)	(184		)	Interest expense, net of amounts capitalized	(10		)	(7		)
Foreign currency derivatives	67			(39		)	Interest expense, net of amounts capitalized	(12		)	(1		)
							Other income (expense), net^(*)	96			(20		)
Total	$	46		$	(223	)		$	68		$	(28	)
Alabama Power
Interest rate derivatives	$	—		$	(4	)	Interest expense, net of amounts capitalized	$	(3	)	$	(3	)
Georgia Power
Interest rate derivatives	$	—		$	—		Interest expense, net of amounts capitalized	$	(3	)	$	(2	)
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	$	—		$	—		Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Southern Power
Energy-related derivatives	$	(15	)	$	—		Depreciation and amortization	$	(6	)	$	—
Interest rate derivatives	—			—			Interest expense, net of amounts capitalized	—			(1		)
Foreign currency derivatives	67			(39		)	Interest expense, net of amounts capitalized	(12		)	(1		)
							Other income (expense), net^(*)	96			(20		)
Total	$	52		$	(39	)		$	78		$	(22	)


(*)	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.

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For Southern Company Gas, the pre-tax effect of energy related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings for the successor six months ended June 30, 2017 and the predecessor six months ended 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
Derivatives in Cash Flow Hedging Relationships	Six Months Ended June 30, 2017			Six Months Ended June 30, 2016			Statements of Income Location	Six Months Ended June 30, 2017		Six Months Ended June 30, 2016
	(in millions)			(in millions)				(in millions)		(in millions)
Energy-related derivatives	$	(4	)	$	—		Cost of natural gas	$	—	$	(1	)
Interest rate derivatives	—			(64		)	Interest expense, net of amounts capitalized	—		—
Total	$	(4	)	$	(64	)		$	—	$	(1	)

For the three and six months ended June 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 six months ended June 30, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments on the statements of income were as follows:



		Gain (Loss)
		Three Months Ended June 30,					Six Months Ended June 30,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2017			2016		2017			2016
		(in millions)					(in millions)
Southern Company
Energy Related derivatives:	Natural gas revenues^(*)	$	16		$	—	$	65		$	—
	Cost of natural gas	(2		)	—		(4		)	—
Total derivatives in non-designated hedging relationships		$	14		$	—	$	61		$	—


(*)	Excludes gains (losses) recorded in cost of natural gas associated with weather derivatives of $1 million and $15 million for the three and six months ended June 30, 2017, respectively.

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		Gain (Loss)
		Successor			Predecessor			Successor			Predecessor
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	Three Months Ended June 30, 2017			Three Months Ended June 30, 2016			Six Months Ended June 30, 2017			Six Months Ended June 30, 2016
		(in millions)			(in millions)			(in millions)			(in millions)
Southern Company Gas
Energy Related derivatives:	Natural gas revenues^(*)	$	16		$	(21	)	$	65		$	(1	)
	Cost of natural gas	(2		)	(61		)	(4		)	(62		)
Total derivatives in non-designated hedging relationships		$	14		$	(82	)	$	61		$	(63	)


(*)	Excludes gains recorded in cost of natural gas associated with weather derivatives of $15 million for the successor six months ended June 30, 2017 and immaterial amounts for all other periods presented.

For the three and six months ended June 30, 2017 and 2016, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:



Derivatives in Fair Value Hedging Relationships
		Gain (Loss)
		Three Months Ended June 30,				Six Months Ended June 30,
Derivative Category	Statements of Income Location	2017		2016		2017			2016
		(in millions)				(in millions)
Southern Company
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	7	$	4	$	(1	)	$	24
Georgia Power
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	—	$	—	$	(1	)	$	15

For the three and six months ended June 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 June 30, 2017, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

At June 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 for Southern Company, $10 million for the traditional electric operating companies and Southern Power, and $1 million for Southern Company Gas. The maximum potential collateral

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requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.

Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Alabama Power and Southern Power may be required to post collateral. At June 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 June 30, 2017, cash collateral held on deposit in broker margin accounts was $71 million.

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's, the traditional electric operating companies', Southern Power's, and Southern Company Gas' exposure to counterparty credit risk. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.

Southern Company Gas also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

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(I)	ACQUISITIONS

Southern Company

Merger with Southern Company Gas

Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through the natural gas distribution utilities. On July 1, 2016, Southern Company completed the Merger for a total purchase price of approximately $8.0 billion and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company.

The Merger was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation:



Southern Company Gas Purchase Price
	(in millions)
Current assets	$	1,557
Property, plant, and equipment	10,108
Goodwill	5,967
Intangible assets	400
Regulatory assets	1,118
Other assets	229
Current liabilities	(2,201		)
Other liabilities	(4,742		)
Long-term debt	(4,261		)
Noncontrolling interest	(174		)
Total purchase price	$	8,001

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $6.0 billion is recognized as goodwill, which is primarily attributable to positioning the Southern Company system to provide natural gas infrastructure to meet customers' growing energy needs and to compete for growth across the energy value chain. Southern Company anticipates that much of the value assigned to goodwill will not be deductible for tax purposes.

The valuation of identifiable intangible assets included customer relationships, trade names, and storage and transportation contracts with estimated lives of one to 28 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).

The results of operations for Southern Company Gas have been included in Southern Company's consolidated financial statements from the date of acquisition and consist of operating revenues of $716 million and $2.3 billion and net income of $49 million and $288 million for the three and six months ended June 30, 2017, respectively.

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.

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	For the Six Months Ended June 30,
	2016
Operating revenues (in millions)	$	10,346
Net income attributable to Southern Company (in millions)	$	1,255
Basic Earnings Per Share (EPS)	$	1.34
Diluted EPS	$	1.33

These unaudited pro forma results are for comparative purposes only and may not be indicative of the results that would have occurred had this acquisition been completed on January 1, 2015 or the results that would be attained in the future.

Acquisition of PowerSecure

On May 9, 2016, Southern Company acquired all of the outstanding stock of PowerSecure, a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, for $18.75 per common share in cash, resulting in an aggregate purchase price of $429 million. As a result, PowerSecure became a wholly-owned subsidiary of Southern Company.

The acquisition of PowerSecure was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the final purchase price allocation:



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

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $284 million was recognized as goodwill, which is primarily attributable to expected business expansion opportunities for PowerSecure. Southern Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes.

The valuation of identifiable intangible assets included customer relationships, trade names, patents, backlog, and software with estimated lives of one to 26 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).

The results of operations for PowerSecure have been included in Southern Company's consolidated financial statements from the date of acquisition and are immaterial to the consolidated financial results of Southern Company. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were immaterial to Southern Company's consolidated financial results for all periods presented.

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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 Six Months Ended June 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

The aggregate amounts of revenue and net income, excluding impacts from PTCs, recognized by Southern Power related to the Bethel facility included in Southern Power's condensed consolidated statements of income for year-to-date 2017 were immaterial. The Bethel facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service; therefore, supplemental pro forma information for the comparable 2016 period is not meaningful and has been omitted.

In connection with Southern Power's 2016 acquisitions, allocations of the purchase price to individual assets were finalized during the six months ended June 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.

Acquisitions Subsequent to June 30, 2017

Subsequent to June 30, 2017, Southern Power acquired a 100% ownership interest in and commenced construction of the Cactus Flats 148-MW wind facility, the majority of which is covered by two PPAs, which expire in 2030 and 2033. The facility is expected to be placed in service in mid-2018. The ultimate outcome of this matter cannot be determined at this time.

Construction Projects Completed and in Progress



Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Projects Completed During the Six Months Ended June 30, 2017
East Pecos	Solar	120	Pecos County, TX	March 2017	15 years
Lamesa	Solar	102	Dawson County, TX	April 2017	15 years

Project Under Construction as of June 30, 2017
Mankato	Natural Gas	345	Mankato, MN	Second quarter 2019	20 years

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Development Projects


(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.

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments as of June 30, 2017 and December 31, 2016 and related income from those investments for the successor three and six month periods ended June 30, 2017 and the predecessor three and six month periods ended June 30, 2016 were as follows:




Balance Sheet Information	June 30, 2017		December 31, 2016
	(in millions)
SNG	$	1,405	$	1,394
Atlantic Coast Pipeline	53		33
PennEast Pipeline	45		22
Triton	43		44
Pivotal JAX LNG, LLC	32		16
Horizon Pipeline	31		30
Other	1		2
Total	$	1,610	$	1,541



	Successor		Predecessor		Successor		Predecessor
Income Statement Information	Three Months Ended June 30, 2017		Three Months Ended June 30, 2016		Six Months Ended June 30, 2017		Six Months Ended June 30, 2016
	(in millions)		(in millions)		(in millions)		(in millions)
SNG	$	24	$	—	$	58	$	—
Triton	2		1		2		1
PennEast Pipeline	1		—		4		—
Atlantic Coast Pipeline	2		—		3		—
Horizon Pipeline	—		—		1		1
Total	$	29	$	1	$	68	$	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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Gas made an additional $50 million contribution to maintain its 50% equity interest in SNG. See Note 11 to the financial statements of Southern Company Gas under "Investment in SNG" in Item 8 of the Form 10-K for additional information on this investment. Selected financial information of SNG for the three and six months ended June 30, 2017 is as follows:



Income Statement Information	Three Months Ended June 30, 2017		Six Months Ended June 30, 2017
	(in millions)
Revenues	$	143	$	298
Operating income	$	63	$	147
Net income	$	48	$	114

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(K) SEGMENT AND RELATED INFORMATION

Southern Company

The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the seven natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations.

Southern Company's reportable business segments are the sale of electricity by the four traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $90 million and $190 million for the three and six months ended June 30, 2017, respectively, and $107 million and $204 million for the three and six months ended June 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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Financial data for business segments and products and services for the three and six months ended June 30, 2017 and 2016 was as follows:



	Electric Utilities
	Traditional Electric Operating Companies			Southern Power		Eliminations			Total			Southern Company Gas		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2017:
Operating revenues	$	4,157		$	529	$	(101	)	$	4,585		$	716	$	166		$	(37	)	$	5,430
Segment net income (loss)^(a)(b)	(1,442		)	82		—			(1,360		)	49		(68		)	(2		)	(1,381		)
Six Months Ended June 30, 2017:
Operating revenues	$	7,943		$	979	$	(206	)	$	8,716		$	2,276	$	289		$	(79	)	$	11,202
Segment net income (loss)^(a)(b)(c)	(1,010		)	151		—			(859		)	288		(152		)	—			(723		)
Total assets at June 30, 2017	$	71,503		$	14,703	$	(317	)	$	85,889		$	21,809	$	2,348		$	(1,362	)	$	108,684
Three Months Ended June 30, 2016:
Operating revenues	$	4,115		$	373	$	(109	)	$	4,379		$	—	$	125		$	(45	)	$	4,459
Segment net income (loss)^(a)(b)	599			89		—			688			—		(61		)	(4		)	623
Six Months Ended June 30, 2016:
Operating revenues	$	7,884		$	688	$	(212	)	$	8,360		$	—	$	172		$	(81	)	$	8,451
Segment net income (loss)^(a)(b)	1,064			139		—			1,203			—		(84		)	(7		)	1,112
Total assets at December 31, 2016	$	72,141		$	15,169	$	(316	)	$	86,994		$	21,853	$	2,474		$	(1,624	)	$	109,697


(a)	Attributable to Southern Company.

(b)

Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $3.0 billion ($2.1 billion after tax) and $81 million ($50 million after tax) for the three months ended June 30, 2017 and 2016, respectively, and $3.1 billion ($2.2 billion after tax) and $134 million ($83 million after tax) for the six months ended June 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 six months ended June 30, 2017. See Note (B) under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information.

Products and Services



	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended June 30, 2017	$	3,777	$	618	$	190	$	4,585
Three Months Ended June 30, 2016	3,748		446		185		4,379

Six Months Ended June 30, 2017	$	7,171	$	1,149	$	396	$	8,716
Six Months Ended June 30, 2016	7,124		842		394		8,360

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)



	Southern Company Gas' Revenues
Period	Gas Distribution Operations		Gas Marketing Services		Other			Total
	(in millions)
Three Months Ended June 30, 2017	$	557	$	166	$	(7	)	$	716
Six Months Ended June 30, 2017	$	1,689	$	454	$	133		$	2,276

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 and six months ended June 30, 2017 and the predecessor three and six months ended 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 June 30, 2017:
Operating revenues	$	603	$	166	$	(12	)	$	12	$	769	$	3		$	(56	)	$	716
Segment net income	54		4		(17		)	9		50		(1		)	—			49
Successor – Six Months Ended June 30, 2017:
Operating revenues	$	1,783	$	454	$	119		$	37	$	2,393	$	5		$	(122	)	$	2,276
Segment net income	171		35		51			25		282		6			—			288
Successor – Total assets at June 30, 2017	$	18,257	$	2,093	$	989		$	2,381	$	23,720	$	11,182		$	(13,093	)	$	21,809

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)



	Gas Distribution Operations		Gas Marketing Services		Wholesale Gas Services^(*)			Gas Midstream Operations			Total		All Other			Eliminations			Consolidated
	(in millions)
Predecessor – Three Months Ended June 30, 2016:
Operating revenues	$	547	$	149	$	(95	)	$	10		$	611	$	2		$	(42	)	$	571
Segment EBIT	118		29		(112		)	(5		)	30		(55		)	1			(24		)
Predecessor – Six Months Ended June 30, 2016:
Operating revenues	$	1,575	$	435	$	(32	)	$	25		$	2,003	$	4		$	(102	)	$	1,905
Segment EBIT	353		109		(68		)	(6		)	388		(60		)	—			328
Successor – Total assets at December 31, 2016	$	19,453	$	2,084	$	1,127		$	2,211		$	24,875	$	11,145		$	(14,167	)	$	21,853


(*)	The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.



	Third Party Gross Revenues		Intercompany Revenues		Total Gross Revenues		Less Gross Gas Costs		Operating Revenues
	(in millions)
Successor – Three Months Ended June 30, 2017	$	1,531	$	123	$	1,654	$	1,666	$	(12	)
Successor – Six Months Ended June 30, 2017	3,370		259		3,629		3,510		119
Predecessor – Three Months Ended June 30, 2016	$	1,061	$	58	$	1,119	$	1,214	$	(95	)
Predecessor – Six Months Ended June 30, 2016	2,500		143		2,643		2,675		(32		)

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrants are involved.

Item 1A. Risk Factors.

See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. Except as described below, there have been no material changes to these risk factors from those previously disclosed in the Form 10-K.

The bankruptcy filing of the EPC Contractor is expected to have a material impact on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 and could have a material impact on the financial statements of Southern Company and Georgia Power, and any inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4, and therefore on the financial statements of Southern Company and Georgia Power.

See "Construction Risk" in Item 1A – Risk Factors of Southern Company and Georgia Power in the Form 10-K for a discussion of risks relating to major construction projects, including Plant Vogtle Units 3 and 4 and see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information.

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$400 million, of which $354 million had been paid or accrued as of June 30, 2017. Georgia Power's proportionate share of this aggregate liability totaled approximately $183 million.

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). In addition, the Vogtle Owners could terminate the Vogtle 3 and 4 Agreement for certain breaches by the EPC Contractor, including abandonment of work by the EPC Contractor.

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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.



Preliminary in-service dates
Unit 3	February 2021			–	March 2022
Unit 4	February 2022			–	March 2023
	(in billions)
Preliminary estimated cost to complete	$	3.9		–	$	4.6
CWIP as of June 30, 2017	4.5				4.5
Guarantee Obligations	(1.7		)		(1.7		)
Estimated capital costs	$	6.7		–	$	7.4
Vogtle Cost Settlement Agreement Revised Forecast	(5.7		)		(5.7		)
Estimated net additional capital costs	$	1.0		–	$	1.7

Georgia Power's estimated financing costs during the construction period total approximately $3.1 billion to $3.5 billion, of which approximately $1.4 billion had been incurred through June 30, 2017.



	Preliminary Cancellation Cost Estimate
	(in billions)
CWIP as of June 30, 2017	$	4.5
Financing costs collected, net of tax	1.4
Cancellation costs^(*)	0.4
Total	$	6.3


(*)	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, and currently expects to include its recommendation in its seventeenth Vogtle Construction Monitoring report to be filed with the Georgia PSC in late August 2017.

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The ultimate outcome of these matters is dependent on the completion of the assessments described above, as well as the related regulatory treatment, and cannot be determined at this time.

Item 6. Exhibits.

The exhibits below with an asterisk (*) preceding the exhibit number are filed herewith. The remaining exhibits have previously been filed with the SEC and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements.



	(4) Instruments Describing Rights of Security Holders, Including Indentures

	Southern Company

*	(a)1	-	Fourth Supplemental Indenture to Junior Subordinated Note Indenture, dated as of June 21, 2017, providing for the issuance of the Series 2017A 5.325% Junior Subordinated Notes due June 21, 2057.

*	(a)2	-	Nineteenth Supplemental Indenture to Senior Note Indenture, dated as of June 21, 2017, providing for the issuance of the Series 2017A Floating Rate Senior Notes due September 30, 2020.

	Georgia Power

	(c)1	-	Amendment No. 3, dated July 27, 2017 to Loan Guarantee Agreement dated February 20, 2014, between Georgia Power and the DOE. (Designated in Form 8-K dated July 27, 2017, File No. 1-6468, as Exhibit 4.1.)

	Gulf Power

	(d)	-	Twenty-Second Supplemental Indenture to Senior Note Indenture, dated as of May 18, 2017, providing for the issuance of the Series 2017A 3.30% Senior Notes due May 30, 2027. (Designated in Form 8-K dated May 15, 2017, File No. 001-31737, as Exhibit 4.2.)

	Southern Company Gas

	(g)1	-	Form of Southern Company Gas Capital Corporation's Series 2017A 4.400% Senior Notes due May 30, 2047. (Designated in Form 8-K dated May 4, 2017, File No. 1-14174, as Exhibit 4.1.)

	(g)2	-	Form of Southern Company Gas' Guarantee related to the Series 2017A 4.400% Senior Notes due May 30, 2047. (Designated in Form 8-K dated May 4, 2017, File No. 1-14174, as Exhibit 4.3.)

	(10) Material Contracts

	Georgia Power

	(c)1	-	Amendment No. 2 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. (Designated in Form 8-K dated May 12, 2017, File No. 1-6468, as Exhibit 10.1.)
	(c)2	-	Amendment No. 3 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. (Designated in Form 8-K dated June 3, 2017, File No. 1-6468, as Exhibit 10.1.)

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	(c)3	-	Amendment No. 4 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. (Designated in Form 8-K dated June 5, 2017, File No. 1-6468, as Exhibit 10.1.)
	(c)4	-	Amendment No. 5 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. (Designated in Form 8-K dated June 16, 2017, File No. 1-6468, as Exhibit 10.2.)
	(c)5	-	Amendment No. 6 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. (Designated in Form 8-K dated June 22, 2017, File No. 1-6468, as Exhibit 10.1.)
	(c)6	-	Amendment No. 7 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. (Designated in Form 8-K dated June 28, 2017, File No. 1-6468, as Exhibit 10.1.)
	(c)7	-	Amendment No. 8 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. (Designated in Form 8-K dated July 20, 2017, File No. 1-6468, as Exhibit 10.1.)
	(c)8	-	Settlement Agreement dated as of June 9, 2017, by and among Georgia Power, Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Toshiba Corporation. (Designated in Form 8-K dated June 16, 2017, File No. 1-6468, as Exhibit 10.1.)
*	(c)9	-	Amended and Restated Services Agreement dated as of June 20, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, and The City of Dalton, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse and WECTEC. (Georgia Power has requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the SEC. Georgia Power omitted such portions from the filing and filed them separately with the SEC.)

	(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).)

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	Georgia Power

	(c)	-	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).)

	Gulf Power

	(d)	-	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).)

	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.

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*	(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.

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	(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

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Table of Contents

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: August 1, 2017

266

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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: August 1, 2017

267

Table of Contents

GEORGIA POWER COMPANY

SIGNATURES



		GEORGIA POWER COMPANY

By		W. Paul Bowers
		Chairman, President, and Chief Executive Officer
		(Principal Executive Officer)

By		W. Ron Hinson
		Executive Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)

By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: August 1, 2017

268

Table of Contents

GULF POWER COMPANY

SIGNATURES



		GULF POWER COMPANY

By		S. W. Connally, Jr.
		Chairman, President and Chief Executive Officer
		(Principal Executive Officer)

By		Xia Liu
		Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)

By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: August 1, 2017

269

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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: August 1, 2017

270

Table of Contents

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: August 1, 2017

271

Table of Contents

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: August 1, 2017

272