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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2017

OR

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from           to            

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

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

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INDEX TO QUARTERLY REPORT ON FORM 10-Q

March 31, 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	46
	Condensed Statements of Comprehensive Income	46
	Condensed Statements of Cash Flows	47
	Condensed Balance Sheets	48
	Management's Discussion and Analysis of Financial Condition and Results of Operations	50
	Georgia Power Company
	Condensed Statements of Income	61
	Condensed Statements of Comprehensive Income	61
	Condensed Statements of Cash Flows	62
	Condensed Balance Sheets	63
	Management's Discussion and Analysis of Financial Condition and Results of Operations	65
	Gulf Power Company
	Condensed Statements of Income	82
	Condensed Statements of Comprehensive Income	82
	Condensed Statements of Cash Flows	83
	Condensed Balance Sheets	84
	Management's Discussion and Analysis of Financial Condition and Results of Operations	86
	Mississippi Power Company
	Condensed Statements of Income	99
	Condensed Statements of Comprehensive Income	99
	Condensed Statements of Cash Flows	100
	Condensed Balance Sheets	101
	Management's Discussion and Analysis of Financial Condition and Results of Operations	103
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	130
	Condensed Consolidated Statements of Comprehensive Income	130
	Condensed Consolidated Statements of Cash Flows	131
	Condensed Consolidated Balance Sheets	132
	Management's Discussion and Analysis of Financial Condition and Results of Operations	134

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INDEX TO QUARTERLY REPORT ON FORM 10-Q

March 31, 2017

		Page Number
	PART I—FINANCIAL INFORMATION (CONTINUED)
	Southern Company Gas and Subsidiary Companies
	Condensed Consolidated Statements of Income	146
	Condensed Consolidated Statements of Comprehensive Income	146
	Condensed Consolidated Statements of Cash Flows	147
	Condensed Consolidated Balance Sheets	148
	Management's Discussion and Analysis of Financial Condition and Results of Operations	150
	Notes to the Condensed Financial Statements	169
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	44
Item 4.	Controls and Procedures	44
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	229
Item 1A.	Risk Factors	229
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	Inapplicable
Item 3.	Defaults Upon Senior Securities	Inapplicable
Item 4.	Mine Safety Disclosures	Inapplicable
Item 5.	Other Information	231
Item 6.	Exhibits	231
	Signatures	236

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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	Westinghouse and its affiliate, WECTEC Global Project Services Inc. (formerly known as CB&I Stone & Webster, Inc.), formerly a subsidiary of The Shaw Group Inc. and Chicago Bridge & Iron Company N.V.
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
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
Internal Revenue Code	Internal Revenue Code of 1986, as amended
IRS	Internal Revenue Service
ITC	Investment tax credit
Kemper IGCC	IGCC facility under construction by Mississippi Power in Kemper County, Mississippi

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DEFINITIONS

(continued)

Term	Meaning
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
Nicor Gas Credit Facility	$700 million credit facility entered into by Nicor Gas to support its commercial paper program
NRC	U.S. Nuclear Regulatory Commission
NYMEX	New York Mercantile Exchange, Inc.
OCI	Other comprehensive income
PennEast Pipeline	PennEast Pipeline Company, LLC
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
Rate CNP PPA	Alabama Power's Rate Certificated New Plant Power Purchase Agreement

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DEFINITIONS

(continued)

Term	Meaning
Rate ECR	Alabama Power's Rate Energy Cost Recovery
Rate NDR	Alabama Power's Rate Natural Disaster Reserve
Rate RSE	Alabama Power's Rate Stabilization and Equalization plan
registrants	Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and Southern Company Gas
ROE	Return on equity
S&P	S&P Global Ratings, a division of S&P Global Inc.
scrubber	Flue gas desulfurization system
SCS	Southern Company Services, Inc. (the Southern Company system service company)
SEC	U.S. Securities and Exchange Commission
SMEPA	South Mississippi Electric Power Association (now known as Cooperative Energy)
SNG	Southern Natural Gas Company, L.L.C.
Southern Company	The Southern Company
Southern Company Gas	Southern Company Gas and its subsidiaries
Southern Company Gas Capital	Southern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas
Southern Company Gas Credit Facility	$1.3 billion credit agreement entered into by Southern Company Gas Capital to support its commercial paper program
Southern Company system	Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas (as of July 1, 2016), Southern Electric Generating Company, Southern Nuclear, SCS, Southern Communications Services, Inc., PowerSecure (as of May 9, 2016), and other subsidiaries
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company and its subsidiaries
SouthStar	SouthStar Energy Services, LLC
STRIDE	Atlanta Gas Light's Strategic Infrastructure Development and Enhancement program
Toshiba	Toshiba Corporation, parent company of Westinghouse
Toshiba Guarantee	Certain payment obligations of the 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 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, sustaining nitrogen supply, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC);

•	the results of the Contractor's bankruptcy filing and the impact of any inability or other failure of Toshiba to perform its obligations under the Toshiba Guarantee, including any effect on the construction of Plant Vogtle Units 3 and 4, as well as the engineering, procurement, and construction agreement for Plant Vogtle Units 3 and 4 and Georgia Power's DOE loan guarantees;

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

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

•	advances in technology;

•	ongoing renewable energy partnerships and development agreements;

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

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

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)

•

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

•	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.

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THE SOUTHERN COMPANY

AND SUBSIDIARY COMPANIES

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

 

	For the Three Months Ended March 31,
	2017				2016
	(in millions)
Operating Revenues:
Retail electric revenues	$	3,394			$	3,377
Wholesale electric revenues	531				396
Other electric revenues	175				181
Natural gas revenues	1,530				—
Other revenues	141				38
Total operating revenues	5,771				3,992
Operating Expenses:
Fuel	996				911
Purchased power	179				165
Cost of natural gas	719				—
Cost of other sales	88				19
Other operations and maintenance	1,329				1,107
Depreciation and amortization	716				541
Taxes other than income taxes	330				256
Estimated loss on Kemper IGCC	108				53
Total operating expenses	4,465				3,052
Operating Income	1,306				940
Other Income and (Expense):
Allowance for equity funds used during construction	57				53
Earnings from equity method investments	39				—
Interest expense, net of amounts capitalized	(416		)		(246		)
Other income (expense), net	(6		)		(29		)
Total other income and (expense)	(326		)		(222		)
Earnings Before Income Taxes	980				718
Income taxes	315				217
Consolidated Net Income	665				501
Less:
Dividends on preferred and preference stock of subsidiaries	11				11
Net income (loss) attributable to noncontrolling interests	(4		)		1
Consolidated Net Income Attributable to Southern Company	$	658			$	489
Common Stock Data:
Earnings per share (EPS) —
Basic EPS	$	0.66			$	0.53
Diluted EPS	$	0.66			$	0.53
Average number of shares of common stock outstanding (in millions)
Basic	993				916
Diluted	1,000				922
Cash dividends paid per share of common stock	$	0.5600			$	0.5425

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 COMPREHENSIVE INCOME (UNAUDITED)

 

	For the Three Months Ended March 31,
	2017				2016
	(in millions)
Consolidated Net Income	$	665			$	501
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(5) and $(72), respectively	(9		)		(117		)
Reclassification adjustment for amounts included in net income, net of tax of $(1) and $1, respectively	(1		)		2
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $- and $1, respectively	1				1
Total other comprehensive income (loss)	(9		)		(114		)
Less:
Dividends on preferred and preference stock of subsidiaries	11				11
Comprehensive income (loss) attributable to noncontrolling interests	(4		)		1
Consolidated Comprehensive Income Attributable to Southern Company	$	649			$	375

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 Three Months Ended March 31,
	2017				2016
	(in millions)
Operating Activities:
Consolidated net income	$	665			$	501
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	823				639
Deferred income taxes	161				(4		)
Allowance for equity funds used during construction	(57		)		(53		)
Stock based compensation expense	61				58
Estimated loss on Kemper IGCC	108				53
Mark-to-market adjustments	(81		)		(2		)
Other, net	(11		)		(6		)
Changes in certain current assets and liabilities —
-Receivables	312				235
-Prepayments	(111		)		(65		)
-Natural gas for sale, net of temporary LIFO liquidation	411				—
-Other current assets	(31		)		(7		)
-Accounts payable	(533		)		(72		)
-Accrued taxes	(212		)		(57		)
-Accrued compensation	(438		)		(332		)
-Retail fuel cost over recovery	(122		)		25
-Other current liabilities	(48		)		(35		)
Net cash provided from operating activities	897				878
Investing Activities:
Business acquisitions, net of cash acquired	(1,020		)		(114		)
Property additions	(1,488		)		(1,872		)
Investment in restricted cash	(13		)		(289		)
Distribution of restricted cash	26				292
Nuclear decommissioning trust fund purchases	(224		)		(316		)
Nuclear decommissioning trust fund sales	218				311
Cost of removal, net of salvage	(61		)		(52		)
Change in construction payables, net	(170		)		(94		)
Investment in unconsolidated subsidiaries	(81		)		—
Payments pursuant to LTSAs	(55		)		(49		)
Other investing activities	65				(14		)
Net cash used for investing activities	(2,803		)		(2,197		)
Financing Activities:
Increase in notes payable, net	573				294
Proceeds —
Long-term debt	1,409				1,997
Common stock	186				270
Short-term borrowings	4				—
Redemptions and repurchases —
Long-term debt	(608		)		(888		)
Short-term borrowings	—				(475		)
Distributions to noncontrolling interests	(18		)		(4		)
Capital contributions from noncontrolling interests	71				131
Purchase of membership interests from noncontrolling interests	—				(129		)
Payment of common stock dividends	(556		)		(497		)
Other financing activities	(36		)		(30		)
Net cash provided from financing activities	1,025				669
Net Change in Cash and Cash Equivalents	(881		)		(650		)
Cash and Cash Equivalents at Beginning of Period	1,975				1,404
Cash and Cash Equivalents at End of Period	$	1,094			$	754
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $25 and $30 capitalized for 2017 and 2016, respectively)	$	461			$	224
Income taxes, net	(6		)		(141		)
Noncash transactions — Accrued property additions at end of period	578				731

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 March 31, 2017				At December 31, 2016
		(in millions)
Current Assets:
Cash and cash equivalents		$	1,094			$	1,975
Receivables —
Customer accounts receivable		1,560				1,565
Energy marketing receivable		493				623
Unbilled revenues		589				706
Under recovered regulatory clause revenues		47				18
Income taxes receivable, current		544				544
Other accounts and notes receivable		433				377
Accumulated provision for uncollectible accounts		(53		)		(43		)
Materials and supplies		1,477				1,462
Fossil fuel for generation		687				689
Natural gas for sale		346				631
Prepaid expenses		401				364
Other regulatory assets, current		560				581
Other current assets		249				230
Total current assets		8,427				9,722
Property, Plant, and Equipment:
In service		99,774				98,416
Less: Accumulated depreciation		30,330				29,852
Plant in service, net of depreciation		69,444				68,564
Nuclear fuel, at amortized cost		902				905
Construction work in progress		9,465				8,977
Total property, plant, and equipment		79,811				78,446
Other Property and Investments:
Goodwill		6,251				6,251
Equity investments in unconsolidated subsidiaries		1,615				1,549
Other intangible assets, net of amortization of $97 and $62 at March 31, 2017 and December 31, 2016, respectively		935				970
Nuclear decommissioning trusts, at fair value		1,678				1,606
Leveraged leases		780				774
Miscellaneous property and investments		293				270
Total other property and investments		11,552				11,420
Deferred Charges and Other Assets:
Deferred charges related to income taxes		1,647				1,629
Unamortized loss on reacquired debt		218				223
Other regulatory assets, deferred		6,748				6,851
Other deferred charges and assets		1,357				1,406
Total deferred charges and other assets		9,970				10,109
Total Assets		$	109,760			$	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 March 31, 2017				At December 31, 2016
		(in millions)
Current Liabilities:
Securities due within one year		$	3,269			$	2,587
Notes payable		2,818				2,241
Energy marketing trade payables		471				597
Accounts payable		1,750				2,228
Customer deposits		541				558
Accrued taxes —
Accrued income taxes		258				193
Unrecognized tax benefits		400				385
Other accrued taxes		326				667
Accrued interest		453				518
Accrued compensation		461				915
Asset retirement obligations, current		386				378
Liabilities from risk management activities, net of collateral		63				107
Acquisitions payable		—				489
Other regulatory liabilities, current		221				236
Other current liabilities		867				818
Total current liabilities		12,284				12,917
Long-term Debt		42,786				42,629
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		14,307				14,092
Deferred credits related to income taxes		215				219
Accumulated deferred investment tax credits		2,264				2,228
Employee benefit obligations		2,234				2,299
Asset retirement obligations, deferred		4,170				4,136
Accrued environmental remediation		388				397
Other cost of removal obligations		2,724				2,748
Other regulatory liabilities, deferred		237				258
Other deferred credits and liabilities		873				880
Total deferred credits and other liabilities		27,412				27,257
Total Liabilities		82,482				82,803
Redeemable Preferred Stock of Subsidiaries		118				118
Redeemable Noncontrolling Interests		164				164
Stockholders' Equity:
Common Stockholders' Equity:
Common stock, par value $5 per share —
Authorized — 1.5 billion shares
Issued — March 31, 2017: 995 million shares
— December 31, 2016: 991 million shares
Treasury — March 31, 2017: 0.9 million shares
— December 31, 2016: 0.8 million shares
Par value		4,973				4,952
Paid-in capital		9,884				9,661
Treasury, at cost		(33		)		(31		)
Retained earnings		10,459				10,356
Accumulated other comprehensive loss		(189		)		(180		)
Total Common Stockholders' Equity		25,094				24,758
Preferred and Preference Stock of Subsidiaries		609				609
Noncontrolling Interests		1,293				1,245
Total Stockholders' Equity		26,996				26,612
Total Liabilities and Stockholders' Equity		$	109,760			$	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

FIRST QUARTER 2017 vs. FIRST QUARTER 2016

OVERVIEW

Southern Company is a holding company that owns all of the common stock of the traditional electric operating companies and of the parent entities of Southern Power and Southern Company Gas and owns other direct and indirect subsidiaries. Discussion of the results of operations is focused on the Southern Company system's primary business 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.

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Company's financial statements. In addition, an inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's financial statements. The ultimate outcome of these matters also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and cannot be determined at this time.

RESULTS OF OPERATIONS

Net Income

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

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

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

Retail Electric Revenues

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

In the first quarter 2017, retail electric revenues were $3.39 billion compared to $3.38 billion for the corresponding period in 2016.

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

		First Quarter 2017
		(in millions)				(% change)
Retail electric – prior year		$	3,377
Estimated change resulting from –
Rates and pricing		118				3.5
Sales decline		(11		)		(0.3	)
Weather		(137		)		(4.1	)
Fuel and other cost recovery		47				1.4
Retail electric – current year		$	3,394			0.5	%

Revenues associated with changes in rates and pricing increased in the first quarter 2017 when compared to the corresponding period in 2016 primarily due to a Rate RSE increase at Alabama Power effective January 1, 2017, the

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rate pricing effect of decreased customer usage and higher contributions from commercial and industrial customers under a rate plan allowing for variable demand-driven pricing at Georgia Power, and an ECO Plan rate increase at Mississippi Power implemented in the third quarter 2016.

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 first quarter 2017 when compared to the corresponding period in 2016. Industrial KWH sales decreased 2.2% in the first quarter 2017 primarily in the chemicals, stone, clay, and glass, and paper sectors. A strong dollar, low oil prices, weak global economic conditions, and economic policy uncertainty have constrained sales in the industrial sector. Weather-adjusted commercial KWH sales decreased 1.9% in the first quarter 2017 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 0.8% in the first quarter 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 $47 million in the first quarter 2017 when compared to the corresponding period in 2016 primarily due to an increase in fuel prices. Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.

Wholesale Electric Revenues

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

Wholesale electric revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Electricity 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 first quarter 2017, wholesale electric revenues were $531 million compared to $396 million for the corresponding period in 2016. This increase was primarily related to a $118 million increase in energy revenues and a $17 million increase in capacity revenues. The increase in energy revenues primarily related to Southern Power increases in renewable energy sales arising from new solar and wind facilities, sales from new natural gas PPAs, and

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non-PPA revenues from short-term sales. The increase in capacity revenues was primarily due to 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, $1.5 billion of natural gas revenues are included in the consolidated statements of income for the first quarter 2017.

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

Other Revenues

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

N/M - Not meaningful

In the first quarter 2017, other revenues were $141 million compared to $38 million for the corresponding period in 2016. The increase was primarily due to $70 million from products and services at PowerSecure, which was acquired on May 9, 2016, and $30 million 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

		First Quarter 2017 vs. First Quarter 2016
		(change in millions)				(% change)
Fuel		$	85			9.3
Purchased power		14				8.5
Total fuel and purchased power expenses		$	99

In the first quarter 2017, total fuel and purchased power expenses were $1.2 billion compared to $1.1 billion for the corresponding period in 2016. The increase was primarily the result of a $121 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices, partially offset by a $22 million decrease in the volume of KWHs generated and purchased.

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

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

		First Quarter 2017		First Quarter 2016
Total generation (in billions of KWHs)		44		44
Total purchased power (in billions of KWHs)		4		4
Sources of generation (percent) —
Coal		29		27
Nuclear		17		17
Gas		46		47
Hydro		2		7
Other		6		2
Cost of fuel, generated (in cents per net KWH) —
Coal		2.88		3.24
Nuclear		0.79		0.82
Gas		2.92		2.16
Average cost of fuel, generated (in cents per net KWH)		2.50		2.23
Average cost of purchased power (in cents per net KWH)(*)		6.11		5.27

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

Fuel

In the first quarter 2017, fuel expense was $996 million compared to $911 million for the corresponding period in 2016. The increase was primarily due to a 35.2% increase in the average cost of natural gas per KWH generated and a 5.5% increase in the volume of KWHs generated by coal, partially offset by an 11.1% decrease in the average cost of coal per KWH generated and an 8.4% decrease in the volume of KWHs generated by natural gas.

Purchased Power

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

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, $719 million of natural gas costs were included in the consolidated statements of income for the first quarter 2017.

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

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Cost of Other Sales

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

N/M - Not meaningful

In the first quarter 2017, cost of other sales were $88 million compared to $19 million for the corresponding period in 2016. The increase was primarily due to costs related to sales of products and services by PowerSecure, which was acquired on May 9, 2016.

See Note (I) to the Condensed Financial Statements under "Southern Company – Acquisition of PowerSecure" herein for additional information.

Other Operations and Maintenance Expenses

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

In the first 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 $253 million in operations and maintenance expenses at Southern Company Gas following the Merger, $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), and $21 million in operations and maintenance expenses at PowerSecure, which was acquired on May 9, 2016, partially offset by a decrease of $38 million in scheduled outage and maintenance costs at generation facilities and a $19 million increase in gains from sales of integrated transmission system assets at Georgia Power.

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

Depreciation and Amortization

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

In the first quarter 2017, depreciation and amortization was $716 million compared to $541 million for the corresponding period in 2016. Following the Merger, $120 million in depreciation and amortization for Southern Company Gas is included in the consolidated statements of income for the first quarter 2017. Additionally, the increase reflects $60 million related to additional plant in service at the traditional electric operating companies and Southern Power, partially offset by $20 million more of a reduction in depreciation in the first 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.

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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Taxes Other Than Income Taxes

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

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

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

Estimated Loss on Kemper IGCC

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

N/M - Not meaningful

In the first quarter 2017 and 2016, estimated probable losses on the Kemper IGCC of $108 million and $53 million, respectively, were recorded at Southern Company. These losses reflect revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction 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).

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

Earnings from Equity Method Investments

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

N/M - Not meaningful

In the first quarter 2017, earnings from equity method investments were $39 million, primarily related to earnings from Southern Company Gas' equity method investment in SNG effective September 2016.

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Interest Expense, Net of Amounts Capitalized

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

In the first quarter 2017, interest expense, net of amounts capitalized was $416 million compared to $246 million in the corresponding period in 2016. The increase was primarily due to an increase in average outstanding long-term debt primarily related to the financing of the Merger and the funding of Southern Power's growth strategy and continuous construction program. In addition, following the Merger, $46 million in interest expense of Southern Company Gas is included in the consolidated statements of income for the first quarter 2017.

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

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

In the first quarter 2017, other income (expense), net was $(6) million compared to $(29) million for the corresponding period in 2016. The change was primarily due to parent company expenses incurred in 2016 associated with bridge financing for the Merger. The change also includes a currency loss of $17 million at Southern Power arising from a translation of euro-denominated fixed-rate notes into U.S. dollars, fully offset by a gain of $17 million on the related foreign currency hedge that was reclassified from accumulated OCI into earnings.

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

Income Taxes

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

In the first quarter 2017, income taxes were $315 million compared to $217 million for the corresponding period in 2016. The increase was primarily due to $150 million in taxes at Southern Company Gas following the Merger and a $12 million increase related to a decrease in tax benefits from solar ITCs at Southern Power, partially offset by increases in tax benefits of $30 million from wind PTCs at Southern Power, $21 million related to the estimated probable losses on construction of the Kemper IGCC at Mississippi Power, and $9 million from state apportionment rate changes 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. The completion of construction and resolution of cost recovery relating to the Kemper IGCC and the

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impact of the Contractor's bankruptcy on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 are other 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 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 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

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statements of Southern Company 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 Southern Company in Item 7 of the Form 10-K for additional information regarding the final rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs and the final effluent guidelines rule.

On March 1, 2017, the EPA and the U.S. Army Corps of Engineers released a notice of intent to review and rescind or further revise the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.

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

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

Global Climate Issues

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

On March 28, 2017, the 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. The ultimate outcome of this matter cannot be determined at this time.

Regulatory Matters

Fuel Cost Recovery

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

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

Renewables

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

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

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.

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 of approximately $50 million incurred through March 31, 2017 will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.

Gulf Power

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

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

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52.5% for all retail regulatory purposes; (3) begin amortizing the regulatory asset associated with the investment balances remaining after the retirement of Plant Smith Units 1 and 2 (357 MWs) over 15 years effective January 1, 2018; and (4) implement new depreciation rates effective January 1, 2018. The 2017 Rate Case Settlement Agreement also resulted in a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs), which was recorded in the first quarter 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. Accordingly, 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 an ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase within the 11-month statutory time limit, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.

Construction Program

Overview

The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings. Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates.

The two largest construction projects currently underway in the Southern Company system are Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs) and Mississippi Power's 582-MW Kemper IGCC. 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 –

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

Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.

Integrated Coal Gasification Combined Cycle

Mississippi Power continues to progress toward completing the construction and start-up of the Kemper IGCC, which was approved by the Mississippi PSC in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of Initial DOE Grants and excluding the Cost Cap Exceptions. The current cost estimate for the Kemper IGCC in total is approximately $7.16 billion, which includes approximately $5.75 billion of costs subject to the construction cost cap and is net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts to customers. Mississippi Power does not intend to seek any rate recovery for any related costs that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Southern Company recorded pre-tax charges to income for revisions to the cost estimate subject to the construction cost cap totaling $108 million ($67 million after tax) in the first quarter 2017. Since 2013, in the aggregate, Southern Company has incurred charges of $2.87 billion ($1.77 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2017. The current cost estimate includes costs through May 31, 2017, as well as identified costs to be incurred beyond May 31, 2017, expected to be subject to the $2.88 billion cost cap. Additional improvement projects to enhance plant performance, safety, and/or operations ultimately may be completed after the remainder of the Kemper IGCC is placed in service. These projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap.

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

In December 2015, the Mississippi PSC issued an order, based on a stipulation between Mississippi Power and the Mississippi Public Utilities Staff (MPUS), authorizing rates that provide for the recovery of approximately $126 million annually related to the combined cycle and associated common facilities portion of Kemper IGCC assets previously placed in service. Upon placing the remainder of the plant in service, Mississippi Power will be focused primarily on completing the regulatory cost recovery process.

Mississippi Power is required to file a rate case to address Kemper IGCC cost recovery by June 3, 2017 (2017 Rate Case). Costs incurred through March 31, 2017 totaled $6.93 billion, net of the Initial and Additional DOE Grants. Of this total, $2.87 billion of costs has been recognized through income as a result of the $2.88 billion cost cap, $0.83 billion is included in retail and wholesale rates for the assets in service, and the remainder will be the subject of the 2017 Rate Case to be filed with the Mississippi PSC and expected subsequent wholesale Municipal and Rural Associations rate filing with the FERC. Mississippi Power continues to believe that all costs related to the Kemper IGCC that remain subject to recovery have been prudently incurred in accordance with the requirements of the 2012 MPSC CPCN Order. Mississippi Power recognizes significant areas of potential challenge during future regulatory proceedings (and any subsequent, related legal challenges) exist. As described further herein, these challenges include, but are not limited to, prudence issues associated with capital costs, financing costs (AFUDC), and future

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operating costs, net of chemical revenues; potential operating parameters; income tax issues; costs deferred as regulatory assets; and the 15% portion of the project previously contracted to SMEPA.

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

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

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 Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein. Also see "Litigation" and "Other Matters" herein.

Litigation

On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. On August 12, 2016, Southern Company and Mississippi Power removed the case to the U.S. District Court for the Southern District of Mississippi. The plaintiffs filed a request to remand the case back to state court, which was granted on November 17, 2016. The individual plaintiff, John Carlton Dean, alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost

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and schedule of the Kemper IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On December 7, 2016, Southern Company filed motions to dismiss, which the Circuit Court is expected to address in the second quarter 2017.

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

Southern Company believes these legal challenges have no merit; however, an adverse outcome in 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, and the ultimate outcome of these matters cannot be determined at this time.

Nuclear Construction

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

Vogtle 3 and 4 Agreement and Contractor Bankruptcy

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

On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Among other things, the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) revised the guaranteed substantial completion dates to June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (ii) provided that delay liquidated damages will commence if the nuclear fuel loading date for each unit does not occur by December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; and (iii) provided that, pursuant to the amendment to the Vogtle 3 and 4 Agreement, Georgia Power, based

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

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

Under the Toshiba Guarantee, Toshiba has guaranteed certain payment obligations of the Contractor, including any liability of the Contractor for abandonment of work. However, due to Toshiba's financial situation described below, substantial risk regarding the Vogtle Owners' ability to fully collect under the Toshiba Guarantee exists. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed. In the event of such notice, the Vogtle Owners would be able to draw on the entire balance of the Westinghouse Letters of Credit. The Westinghouse Letters of Credit remain in place in accordance with the terms of the Vogtle 3 and 4 Agreement.

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

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

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

A number of subcontractors to the Contractor, including Fluor Enterprises, have alleged non-payment by the Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken, and continues to take, action to remove liens filed by these subcontractors through the posting of surety bonds.

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

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

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

The Contractor's bankruptcy filing is expected to have a material impact on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 and could have a material impact on Southern Company's financial statements. In addition, an inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's financial statements.

The ultimate outcome of these matters also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and cannot be determined at this time.

Regulatory Matters

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

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

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

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

Other Matters

As of March 31, 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 as construction proceeds. Processes are in place

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that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

As construction continues, the risk remains that challenges with labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost. Georgia Power's previously estimated owner's costs of approximately $10 million per month and financing costs of approximately $30 million per month for Plant Vogtle Units 3 and 4 are being evaluated as part of the comprehensive schedule and cost-to-complete analysis being performed as a result of the Contractor's bankruptcy.

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

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 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.

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 of Mississippi Power's former 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 of Mississippi Power's former officers made materially false and misleading statements regarding the Kemper IGCC in violation of certain provisions

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

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 of Mississippi Power's former 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. Southern Company believes that this legal challenge has no merit; however, an adverse outcome in this proceeding could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in this matter, and the ultimate outcome of this matter cannot be determined at this time.

The SEC is conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company believes the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on the Kemper IGCC estimated construction costs and expected in-service date. 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 Estimated Construction Costs, Project Completion Date, and Rate Recovery

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

As a result of revisions to the cost estimate, Southern Company recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC subject to the construction cost cap of $108 million ($67 million after tax) in the first quarter 2017, $127 million ($78 million after tax) in the fourth quarter 2016, $88 million ($54 million after tax) in the third quarter 2016, $81 million ($50 million after tax) in the second quarter 2016, $53

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million ($33 million after tax) in the first quarter 2016, $183 million ($113 million after tax) in the fourth quarter 2015, $150 million ($93 million after tax) in the third quarter 2015, $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, and $540 million ($333 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $2.87 billion ($1.77 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2017.

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

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

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

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

Although the 2017 Rate Case has not yet been filed and is subject to future developments with either the Kemper IGCC or the Mississippi PSC, consistent with its approach in the 2013 and 2015 rate proceedings in accordance with the law passed in 2013 authorizing multi-year rate plans, Mississippi Power is developing both a traditional rate case requesting full cost recovery of the amounts not currently in rates and a rate mitigation plan that together

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

Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimate rate recovery for the Kemper IGCC, and the potential impact on Southern Company's results of operations, Southern Company considers these items to be critical accounting estimates. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Recently Issued Accounting Standards

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, 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 contractual term. For such arrangements, Southern Company expects that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.

Southern Company's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and presented separately from revenues under ASC 606 on Southern Company's financial statements. In addition, the power and utilities industry is currently addressing 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 must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Southern Company has not elected its transition method.

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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.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at March 31, 2017. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

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

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

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related to an increase in commercial paper borrowings; and a decrease of $0.5 billion in accounts payable primarily due to the timing of vendor payments.

At the end of the first quarter 2017, the market price of Southern Company's common stock was $49.78 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $25.23 per share, representing a market-to-book ratio of 197%, compared to $49.19, $25.00, and 197%, respectively, at the end of 2016. Southern Company's common stock dividend for the first quarter 2017 was $0.56 per share compared to $0.5425 per share in the first 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 $3.3 billion will be required through March 31, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for information regarding additional factors that may impact construction expenditures.

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 –

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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 March 31, 2017 would allow for borrowings of up to $2.8 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.6 billion. The Contractor's bankruptcy and failure to perform its obligations under the Vogtle 3 and 4 Agreement could impact Georgia Power's ability to make further borrowings under the Loan Guarantee Agreement. 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 conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

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

As of March 31, 2017, Southern Company's current liabilities exceeded current assets by $3.9 billion, primarily due to long-term debt that is due within one year of $3.3 billion, including approximately $0.4 billion at the parent company, $0.4 billion at Alabama Power, $0.5 billion at Georgia Power, $0.1 billion at Gulf Power, $1.3 billion at Mississippi Power, and $0.6 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.

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

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

(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 $1.3 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.

Most of these bank credit arrangements, as well as the term loan arrangements of Alabama Power, Gulf 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 March 31, 2017, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

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

A portion of the unused credit with banks is allocated to provide liquidity support to the pollution control revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of March 31, 2017 was approximately $1.9 billion. In addition, at March 31, 2017, the traditional electric operating companies had approximately $386 million of fixed rate 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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Details of short-term borrowings were as follows:

		Short-term Debt at March 31, 2017							Short-term Debt During the Period(*)
		Amount Outstanding				Weighted Average Interest Rate			Average Amount Outstanding				Weighted Average Interest Rate			Maximum Amount Outstanding
		(in millions)							(in millions)							(in millions)
Commercial paper		$	2,682			1.2	%		$	2,355			1.1	%		$	2,885
Short-term bank debt		136				2.2	%		125				1.8	%		349
Total		$	2,818			1.3	%		$	2,480			1.1	%

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

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

Southern Company believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, bank term loans, and operating cash flows.

Credit Rating Risk

At March 31, 2017, Southern Company and its subsidiaries did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

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

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

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

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

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

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

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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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

Financing Activities

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

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

Company(a)	Senior Note Issuances				Senior Note Maturities and Redemptions				Other Long-Term Debt Issuances				Other Long-Term Debt Redemptions and Maturities(b)
	(in millions)
Southern Company(c)	$	—			$	—			$	—			$	400
Alabama Power	550				200				—				—
Georgia Power	850				—				—				2
Gulf Power	—				—				6				—
Southern Power	—				—				3				2
Other	—				—				—				4
Southern Company Consolidated	$	1,400			$	200			$	9			$	408

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

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

(c)	Represents the Southern Company parent entity.

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

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

In 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.

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 three months ended March 31, 2017, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to Gulf Power and Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power and Southern Company Gas, respectively, herein. For an in-depth discussion of each registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each registrant in Item 7 of the Form 10-K and Note 1 to the financial statements of each registrant under "Financial Instruments," Note 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 10 to the financial statements of Gulf Power, Mississippi Power, and Southern Company Gas, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also, see Note (C) and Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.

Item 4. Controls and Procedures.

(a)	Evaluation of disclosure controls and procedures.

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

(b)	Changes in internal controls over financial reporting.

There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the first 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 March 31,
	2017				2016
	(in millions)
Operating Revenues:
Retail revenues	$	1,227			$	1,193
Wholesale revenues, non-affiliates	66				63
Wholesale revenues, affiliates	33				22
Other revenues	56				53
Total operating revenues	1,382				1,331
Operating Expenses:
Fuel	298				268
Purchased power, non-affiliates	34				36
Purchased power, affiliates	28				33
Other operations and maintenance	369				392
Depreciation and amortization	181				172
Taxes other than income taxes	96				97
Total operating expenses	1,006				998
Operating Income	376				333
Other Income and (Expense):
Allowance for equity funds used during construction	8				10
Interest expense, net of amounts capitalized	(75		)		(73		)
Other income (expense), net	(5		)		(8		)
Total other income and (expense)	(72		)		(71		)
Earnings Before Income Taxes	304				262
Income taxes	126				102
Net Income	178				160
Dividends on Preferred and Preference Stock	4				4
Net Income After Dividends on Preferred and Preference Stock	$	174			$	156

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 

	For the Three Months Ended March 31,
	2017				2016
	(in millions)
Net Income	$	178			$	160
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $- and $(1), respectively	—				(2		)
Reclassification adjustment for amounts included in net income, net of tax of $1 and $1, respectively	1				1
Total other comprehensive income (loss)	1				(1		)
Comprehensive Income	$	179			$	159

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 Three Months Ended March 31,
	2017				2016
	(in millions)
Operating Activities:
Net income	$	178			$	160
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	219				211
Deferred income taxes	59				68
Other, net	(3		)		(14		)
Changes in certain current assets and liabilities —
-Receivables	30				191
-Fossil fuel stock	10				(27		)
-Other current assets	(87		)		(87		)
-Accounts payable	(214		)		(143		)
-Accrued taxes	77				66
-Accrued compensation	(96		)		(75		)
-Retail fuel cost over recovery	(36		)		(1		)
-Other current liabilities	(9		)		(8		)
Net cash provided from operating activities	128				341
Investing Activities:
Property additions	(306		)		(313		)
Nuclear decommissioning trust fund purchases	(63		)		(105		)
Nuclear decommissioning trust fund sales	63				105
Cost of removal, net of salvage	(26		)		(31		)
Change in construction payables	5				(15		)
Other investing activities	(2		)		(9		)
Net cash used for investing activities	(329		)		(368		)
Financing Activities:
Proceeds —
Senior notes	550				400
Capital contributions from parent company	314				236
Other long-term debt	—				45
Redemptions and repurchases — Senior notes	(200		)		(200		)
Payment of common stock dividends	(179		)		(191		)
Other financing activities	(8		)		(13		)
Net cash provided from financing activities	477				277
Net Change in Cash and Cash Equivalents	276				250
Cash and Cash Equivalents at Beginning of Period	420				194
Cash and Cash Equivalents at End of Period	$	696			$	444
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $3 and $4 capitalized for 2017 and 2016, respectively)	$	84			$	76
Income taxes, net	—				(162		)
Noncash transactions — Accrued property additions at end of period	90				106

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 March 31, 2017				At December 31, 2016
		(in millions)
Current Assets:
Cash and cash equivalents		$	696			$	420
Receivables —
Customer accounts receivable		326				348
Unbilled revenues		127				146
Other accounts and notes receivable		31				27
Affiliated		35				40
Accumulated provision for uncollectible accounts		(10		)		(10		)
Fossil fuel stock		195				205
Materials and supplies		444				435
Prepaid expenses		106				34
Other regulatory assets, current		141				149
Other current assets		8				11
Total current assets		2,099				1,805
Property, Plant, and Equipment:
In service		26,134				26,031
Less: Accumulated provision for depreciation		9,241				9,112
Plant in service, net of depreciation		16,893				16,919
Nuclear fuel, at amortized cost		332				336
Construction work in progress		642				491
Total property, plant, and equipment		17,867				17,746
Other Property and Investments:
Equity investments in unconsolidated subsidiaries		65				66
Nuclear decommissioning trusts, at fair value		825				792
Miscellaneous property and investments		113				112
Total other property and investments		1,003				970
Deferred Charges and Other Assets:
Deferred charges related to income taxes		526				525
Deferred under recovered regulatory clause revenues		—				150
Other regulatory assets, deferred		1,218				1,157
Other deferred charges and assets		156				163
Total deferred charges and other assets		1,900				1,995
Total Assets		$	22,869			$	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 March 31, 2017				At December 31, 2016
		(in millions)
Current Liabilities:
Securities due within one year		$	361			$	561
Accounts payable —
Affiliated		224				297
Other		232				433
Customer deposits		90				88
Accrued taxes —
Accrued income taxes		95				45
Other accrued taxes		65				42
Accrued interest		65				78
Accrued compensation		95				193
Other regulatory liabilities, current		45				85
Other current liabilities		71				76
Total current liabilities		1,343				1,898
Long-term Debt		7,081				6,535
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		4,714				4,654
Deferred credits related to income taxes		65				65
Accumulated deferred investment tax credits		108				110
Employee benefit obligations		288				300
Asset retirement obligations		1,523				1,503
Other cost of removal obligations		667				684
Other regulatory liabilities, deferred		88				100
Other deferred credits and liabilities		70				63
Total deferred credits and other liabilities		7,523				7,479
Total Liabilities		15,947				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		2,936				2,613
Retained earnings		2,513				2,518
Accumulated other comprehensive loss		(30		)		(30		)
Total common stockholder's equity		6,641				6,323
Total Liabilities and Stockholder's Equity		$	22,869			$	22,516

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

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2017 vs. FIRST QUARTER 2016

OVERVIEW

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

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

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

RESULTS OF OPERATIONS

Net Income

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

Alabama Power's net income after dividends on preferred and preference stock for the first quarter 2017 was $174 million compared to $156 million for the corresponding period in 2016. The increase was primarily related to an increase in rates under Rate RSE effective January 1, 2017 and a decrease in non-fuel operations and maintenance expenses. The increase to net income was partially offset by a decrease in weather-related revenues associated with milder weather in the first quarter 2017 compared to the corresponding period in 2016.

Retail Revenues

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

In the first quarter 2017, retail revenues were $1.23 billion compared to $1.19 billion for the corresponding period in 2016.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:

	First Quarter 2017
	(in millions)				(% change)
Retail – prior year	$	1,193
Estimated change resulting from –
Rates and pricing	80				6.7
Sales growth (decline)	(1		)		(0.1	)
Weather	(55		)		(4.6	)
Fuel and other cost recovery	10				0.8
Retail – current year	$	1,227			2.8	%

Revenues associated with changes in rates and pricing increased in the first quarter 2017 when compared to the corresponding period 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 remained essentially flat in the first quarter 2017 when compared to the corresponding period in 2016. Industrial KWH sales decreased 1.2% for the first quarter 2017 when compared to the corresponding period in 2016 as a result of a decrease in demand resulting from changes in production levels primarily in the pipeline sector, partially offset by an increase in the chemicals and paper sectors. Weather-adjusted commercial KWH sales decreased 1.2% for the first quarter 2017 due to lower customer usage. Weather-adjusted residential KWH sales increased 0.6% for the first quarter 2017 primarily due to customer growth.

Revenues resulting from changes in weather decreased in the first quarter 2017 due to milder weather experienced in Alabama Power's service territory compared to the corresponding period in 2016. For the first quarter 2017, the resulting decreases were 9.0% and 2.1% for residential and commercial sales revenue, respectively.

Fuel and other cost recovery revenues increased in the first quarter 2017 when compared to the corresponding period in 2016 primarily due to an increase in the average cost of fuel. Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.

Wholesale Revenues – Affiliates

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

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

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses

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

In the first quarter 2017, fuel and purchased power expenses were $360 million compared to $337 million for the corresponding period in 2016. The increase was primarily due to a $41 million increase related to the volume of KWHs generated and a $4 million net increase related to the average cost of purchased power and fuel. These increases were partially offset by a $22 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.

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

	First Quarter 2017		First Quarter 2016
Total generation (in billions of KWHs)	15		15
Total purchased power (in billions of KWHs)	1		1
Sources of generation (percent) —
Coal	49		40
Nuclear	26		27
Gas	20		19
Hydro	5		14
Cost of fuel, generated (in cents per net KWH) —
Coal	2.60		2.86
Nuclear	0.74		0.77
Gas	2.77		2.46
Average cost of fuel, generated (in cents per net KWH)(a)	2.13		2.12
Average cost of purchased power (in cents per net KWH)(b)	6.70		5.16

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

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

Fuel

In the first quarter 2017, fuel expense was $298 million compared to $268 million for the corresponding period in 2016. The increase was primarily due to a 23.1% increase in the volume of KWHs generated by coal and a 12.6% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, partially offset by a 9.1% decrease in the average cost of coal per KWH generated.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Purchased Power – Affiliates

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

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

Other Operations and Maintenance Expenses

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

In the first quarter 2017, other operations and maintenance expenses were $369 million compared to $392 million for the corresponding period in 2016. The decrease was primarily due to decreases of $23 million in scheduled steam and other power generation outage and labor costs and $3 million in nuclear generation costs primarily due to lower amortization of prior outage costs. In addition, bad debt expense decreased $2 million. These decreases were partially offset by a $6 million increase in vegetation management costs.

Income Taxes

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

In the first quarter 2017, income taxes were $126 million compared to $102 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.

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 tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Alabama Power's financial statements. For additional information relating to these issues, see RISK FACTORS in Item 1A

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Environmental Matters

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

Environmental Statutes and Regulations

Water Quality

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

On March 1, 2017, the EPA and the U.S. Army Corps of Engineers released a notice of intent to review and rescind or further revise the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.

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

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

Global Climate Issues

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

On March 28, 2017, the 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. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Notes 1 and 3 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and "Retail Regulatory Matters," respectively, in Item 8

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Other Matters

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

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 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

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While Alabama Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Alabama Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, Alabama Power expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.

Alabama Power's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and

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presented separately from revenues under ASC 606 on Alabama Power's financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Alabama Power expects CIAC to be out of the scope of ASC 606.

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Alabama Power must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Alabama Power has not elected its transition method.

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. 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 March 31, 2017. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $128 million for the first three months of 2017, a decrease of $213 million as compared to the first three months of 2016. The decrease in net cash provided from operating activities was primarily due to the receipt of income tax refunds in 2016 as a result of bonus depreciation and the timing of vendor payments. Net cash used for investing activities totaled $329 million for the first three months of 2017 primarily due to gross property additions related to distribution, transmission, environmental, and steam generation. Net cash provided from financing activities totaled $477 million for the first three 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 three months of 2017 include increases of $546 million in long-term debt, primarily due to the issuance of additional senior notes, $323 million in additional paid-in capital due to capital contributions from Southern Company, $276 million in cash and cash equivalents, and $121 million in property, plant, and equipment, primarily due to additions to environmental, transmission, steam generation, and distribution. Other significant changes include decreases of $201 million in other accounts payable primarily due to

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

the timing of vendor payments, $200 million in securities due within one year, and $150 million in deferred under recovered regulatory clause revenues primarily due to the application of the Rate RSE refund liability and establishment of a separate regulatory asset to eliminate the under-recovered balance in Rate CNP PPA in accordance with the accounting order issued by the Alabama PSC. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Alabama Power's rate mechanisms.

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 March 31, 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.

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

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

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 March 31, 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 March 31, 2017. At March 31, 2017, Alabama Power had no fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

Alabama Power also has substantial cash flow from operating activities and access to capital markets, including a commercial paper program, to meet liquidity needs. Alabama Power may meet short-term cash needs through its commercial paper program. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support.

Details of commercial paper borrowings were as follows:

		Short-term Debt During the Period(*)
		Average Amount Outstanding				Weighted Average Interest Rate			Maximum Amount Outstanding
		(in millions)							(in millions)
Commercial paper		$	30			0.9	%		$	200

(*)	Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2017. No short-term debt was outstanding at March 31, 2017.

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

Credit Rating Risk

At March 31, 2017, Alabama Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The maximum potential collateral requirements under these contracts at March 31, 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	$	316

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

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

Financing Activities

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

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

In 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

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2017				2016
	(in millions)
Operating Revenues:
Retail revenues	$	1,689			$	1,717
Wholesale revenues, non-affiliates	39				41
Wholesale revenues, affiliates	8				5
Other revenues	96				109
Total operating revenues	1,832				1,872
Operating Expenses:
Fuel	371				376
Purchased power, non-affiliates	88				83
Purchased power, affiliates	172				139
Other operations and maintenance	381				457
Depreciation and amortization	221				211
Taxes other than income taxes	98				97
Total operating expenses	1,331				1,363
Operating Income	501				509
Other Income and (Expense):
Interest expense, net of amounts capitalized	(101		)		(94		)
Other income (expense), net	20				17
Total other income and (expense)	(81		)		(77		)
Earnings Before Income Taxes	420				432
Income taxes	156				159
Net Income	264				273
Dividends on Preferred and Preference Stock	4				4
Net Income After Dividends on Preferred and Preference Stock	$	260			$	269

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2017				2016
	(in millions)
Net Income	$	264			$	273
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $- and $-, respectively	—				—
Reclassification adjustment for amounts included in net income, net of tax of $- and $-, respectively	1				1
Total other comprehensive income (loss)	1				1
Comprehensive Income	$	265			$	274

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 Three Months Ended March 31,
	2017				2016
	(in millions)
Operating Activities:
Net income	$	264			$	273
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	271				261
Deferred income taxes	71				55
Allowance for equity funds used during construction	(13		)		(14		)
Deferred expenses	38				38
Pension, postretirement, and other employee benefits	(21		)		(10		)
Settlement of asset retirement obligations	(22		)		(24		)
Other, net	(29		)		27
Changes in certain current assets and liabilities —
-Receivables	142				155
-Fossil fuel stock	(38		)		36
-Prepaid income taxes	5				38
-Other current assets	(16		)		12
-Accounts payable	(155		)		4
-Accrued taxes	(235		)		(235		)
-Accrued compensation	(87		)		(66		)
-Retail fuel cost over recovery	(66		)		14
-Other current liabilities	2				2
Net cash provided from operating activities	111				566
Investing Activities:
Property additions	(556		)		(553		)
Nuclear decommissioning trust fund purchases	(161		)		(211		)
Nuclear decommissioning trust fund sales	155				206
Cost of removal, net of salvage	(17		)		(15		)
Change in construction payables, net of joint owner portion	(36		)		(101		)
Payments pursuant to LTSAs	(22		)		(11		)
Sale of property	63				—
Other investing activities	8				(4		)
Net cash used for investing activities	(566		)		(689		)
Financing Activities:
Decrease in notes payable, net	(391		)		(158		)
Proceeds —
Capital contributions from parent company	345				218
Senior notes	850				650
Redemptions and repurchases —
Pollution control revenue bonds	—				(4		)
Senior notes	—				(250		)
Payment of common stock dividends	(320		)		(326		)
Other financing activities	(11		)		(14		)
Net cash provided from financing activities	473				116
Net Change in Cash and Cash Equivalents	18				(7		)
Cash and Cash Equivalents at Beginning of Period	3				67
Cash and Cash Equivalents at End of Period	$	21			$	60
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $5 and $5 capitalized for 2017 and 2016, respectively)	$	88			$	86
Income taxes, net	(5		)		(88		)
Noncash transactions — Accrued property additions at end of period	320				290

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

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CONDENSED BALANCE SHEETS (UNAUDITED)

 

Assets		At March 31, 2017				At December 31, 2016
		(in millions)
Current Assets:
Cash and cash equivalents		$	21			$	3
Receivables —
Customer accounts receivable		470				523
Unbilled revenues		200				224
Joint owner accounts receivable		146				57
Other accounts and notes receivable		57				81
Affiliated		12				18
Accumulated provision for uncollectible accounts		(3		)		(3		)
Fossil fuel stock		336				298
Materials and supplies		474				479
Prepaid expenses		35				105
Other regulatory assets, current		195				193
Other current assets		38				38
Total current assets		1,981				2,016
Property, Plant, and Equipment:
In service		34,059				33,841
Less: Accumulated provision for depreciation		11,443				11,317
Plant in service, net of depreciation		22,616				22,524
Nuclear fuel, at amortized cost		570				569
Construction work in progress		5,183				4,939
Total property, plant, and equipment		28,369				28,032
Other Property and Investments:
Equity investments in unconsolidated subsidiaries		58				60
Nuclear decommissioning trusts, at fair value		853				814
Miscellaneous property and investments		46				46
Total other property and investments		957				920
Deferred Charges and Other Assets:
Deferred charges related to income taxes		676				676
Other regulatory assets, deferred		2,792				2,774
Other deferred charges and assets		473				417
Total deferred charges and other assets		3,941				3,867
Total Assets		$	35,248			$	34,835

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

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CONDENSED BALANCE SHEETS (UNAUDITED)

 

Liabilities and Stockholder's Equity		At March 31, 2017				At December 31, 2016
		(in millions)
Current Liabilities:
Securities due within one year		$	488			$	460
Notes payable		—				391
Accounts payable —
Affiliated		347				438
Other		657				589
Customer deposits		268				265
Accrued taxes —
Accrued income taxes		56				17
Other accrued taxes		115				390
Accrued interest		115				106
Accrued compensation		110				224
Asset retirement obligations, current		305				299
Other current liabilities		241				297
Total current liabilities		2,702				3,476
Long-term Debt		11,042				10,225
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		6,073				6,000
Deferred credits related to income taxes		119				121
Accumulated deferred investment tax credits		253				256
Employee benefit obligations		673				703
Asset retirement obligations, deferred		2,256				2,233
Other deferred credits and liabilities		214				199
Total deferred credits and other liabilities		9,588				9,512
Total Liabilities		23,332				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		7,238				6,885
Retained earnings		4,026				4,086
Accumulated other comprehensive loss		(12		)		(13		)
Total common stockholder's equity		11,650				11,356
Total Liabilities and Stockholder's Equity		$	35,248			$	34,835

The accompanying notes as they relate to Georgia 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

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

Georgia 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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Net Income

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

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

Retail Revenues

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

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

Details of the changes in retail revenues were as follows:

	First Quarter 2017
	(in millions)				(% change)
Retail – prior year	$	1,717
Estimated change resulting from –
Rates and pricing	26				1.5
Sales decline	(12		)		(0.7	)
Weather	(72		)		(4.2	)
Fuel cost recovery	30				1.8
Retail – current year	$	1,689			(1.6	)%

Revenues associated with changes in rates and pricing increased in the first quarter 2017 when compared to the corresponding period in 2016 primarily due to the rate pricing effect of decreased customer usage and higher contributions from commercial and industrial customers under a rate plan allowing for variable demand-driven pricing.

Revenues attributable to changes in sales decreased in the first quarter 2017 when compared to the corresponding period in 2016. Weather-adjusted residential KWH sales increased 1.3%, weather-adjusted commercial KWH sales decreased 2.5%, and weather-adjusted industrial KWH sales decreased 3.2% in the first quarter 2017 when compared to the corresponding period in 2016. An increase of approximately 29,000 residential customers since March 31, 2016 contributed to the increase in weather-adjusted residential KWH sales. A decline in 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 1,400 commercial customers since March 31, 2016. Decreased demand in the chemicals, paper, transportation, and stone, clay, and glass sectors was the main contributor to the decrease in weather-adjusted industrial KWH sales, partially offset by increased demand in the lumber and rubber sectors. A strong dollar, low oil prices, weak global economic conditions, and economic policy uncertainty have constrained sales in the industrial sector.

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Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased $30 million in the first quarter 2017 when compared to the corresponding period in 2016 primarily due to higher natural gas prices and less available hydro generation, partially offset by lower energy sales resulting from milder weather in the first quarter 2017 as compared to the corresponding period 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" in Item 7 of the Form 10-K for additional information.

Other Revenues

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

In the first quarter 2017, other revenues were $96 million compared to $109 million for the corresponding period in 2016. The decrease was primarily due to a $14 million adjustment for customer temporary facilities services revenues in 2016, partially offset by a $4 million increase in outdoor lighting sales revenues primarily attributable to LED conversions.

Fuel and Purchased Power Expenses

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

In the first quarter 2017, total fuel and purchased power expenses were $631 million compared to $598 million in the corresponding period in 2016. The increase in the first quarter 2017 was primarily due to a $45 million increase in the average cost of fuel and purchased power primarily related to higher natural gas prices and less rainfall for hydro generation, partially offset by a net decrease of $12 million related to the volume of KWHs generated and purchased due to milder weather as compared to the corresponding period in 2016 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" in Item 7 of the Form 10-K for additional information.

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

	First Quarter 2017		First Quarter 2016
Total generation (in billions of KWHs)	14		16
Total purchased power (in billions of KWHs)	7		6
Sources of generation (percent) —
Coal	27		30
Nuclear	26		23
Gas	45		42
Hydro	2		5
Cost of fuel, generated (in cents per net KWH) —
Coal	3.26		3.56
Nuclear	0.85		0.86
Gas	2.77		2.01
Average cost of fuel, generated (in cents per net KWH)	2.39		2.22
Average cost of purchased power (in cents per net KWH)(*)	4.47		4.32

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

Fuel

In the first quarter 2017, fuel expense was $371 million compared to $376 million in the corresponding period in 2016. The decrease was primarily due to a 21.1% decrease in the volume of KWHs generated by coal, partially offset by a 37.8% increase in the average cost of natural gas per KWH generated.

Purchased Power – Non-Affiliates

In the first quarter 2017, purchased power expense from non-affiliates was $88 million compared to $83 million in the corresponding period in 2016. The increase was not material. Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.

Purchased Power – Affiliates

In the first quarter 2017, purchased power expense from affiliates was $172 million compared to $139 million in the corresponding period in 2016. The increase was primarily the result of a 13.8% increase in the volume of KWHs purchased to meet customer demand and a 6.8% 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.

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Other Operations and Maintenance Expenses

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

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

Depreciation and Amortization

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

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

Interest Expense, Net of Amounts Capitalized

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

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

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. The impact of the Contractor's bankruptcy on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 is also a major factor. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and higher multi-family home construction. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power's service territory. Demand for electricity is primarily driven by 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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Current proposals related to potential 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

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 rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs and the final effluent guidelines rule.

On March 1, 2017, the EPA and the U.S. Army Corps of Engineers released a notice of intent to review and rescind or further revise the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.

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

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

Global Climate Issues

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

On March 28, 2017, the 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. The ultimate outcome of this matter cannot be determined at this time.

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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" in Item 7 of the Form 10-K for additional information regarding fuel cost recovery.

Integrated Resource Plan

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

On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at a future generation site in Stewart County, Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing of recovery for costs of approximately $50 million incurred through March 31, 2017 will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.

Nuclear Construction

See Note 3 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, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, the Vogtle Construction Litigation (as defined below), and the Contractor Settlement Agreement (as defined below).

Vogtle 3 and 4 Agreement and Contractor Bankruptcy

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

On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Among other things, the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) revised the guaranteed substantial completion dates to June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (ii) provided that delay liquidated damages will commence if the nuclear fuel loading date for each unit does not occur by December 31, 2018 for Unit 3 and December 31, 2019 for

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Unit 4; and (iii) provided that, pursuant to the amendment to the Vogtle 3 and 4 Agreement, Georgia Power, based on its ownership interest, pay to the Contractor and capitalize to the project cost approximately $350 million in settlement of disputed claims. Further, as a consequence of the settlement and Westinghouse's acquisition of WECTEC, Westinghouse engaged Fluor Enterprises, Inc. (Fluor Enterprises), a subsidiary of Fluor Corporation (Fluor), as a new construction subcontractor.

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

Under the Toshiba Guarantee, Toshiba has guaranteed certain payment obligations of the Contractor, including any liability of the Contractor for abandonment of work. However, due to Toshiba's financial situation described below, substantial risk regarding the Vogtle Owners' ability to fully collect under the Toshiba Guarantee exists. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed. In the event of such notice, the Vogtle Owners would be able to draw on the entire balance of the Westinghouse Letters of Credit. The Westinghouse Letters of Credit remain in place in accordance with the terms of the Vogtle 3 and 4 Agreement.

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

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

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

A number of subcontractors to the Contractor, including Fluor Enterprises, have alleged non-payment by the Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken, and continues to take, action to remove liens filed by these subcontractors through the posting of surety bonds.

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

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

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

The Contractor's bankruptcy filing is expected to have a material impact on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 and could have a material impact on Georgia Power's financial statements. In addition, an inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Georgia Power's financial statements.

The ultimate outcome of these matters also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and cannot be determined at this time.

Regulatory Matters

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

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

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

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

Other Matters

As of March 31, 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 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 as construction proceeds. Processes are in place

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that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

As construction continues, the risk remains that challenges with labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost. Georgia Power's previously estimated owner's costs of approximately $10 million per month and financing costs of approximately $30 million per month for Plant Vogtle Units 3 and 4 are being evaluated as part of the comprehensive schedule and cost-to-complete analysis being performed as a result of the Contractor's bankruptcy.

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

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 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.

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.

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Recently Issued Accounting Standards

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While Georgia Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Georgia Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, Georgia Power expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.

Georgia Power's ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and presented separately from revenues under ASC 606 on Georgia Power's financial statements. In addition, the power and utilities industry is currently addressing 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 must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Georgia Power has not elected its transition method.

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. 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 March 31, 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

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Net cash provided from operating activities totaled $111 million for the first three months of 2017 compared to $566 million for the corresponding period in 2016. The decrease was primarily due to the timing of vendor payments. Net cash used for investing activities totaled $566 million for the first three months of 2017 compared to $689 million for the corresponding period in 2016 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Net cash provided from financing activities totaled $473 million for the first three months of 2017 compared to $116 million in the corresponding period in 2016. The increase in cash provided from financing activities is primarily due to higher issuances of senior notes, higher capital contributions received from Southern Company, and a maturity of senior notes in 2016, partially offset by a reduction in short-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 three months of 2017 include an increase in long-term debt of $845 million due to issuances of senior notes, a decrease in notes payable of $391 million primarily due to changes in short-term liquidity needs, an increase in paid-in capital of $353 million primarily due to capital contributions received from Southern Company, and an increase in property, plant, and equipment of $337 million to comply with environmental standards and construction of generation, transmission, and distribution facilities.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for a description of Georgia Power's capital requirements for its construction program, including estimated capital expenditures for Plant Vogtle Units 3 and 4 and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $488 million will be required through March 31, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information. Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures.

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.

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Georgia Power has entered into a loan guarantee agreement (Loan Guarantee Agreement) with the DOE, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of 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 March 31, 2017 would allow for borrowings of up to $2.8 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.6 billion. The Contractor's bankruptcy and failure to perform its obligations under the Vogtle 3 and 4 Agreement could impact Georgia Power's ability to make further borrowings under the Loan Guarantee Agreement. 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 conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

At March 31, 2017, Georgia Power's current liabilities exceeded current assets by $721 million. Georgia Power's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. Georgia Power intends to utilize operating cash flows, short-term debt, external security issuances, term loans, equity contributions from Southern Company, and, to the extent available, borrowings from the FFB to fund its short-term capital needs. Georgia Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.

At March 31, 2017, Georgia Power had approximately $21 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks at March 31, 2017 was $1.75 billion of which $1.73 billion was unused. This credit arrangement expires in 2020.

This bank credit arrangement contains a covenant that limits debt levels and contains a cross acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross acceleration provision to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, the payment of which was then accelerated. At March 31, 2017, Georgia Power was in compliance with this covenant. This bank credit arrangement does not contain a material adverse change clause at the time of borrowing.

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

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

A portion of the unused credit with banks is allocated to provide liquidity support to Georgia Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2017 was approximately $868 million. In addition, at March 31, 2017, Georgia Power had $250 million of fixed rate 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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of short-term borrowings were as follows:

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

(*)	Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2017. No short-term debt was outstanding at March 31, 2017.

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

Credit Rating Risk

At March 31, 2017, Georgia Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

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

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

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

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.

Subsequent to March 31, 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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

 

	For the Three Months Ended March 31,
	2017				2016
	(in millions)
Operating Revenues:
Retail revenues	$	279			$	283
Wholesale revenues, non-affiliates	17				16
Wholesale revenues, affiliates	37				21
Other revenues	17				15
Total operating revenues	350				335
Operating Expenses:
Fuel	108				94
Purchased power, non-affiliates	32				30
Purchased power, affiliates	2				2
Other operations and maintenance	84				77
Depreciation and amortization	18				38
Taxes other than income taxes	27				29
Loss on Plant Scherer Unit 3	33				—
Total operating expenses	304				270
Operating Income	46				65
Other Income and (Expense):
Interest expense, net of amounts capitalized	(12		)		(13		)
Other income (expense), net	—				(1		)
Total other income and (expense)	(12		)		(14		)
Earnings Before Income Taxes	34				51
Income taxes	14				20
Net Income	20				31
Dividends on Preference Stock	2				2
Net Income After Dividends on Preference Stock	$	18			$	29

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 

	For the Three Months Ended March 31,
	2017				2016
	(in millions)
Net Income	$	20			$	31
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $- and $(2), respectively	(1		)		(3		)
Total other comprehensive income (loss)	(1		)		(3		)
Comprehensive Income	$	19			$	28

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

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CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

 

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

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

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

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CONDENSED BALANCE SHEETS (UNAUDITED)

 

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

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

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2017 vs. FIRST QUARTER 2016

OVERVIEW

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

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

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

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

RESULTS OF OPERATIONS

Net Income

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

Gulf Power's net income after dividends on preference stock for the first quarter 2017 was $18 million compared to $29 million for the corresponding period in 2016. The decrease 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, partially offset by a decrease in depreciation. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information regarding the 2017 Rate Case Settlement Agreement.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

First Quarter 2017 vs. First Quarter 2016
(change in millions)		(% change)
$(4)		(1.4)

In the first quarter 2017, retail revenues were $279 million compared to $283 million for the corresponding period in 2016.

Details of the changes in retail revenues were as follows:

	First Quarter 2017
	(in millions)				(% change)
Retail – prior year	$	283
Estimated change resulting from –
Rates and pricing	1				0.4
Sales decline	(2		)		(0.7	)
Weather	(5		)		(1.8	)
Fuel and other cost recovery	2				0.7
Retail – current year	$	279			(1.4	)%

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

Revenues associated with changes in rates and pricing increased in the first quarter 2017 when compared to the corresponding period in 2016 primarily due to an increase in the environmental cost recovery clause 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 first quarter 2017 when compared to the corresponding period in 2016. For the first quarter 2017, weather-adjusted KWH sales to residential and commercial customers decreased 1.5% and 0.7%, respectively, 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 8.8% for the first quarter 2017 primarily due to increased customer co-generation.

Fuel and other cost recovery revenues increased in the first quarter 2017 when compared to the corresponding period in 2016, primarily due to higher recoverable costs under Gulf Power's environmental cost recovery clause, partially offset by lower recoverable costs under Gulf Power's fuel cost recovery and purchased power capacity cost recovery clauses. 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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Affiliates

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

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

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

Fuel and Purchased Power Expenses

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

In the first quarter 2017, total fuel and purchased power expenses were $142 million compared to $126 million for the corresponding period in 2016. The increase was primarily the result of a $10 million net increase related to the volume of KWHs generated and purchased due to higher generation from Gulf Power's coal-fired units and a $6 million net increase due to the higher average cost of fuel and purchased power for Gulf Power's gas-fired PPA resource.

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

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

	First Quarter 2017		First Quarter 2016
Total generation (in millions of KWHs)	2,322		1,816
Total purchased power (in millions of KWHs)	1,459		1,760
Sources of generation (percent) –
Coal	53		42
Gas	47		58
Cost of fuel, generated (in cents per net KWH) –
Coal	3.27		3.92
Gas	3.24		3.75
Average cost of fuel, generated (in cents per net KWH)	3.26		3.82
Average cost of purchased power (in cents per net KWH)(*)	4.57		3.22

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

Fuel

In the first quarter 2017, fuel expense was $108 million compared to $94 million for the corresponding period in 2016. The increase was primarily due to a 60.9% increase in the volume of KWHs generated by Gulf Power's coal-fired generation resources due to system reliability requirements, partially offset by a 14.7% decrease in the average cost of fuel resulting from lower coal and natural gas prices.

Purchased Power – Non-Affiliates

In the first quarter 2017, purchased power expense from non-affiliates was $32 million compared to $30 million for the corresponding period in 2016. The increase was primarily due to a 39.0% increase in the average cost per KWH purchased primarily resulting from higher fuel costs associated with external purchases, partially offset by a 14.8% decrease in the volume of KWHs purchased due to increased Gulf Power generation.

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.

Other Operations and Maintenance Expenses

First Quarter 2017 vs. First Quarter 2016
(change in millions)		(% change)
$7		9.1

In the first quarter 2017, other operations and maintenance expenses were $84 million compared to $77 million for the corresponding period in 2016. The increase was primarily due to expenses at generating facilities associated with environmental compliance and routine and planned maintenance.

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

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Depreciation and Amortization

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

In the first quarter 2017, depreciation and amortization was $18 million compared to $38 million for the corresponding period in 2016. The decrease was primarily due to $20 million more of a reduction in depreciation in the first quarter 2017 compared to the corresponding period in 2016, as authorized in a settlement agreement approved by the Florida PSC in 2013 (2013 Rate Case Settlement Agreement). See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information.

Income Taxes

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

In the first quarter 2017, income taxes were $14 million compared to $20 million for the corresponding period in 2016. This change was primarily due to the income tax benefit associated with the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with the 2017 Rate Case Settlement Agreement. This decrease was partially offset by higher pre-tax earnings, excluding the write-down. See 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 tax reform legislation are primarily focused on reducing the corporate income tax rate, allowing 100% of capital expenditures to be deducted, and eliminating the interest deduction. The ultimate impact of any tax reform proposals is dependent on the final form of any legislation enacted and the related transition rules and cannot be determined at this time, but could have a material impact on Gulf Power's financial statements. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in retail rates or through long-term wholesale agreements on a timely

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

Environmental Statutes and Regulations

Water Quality

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

On March 1, 2017, the EPA and the U.S. Army Corps of Engineers released a notice of intent to review and rescind or further revise the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.

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

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

Global Climate Issues

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

On March 28, 2017, the 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. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

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

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Retail Base Rate Cases

The 2013 Rate Case Settlement Agreement authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction may not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. For 2014 and 2015, Gulf Power recognized reductions in depreciation of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016. In the first quarter 2017, Gulf Power recognized reductions in depreciation totaling $25.5 million. The 2013 Rate Case Settlement Agreement remains in effect through June 30, 2017.

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

Cost Recovery Clauses

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

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

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

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have a material effect on Gulf Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

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

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While Gulf Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Gulf Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, Gulf Power expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.

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

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Gulf Power must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Gulf Power has not elected its transition method.

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

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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 March 31, 2017. Gulf Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $50 million for the first three months of 2017 compared to $132 million for the corresponding period in 2016. The $82 million decrease in net cash was primarily due to a federal income tax refund received in 2016, as well as decreases in cash flows associated with accrued taxes, cost recovery clauses as a result of decreased revenue collection, and changes in accounts receivable in 2017 compared to 2016. Net cash used for investing activities totaled $57 million in the first three months of 2017 primarily due to property additions to utility plant. Net cash used for financing activities totaled $17 million for the first three months of 2017 primarily due to a decrease in notes payable and the payment of common stock dividends, partially offset by proceeds from the issuance of common stock. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2017 include an increase in common stock of $175 million, a decrease in notes payable of $168 million, primarily funded with the common stock issuance, 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 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, preference stock dividends, purchase commitments, and trust funding requirements. Approximately $92 million will be required through March 31, 2018 to fund maturities of long-term debt. See "Financing Activities" herein for additional information.

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

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Sources of Capital

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

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

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

Expires																Executable Term Loans								Expires Within One Year
2017				2018				Total				Unused				One Year				Two Years				Term Out				No Term Out
(in millions)
$	85			$	195			$	280			$	280			$	45			$	—			$	25			$	70

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 March 31, 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 March 31, 2017 was approximately $82 million. In addition, at March 31, 2017, Gulf Power had approximately $86 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.

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

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Details of short-term borrowings were as follows:

		Short-term Debt at March 31, 2017							Short-term Debt During the Period(*)
		Amount Outstanding				Weighted Average Interest Rate			Average Amount Outstanding				Weighted Average Interest Rate			Maximum Amount Outstanding
		(in millions)							(in millions)							(in millions)
Commercial paper		$	—			—	%		$	29			1.1	%		$	168
Short-term bank debt		100				1.7	%		100				1.5	%		100
Total		$	100			1.7	%		$	129			1.4	%

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

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

Credit Rating Risk

At March 31, 2017, Gulf Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

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

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

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	167
Below BBB- and/or Baa3	$	564

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 first quarter 2017 has not changed materially compared to the December 31, 2016 reporting period. Gulf Power's exposure to market volatility in commodity fuel prices and prices of electricity with respect to its wholesale generating capacity had been limited because its long-term sales agreements shifted substantially all fuel cost responsibility to the purchaser. However, Gulf Power is exposed to market volatility in energy-related commodity prices to the extent any wholesale generating capacity is uncontracted.

In connection with the 2017 Rate Case Settlement Agreement, Gulf Power recorded a $32.5 million write-down of Gulf Power's ownership of Plant Scherer Unit 3 in the first quarter 2017 to resolve the inclusion of Gulf Power's investment in Plant Scherer Unit 3 in retail rates and no adjustment to the environmental cost recovery clause rate

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approved by the Florida PSC in November 2016 was made. The 2017 Rate Case Settlement Agreement provides that 100% of Gulf Power's ownership of Plant Scherer Unit 3 will be included in retail rates. This resolves 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.

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.

In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm recovery, Gulf Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. In particular, Gulf Power may, subject to applicable market conditions, call for redemption and refinance all or a portion of its $150 million aggregate outstanding preference stock during 2017.

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CONDENSED STATEMENTS OF INCOME (UNAUDITED)

 

	For the Three Months Ended March 31,
	2017				2016
	(in millions)
Operating Revenues:
Retail revenues	$	200			$	183
Wholesale revenues, non-affiliates	62				60
Wholesale revenues, affiliates	5				9
Other revenues	5				5
Total operating revenues	272				257
Operating Expenses:
Fuel	78				76
Purchased power, non-affiliates	1				—
Purchased power, affiliates	7				5
Other operations and maintenance	74				69
Depreciation and amortization	40				38
Taxes other than income taxes	26				26
Estimated loss on Kemper IGCC	108				53
Total operating expenses	334				267
Operating Loss	(62		)		(10		)
Other Income and (Expense):
Allowance for equity funds used during construction	35				29
Interest expense, net of amounts capitalized	(19		)		(16		)
Other income (expense), net	(1		)		(2		)
Total other income and (expense)	15				11
Earnings (Loss) Before Income Taxes	(47		)		1
Income taxes (benefit)	(27		)		(10		)
Net Income (Loss)	(20		)		11
Dividends on Preferred Stock	—				—
Net Income (Loss) After Dividends on Preferred Stock	$	(20	)		$	11

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2017				2016
	(in millions)
Net Income (Loss)	$	(20	)		$	11
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)	$	(19	)		$	11

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 Three Months Ended March 31,
	2017				2016
	(in millions)
Operating Activities:
Net income (loss)	$	(20	)		$	11
Adjustments to reconcile net income to net cash used for operating activities —
Depreciation and amortization, total	49				39
Deferred income taxes	(47		)		(4		)
Allowance for equity funds used during construction	(35		)		(29		)
Estimated loss on Kemper IGCC	108				53
Other, net	(3		)		(4		)
Changes in certain current assets and liabilities —
-Other current assets	18				43
-Accounts payable	(35		)		(22		)
-Accrued taxes	(46		)		(60		)
-Accrued compensation	(22		)		(16		)
-Over recovered regulatory clause revenues	(12		)		9
-Customer liability associated with Kemper refunds	—				(51		)
-Other current liabilities	5				8
Net cash used for operating activities	(40		)		(23		)
Investing Activities:
Property additions	(186		)		(197		)
Construction payables	—				(7		)
Payments pursuant to LTSAs	1				(5		)
Other investing activities	(5		)		(5		)
Net cash used for investing activities	(190		)		(214		)
Financing Activities:
Increase in notes payable, net	9				—
Proceeds —
Long-term debt to parent company	—				200
Other long-term debt	—				900
Short-term borrowings	4				—
Redemptions —
Short-term borrowings	—				(475		)
Other long-term debt	—				(425		)
Other financing activities	(1		)		(2		)
Net cash provided from financing activities	12				198
Net Change in Cash and Cash Equivalents	(218		)		(39		)
Cash and Cash Equivalents at Beginning of Period	224				98
Cash and Cash Equivalents at End of Period	$	6			$	59
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $25 and $22, net of $12 and $10 capitalized for 2017 and 2016, respectively)	$	13			$	12
Income taxes, net	—				(24		)
Noncash transactions — Accrued property additions at end of period	78				97

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 March 31, 2017				At December 31, 2016
		(in millions)
Current Assets:
Cash and cash equivalents		$	6			$	224
Receivables —
Customer accounts receivable		26				29
Unbilled revenues		38				42
Income taxes receivable, current		544				544
Other accounts and notes receivable		17				14
Affiliated		14				15
Fossil fuel stock		83				100
Materials and supplies		78				76
Other regulatory assets, current		113				115
Other current assets		3				8
Total current assets		922				1,167
Property, Plant, and Equipment:
In service		4,963				4,865
Less: Accumulated provision for depreciation		1,303				1,289
Plant in service, net of depreciation		3,660				3,576
Construction work in progress		2,570				2,545
Total property, plant, and equipment		6,230				6,121
Other Property and Investments		12				12
Deferred Charges and Other Assets:
Deferred charges related to income taxes		382				361
Other regulatory assets, deferred		520				518
Other deferred charges and assets		22				56
Total deferred charges and other assets		924				935
Total Assets		$	8,088			$	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 March 31, 2017				At December 31, 2016
		(in millions)
Current Liabilities:
Securities due within one year —
Parent		$	—			$	551
Other		1,328				78
Notes payable		36				23
Accounts payable —
Affiliated		44				62
Other		112				135
Customer deposits		16				16
Accrued taxes		51				99
Unrecognized tax benefits		385				383
Accrued interest		50				46
Accrued compensation		20				42
Asset retirement obligations, current		27				32
Over recovered regulatory clause liabilities		39				51
Other current liabilities		22				20
Total current liabilities		2,130				1,538
Long-term Debt:
Long-term debt to parent		551				—
Long-term debt, non-affiliated		1,172				2,424
Total Long-term Debt		1,723				2,424
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		729				756
Employee benefit obligations		113				115
Asset retirement obligations, deferred		148				146
Other cost of removal obligations		172				170
Other regulatory liabilities, deferred		78				84
Other deferred credits and liabilities		36				26
Total deferred credits and other liabilities		1,276				1,297
Total Liabilities		5,129				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		3,526				3,525
Accumulated deficit		(635		)		(616		)
Accumulated other comprehensive loss		(3		)		(4		)
Total common stockholder's equity		2,926				2,943
Total Liabilities and Stockholder's Equity		$	8,088			$	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

FIRST QUARTER 2017 vs. FIRST QUARTER 2016

OVERVIEW

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

Many factors affect the opportunities, challenges, and risks of Mississippi Power's business of providing electric service. These factors include Mississippi Power's ability to maintain and grow energy sales and to operate in a constructive regulatory environment that provides timely recovery of prudently-incurred costs. These costs include those related to the completion and operation of the Kemper IGCC, 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.

Mississippi Power continues to progress toward completing the construction and start-up of the Kemper IGCC, which was approved by the Mississippi PSC in the 2010 CPCN proceedings, subject to a construction cost cap of $2.88 billion, net of $245 million of 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 current cost estimate for the Kemper IGCC in total is approximately $7.16 billion, which includes approximately $5.75 billion of costs subject to the construction cost cap and is net of the $137 million in additional grants from the DOE received on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts to customers. Mississippi Power does not intend to seek any rate recovery for any related costs that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate subject to the construction cost cap totaling $108 million ($67 million after tax) in the first quarter 2017. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.87 billion ($1.77 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2017. The current cost estimate includes costs through May 31, 2017, as well as identified costs to be incurred beyond May 31, 2017, expected to be subject to the $2.88 billion cost cap. Additional improvement projects to enhance plant performance, safety, and/or operations ultimately may be completed after the remainder of the Kemper IGCC is placed in service. These projects have yet to be fully evaluated, have not been included in the current cost estimate, and may be subject to the $2.88 billion cost cap.

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation (2015 Stipulation) between Mississippi Power and the Mississippi Public Utilities Staff (MPUS), authorizing rates that provide for the recovery of approximately $126 million annually related to the combined cycle and associated common facilities portion of Kemper IGCC assets previously placed in service. Upon placing the remainder of the plant in service, Mississippi Power will be focused primarily on completing the regulatory cost recovery process.

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

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

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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

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

RESULTS OF OPERATIONS

Net Income (Loss)

First Quarter 2017 vs. First Quarter 2016
(change in millions)		(% change)
$(31)		N/M

N/M - Not meaningful

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

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

Retail Revenues

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

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

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Details of the changes in retail revenues were as follows:

	First Quarter 2017
	(in millions)				(% change)
Retail – prior year	$	183
Estimated change resulting from –
Rates and pricing	12				6.6
Sales growth (decline)	4				2.1
Weather	(5		)		(2.7	)
Fuel and other cost recovery	6				3.3
Retail – current year	$	200			9.3	%

Revenues associated with changes in rates and pricing increased in the first quarter 2017 when compared to the corresponding period in 2016, primarily due to an ECO Plan rate increase implemented in the third quarter 2016.

Revenues attributable to changes in sales increased for the first quarter 2017 when compared to the corresponding period in 2016. Weather-adjusted KWH sales to residential customers increased 1.3% due to higher customer usage offset by a decline in the number of customers. Weather-adjusted KWH sales to commercial customers decreased 0.1% due to lower customer usage offset by customer growth. KWH sales to industrial customers increased 0.6% primarily due to an unplanned outage by a large customer in 2016.

Fuel and other cost recovery revenues increased in the first quarter 2017 when compared to the corresponding period in 2016, primarily as a result of higher recoverable fuel costs. See "Fuel and Purchased Power Expenses" herein for additional information. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.

Wholesale Revenues – Affiliates

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

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

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

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Fuel and Purchased Power Expenses

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

N/M - Not meaningful

In the first quarter 2017, total fuel and purchased power expenses were $86 million compared to $81 million for the corresponding period in 2016. The increase was due to a $15 million increase in natural gas prices offset by a $10 million net decrease in the volume of KWHs generated and purchased.

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

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

	First Quarter 2017		First Quarter 2016
Total generation (in millions of KWHs)	3,161		3,588
Total purchased power (in millions of KWHs)	242		261
Sources of generation (percent) –
Coal	9		11
Gas	91		89
Cost of fuel, generated (in cents per net KWH) –
Coal	3.33		3.55
Gas	2.65		2.15
Average cost of fuel, generated (in cents per net KWH)	2.71		2.32
Average cost of purchased power (in cents per net KWH)	3.33		2.17

Fuel

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

Purchased Power - Affiliates

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

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, as approved by the FERC.

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Other Operations and Maintenance Expenses

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

In the first quarter 2017, other operations and maintenance expenses were $74 million compared to $69 million for the corresponding period in 2016. The increase was primarily due to a $3 million increase in amortization of prior operations and maintenance expense deferrals associated with the Kemper IGCC in-service assets and a $2 million increase in generation maintenance expenses, including scheduled outages.

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

Estimated Loss on Kemper IGCC

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

N/M - Not meaningful

In the first quarters of 2017 and 2016, estimated probable losses on the Kemper IGCC of $108 million and $53 million, respectively, were recorded at Mississippi Power. These losses reflect revisions of estimated costs expected to be incurred on the construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions.

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.

Allowance for Equity Funds Used During Construction

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

In the first quarter 2017, AFUDC equity was $35 million compared to $29 million for the corresponding period in 2016. The increase resulted from a higher AFUDC rate and an increase in Kemper IGCC CWIP subject to AFUDC.

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

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Interest Expense, Net of Amounts Capitalized

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

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

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

Income Taxes (Benefit)

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

N/M - Not meaningful

In the first quarter 2017, income tax benefit was $27 million compared to $10 million for the corresponding period in 2016. The change was primarily due to the increase in the estimated probable losses on construction of the Kemper IGCC.

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

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Mississippi Power's future earnings potential. The level of Mississippi Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Mississippi Power's business of providing electric service. These factors include Mississippi Power's ability to recover its prudently-incurred costs, including those related to the remainder of the Kemper IGCC costs not included in current rates, in a timely manner during a time of increasing costs, its ability to prevail against legal challenges associated with the Kemper IGCC, and the completion and subsequent operation of the Kemper IGCC in accordance with any operational parameters that may be adopted by the Mississippi PSC. 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.

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

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

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 rule revising the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs and the final effluent guidelines rule.

On March 1, 2017, the EPA and the U.S. Army Corps of Engineers released a notice of intent to review and rescind or further revise the final rule that revised the regulatory definition of waters of the U.S. for all CWA programs. The final rule has been stayed since October 2015 by the U.S. Court of Appeals for the Sixth Circuit.

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

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

Global Climate Issues

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

On March 28, 2017, the 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. The ultimate outcome of this matter cannot be determined at this time.

FERC Matters

Municipal and Rural Associations Tariff

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

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to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's construction of 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 is estimated to be approximately $18 million until the end of May 2017 when the Kemper IGCC is projected to be placed in service.

Retail Regulatory Matters

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

Renewables

Of the three solar projects expected to be in service in 2017, one was placed in service in the first quarter 2017, while the remaining two are expected to be placed in service in June and July 2017. Mississippi Power may retire the renewable energy credits (REC) generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.

Performance Evaluation Plan

On March 15, 2017, Mississippi Power submitted its annual PEP lookback filing for 2016, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time.

Energy Efficiency

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

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Fuel Cost Recovery

At March 31, 2017, the amount of over-recovered retail fuel costs included on the condensed balance sheet was $27 million compared to $37 million at December 31, 2016.

Ad Valorem Tax Adjustment

On April 7, 2017, Mississippi Power submitted its annual ad valorem tax adjustment factor filing for 2017, which included an annual rate increase of 0.85%, or $8 million in annual retail revenues, primarily due to increased assessments. The ultimate outcome of this matter cannot be determined at this time.

Integrated Coal Gasification Combined Cycle

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

Kemper IGCC Overview

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

Kemper IGCC Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of Initial DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014. The remainder of the plant, including the gasifiers and the gas clean-up facilities, represents first-of-a-kind technology. The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. Mississippi Power continues to work toward achieving sustained operation sufficient to place the remainder of the plant in service. The plant has, however, produced and captured CO₂, and has produced sulfuric acid and ammonia, all of acceptable quality under the related off-take agreements. As a result of ongoing challenges associated with the ash removal and gas cleanup sour water systems, efforts to improve reliability and reach sustained operation of both gasifiers and production of electricity from syngas in both combustion turbines remain in process. Mississippi Power currently expects the remainder of the Kemper IGCC, including both gasifiers, will be placed in service by the end of May 2017. The schedule reflects the expected time needed to repair a leak in one of the particulate control devices for gasifier "A," make other minor modifications to each gasifier's ash removal systems, repair the sour water system, and establish sustained operation of both gasifiers for the production of electricity from syngas.

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

Cost Category	2010 Project Estimate(a)				Current Cost Estimate(b)				Actual Costs
	(in billions)
Plant Subject to Cost Cap(c)(e)	$	2.40			$	5.75			$	5.57
Lignite Mine and Equipment	0.21				0.23				0.23
CO2 Pipeline Facilities	0.14				0.12				0.12
AFUDC(d)	0.17				0.83				0.80
Combined Cycle and Related Assets Placed in Service – Incremental(e)	—				0.05				0.04
General Exceptions	0.05				0.10				0.09
Deferred Costs(e)	—				0.22				0.22
Additional DOE Grants	—				(0.14		)		(0.14		)
Total Kemper IGCC(f)	$	2.97			$	7.16			$	6.93

(a)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions.

(b)	Amounts in the Current Cost Estimate include certain estimated post-in-service costs which are expected to be subject to the cost cap.

(c)

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

(d)

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

(e)

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

(f)

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

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

Mississippi Power does not intend to seek rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $108 million ($67 million

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after tax) in the first quarter 2017. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.87 billion ($1.77 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2017. The increase to the cost estimate in the first quarter 2017 primarily reflects $67 million for the extension of the Kemper IGCC's projected in-service date from mid-March 2017 to the end of May 2017, $23 million related to start-up fuel, and $18 million primarily related to outage maintenance and operational improvements.

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

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

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

Rate Recovery of Kemper IGCC Costs

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

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

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

Of these amounts, approximately 29% is related to wholesale and approximately 71% is related to retail, including the 15% portion that was previously contracted to be sold to SMEPA. Mississippi Power and its wholesale customers have generally agreed to similar regulatory treatment for wholesale tariff purposes as approved by the Mississippi PSC for retail for Kemper IGCC-related costs. See "FERC Matters – Municipal and Rural Associations Tariff" and "Termination of Proposed Sale of Undivided Interest" herein for further information.

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 will not seek recovery of the $68 million in additional estimated costs from customers if incurred.

Mississippi Power responded to numerous requests for information from interested parties in the discovery docket, which is now complete. Mississippi Power expects the Mississippi PSC to address these matters in connection with the 2017 Rate Case.

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Economic Viability Analysis

In the fourth quarter 2016, as a part of its Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected.

As a result of the updated long-term natural gas forecast, as well as the revised operating expense projections reflected in the discovery docket filings discussed above, on February 21, 2017, Mississippi Power filed an updated project economic viability analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order confirming authorization of the Kemper IGCC. The project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis.

Mississippi Power expects the Mississippi PSC to address this matter in connection with the 2017 Rate Case.

2017 Rate Case

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

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

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

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

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

2015 Rate Case

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

On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full the 2015 Stipulation entered into between Mississippi Power and the MPUS regarding the In-Service Asset Proposal. 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. Mississippi Power is required to file the 2017 Rate Case by June 3, 2017.

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

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

On February 12, 2015, the Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public

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notice for the related proceedings. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million collected under the 2013 MPSC Rate Order, along with associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation described above.

Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC. Through March 31, 2017, AFUDC recorded since the original May 2014 estimated in-service date for the Kemper IGCC has totaled $445 million, which will continue to accrue at approximately $16 million per month until the remainder of the plant is placed in service. Mississippi Power has not recorded any AFUDC on Kemper IGCC costs in excess of the $2.88 billion cost cap, except for Cost Cap Exception amounts.

2012 MPSC CPCN Order

The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters including availability factor, heat rate, lignite heat content, and chemical revenue based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with the 2017 Rate Case and future proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Mississippi Power's financial statements. See "Prudence" herein for additional information.

Regulatory Assets and Liabilities

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

In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015 and the second quarter 2016, in connection with the implementation of retail and wholesale rates, respectively, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs (associated with assets placed in service and other non-CWIP accounts) that previously were deferred as regulatory assets and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of March 31, 2017, the balance associated with these regulatory assets was $86 million, of which $24 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $111 million as of March 31, 2017. The amortization period for these assets is expected to be determined by the Mississippi PSC in the 2017 Rate Case. See "FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.

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

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

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

Lignite Mine and CO₂ Pipeline Facilities

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

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

In addition, Mississippi Power has constructed and will operate the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery. Mississippi Power entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC (Treetop), pursuant to which Denbury would purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop would purchase 30% of the CO₂ captured from the Kemper IGCC. On June 3, 2016, Mississippi Power cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury's agreement to purchase 100% of the CO₂ captured from the Kemper IGCC, an initial contract term of 16 years, and termination rights if Mississippi Power has not satisfied its contractual obligation to deliver captured CO₂ by July 1, 2017, in addition to Denbury's existing termination rights in the event of a change in law, force majeure, or an event of default by Mississippi Power. Any termination or material modification of the agreement with Denbury could impact the operations of the Kemper IGCC and result in a material reduction in Mississippi Power's revenues to the extent Mississippi Power is not able to enter into other similar contractual arrangements or otherwise sequester the CO₂ produced. Additionally, sustained oil price reductions could result in significantly lower revenues than Mississippi Power originally forecasted to be available to offset customer rate impacts, which could have a material impact on Mississippi Power's financial statements.

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 matures on July 31, 2018.

Litigation

On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. On August 12, 2016, Southern Company and Mississippi Power removed the case to the U.S. District Court for the Southern District of Mississippi. The plaintiffs filed a request to remand the case back to state court, which was granted on

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November 17, 2016. The individual plaintiff, John Carlton Dean, alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On December 7, 2016, Southern Company and Mississippi Power filed motions to dismiss, which the Circuit Court is expected to address in the second quarter 2017.

On June 9, 2016, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO₂ contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS have moved to compel arbitration pursuant to the terms of the CO₂ contract, which the court is expected to address in the second quarter 2017.

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. See "Rate Recovery of Kemper IGCC Costs" herein for additional information.

Income Tax Matters

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

Other Matters

Mississippi Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has

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

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

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Kemper IGCC Estimated Construction Costs, Project Completion Date, and Rate Recovery

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

As a result of revisions to the cost estimate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC subject to the construction cost cap of $108 million ($67 million after tax) in the first quarter 2017, $127 million ($78 million after tax) in the fourth quarter 2016, $88 million ($54 million after tax) in the third quarter 2016, $81 million ($50 million after tax) in the second quarter 2016, $53 million ($33 million after tax) in the first quarter 2016, $183 million ($113 million after tax) in the fourth quarter 2015, $150 million ($93 million after tax) in the third quarter 2015, $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, $462 million ($285 million after tax) in the first quarter 2013, and $78 million ($48 million after tax) in the fourth quarter

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2012. In the aggregate, Mississippi Power has incurred charges of $2.87 billion ($1.77 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2017.

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

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

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

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

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

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

Given the significant judgment involved in estimating the future costs to complete construction and start-up, the project completion date, the ultimate rate recovery for the Kemper IGCC, and the potential impact on Mississippi Power's results of operations, Mississippi Power considers these items to be critical accounting estimates. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Recently Issued Accounting Standards

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While Mississippi Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Mississippi Power's revenue, including energy provided to customers, is from tariff offerings that provide electricity without a defined contractual term. For such arrangements, Mississippi Power expects that the revenue from contracts with these customers will continue to be equivalent to the electricity supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.

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

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Mississippi Power must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Mississippi Power has not elected its transition method.

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

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service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. Mississippi Power is currently evaluating the new standard. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Mississippi Power's operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Mississippi Power's financial statements.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Earnings for the three months ended March 31, 2017 were negatively affected by revisions to the cost estimate for the Kemper IGCC.

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

On February 28, 2017, the maturity dates for $551 million in promissory notes to Southern Company were extended to July 31, 2018. As of March 31, 2017, the amount of outstanding promissory notes to Southern Company totaled $551 million.

As of March 31, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $1.2 billion primarily due to a $1.2 billion unsecured term loan that matures on March 30, 2018 and $35 million in senior notes that mature on November 15, 2017, as well as $36 million of short-term notes payable, $40 million of tax-exempt variable rate demand obligations, and $50 million of pollution control bonds that are required to be remarketed over the next 12 months. Subsequent to March 31, 2017, Mississippi Power borrowed an additional $10 million under a promissory note to Southern Company, which was amended and restated in February 2017. Mississippi Power expects the funds needed to satisfy maturing debt obligations will exceed amounts available from operating cash flows, lines of credit, and other external sources. Accordingly, Mississippi Power intends to satisfy these obligations through loans and/or equity contributions from Southern Company. Specifically, Mississippi Power has been informed by Southern Company that, in the event sufficient funds are not available from external sources, Southern Company intends to provide Mississippi Power with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power, consistent with GAAP. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Going Concern" herein.

Net cash used for operating activities totaled $40 million for the first three months of 2017, an increase of $17 million as compared to the corresponding period in 2016. The increase in cash used for operating activities is primarily due to lower income tax benefits related to the Kemper IGCC and current assets, primarily due to receivables, partially offset by the completion of Mirror CWIP and subsequent refunds in 2016. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" herein for additional information. Net cash used for investing activities totaled $190 million for the first three months of 2017 primarily due to gross property additions related to the Kemper IGCC. Net cash provided from financing activities totaled $12 million for the first three months of 2017 primarily due to an increase in notes

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payable and short-term borrowings. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2017 include a $218 million decrease in cash and cash equivalents and an increase in current liabilities and a decrease in long-term debt primarily resulting from the $1.2 billion unsecured term loan agreement being reclassified from long-term debt to securities due within one year. These changes are partially offset by $551 million of promissory notes to Southern Company being reclassified from current to long-term debt as a result of the maturity dates being extended to July 31, 2018 and an increase in total property, plant, and equipment of $109 million primarily due to the Kemper IGCC. Other significant changes include a decrease in accrued taxes of $48 million primarily due to ad valorem tax payments.

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 obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. Approximately $1.2 billion will be required through March 31, 2018 to fund maturities of long-term debt and $36 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 pollution control revenue bonds that are required to be remarketed over the next 12 months. See "Sources of Capital" herein for additional information.

The construction program of Mississippi Power is currently estimated to be $659 million for 2017, $241 million for 2018, $274 million for 2019, $305 million for 2020, $230 million for 2021, and $289 million for 2022, which includes completion of the Kemper IGCC and post-in-service costs. Expenditures related to the completion of the Kemper IGCC are currently estimated to be $395 million for 2017. 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.

In addition, the construction program includes the development and construction of the Kemper IGCC, a first-of-a-kind technology, which may result in revised estimates during construction. The ability to control costs and avoid cost overruns during the development and construction of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, sustaining nitrogen supply, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).

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

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Sources of Capital

The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which includes resolution of Kemper IGCC 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. As of March 31, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $1.2 billion primarily due to a $1.2 billion unsecured term loan that matures on March 30, 2018 and $35 million in senior notes that mature on November 15, 2017, as well as $36 million of short-term notes payable, $40 million of tax-exempt variable rate demand obligations, and $50 million of pollution control bonds that are required to be remarketed over the next 12 months. Subsequent to March 31, 2017, Mississippi Power borrowed an additional $10 million under a promissory note to Southern Company. Mississippi Power expects the funds needed to satisfy maturing debt obligations will exceed amounts available from operating cash flows, lines of credit, and other external sources. Accordingly, Mississippi Power intends to satisfy these obligations through loans and/or equity contributions from Southern Company. Specifically, Mississippi Power has been informed by Southern Company that, in the event sufficient funds are not available from external sources, Southern Company intends to provide Mississippi Power with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power, consistent with GAAP. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Going Concern" herein.

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

At March 31, 2017, Mississippi Power had approximately $6 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 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)
$	173			$	173			$	141			$	—			$	13			$	13			$	160

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 March 31, 2017,

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Mississippi Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.

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

A portion of the $141 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2017 was approximately $40 million. In addition, at March 31, 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 March 31, 2017						Short-term Debt During the Period(*)
		Amount Outstanding				Weighted Average Interest Rate		Average Amount Outstanding				Weighted Average Interest Rate		Maximum Amount Outstanding
		(in millions)						(in millions)						(in millions)
Short-term bank debt		$	36			3.4%		$	25			2.7%		$	36

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

Credit Rating Risk

At March 31, 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 sales, fuel transportation and storage, energy price risk management, and transmission. At March 31, 2017, the maximum potential collateral requirements under these contracts at a rating of BBB and/or Baa2 or BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $233 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.

Financing Activities

On February 28, 2017, Mississippi Power amended $551 million in promissory notes to Southern Company extending the maturity dates of the notes from December 1, 2017 to July 31, 2018. Subsequent to March 31, 2017, Mississippi Power borrowed an additional $10 million under a promissory note issued to Southern Company.

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On March 31, 2017, Mississippi Power issued a $9 million short-term note bearing interest at 5% per annum, which was repaid on April 27, 2017.

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AND SUBSIDIARY COMPANIES

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

 

	For the Three Months Ended March 31,
	2017				2016
	(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	347			$	215
Wholesale revenues, affiliates	100				97
Other revenues	3				3
Total operating revenues	450				315
Operating Expenses:
Fuel	132				91
Purchased power, non-affiliates	25				13
Purchased power, affiliates	5				6
Other operations and maintenance	92				79
Depreciation and amortization	119				73
Taxes other than income taxes	12				6
Total operating expenses	385				268
Operating Income	65				47
Other Income and (Expense):
Interest expense, net of amounts capitalized	(50		)		(21		)
Other income (expense), net	(1		)		2
Total other income and (expense)	(51		)		(19		)
Earnings Before Income Taxes	14				28
Income taxes (benefit)	(52		)		(23		)
Net Income	66				51
Less: Net income (loss) attributable to noncontrolling interests	(4		)		1
Net Income Attributable to Southern Power	$	70			$	50

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 

	For the Three Months Ended March 31,
	2017				2016
	(in millions)
Net Income	$	66			$	51
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(4) and $-, respectively	(8		)		—
Reclassification adjustment for amounts included in net income, net of tax of $(3) and $-, respectively	(4		)		1
Total other comprehensive income (loss)	(12		)		1
Less: Comprehensive income (loss) attributable to noncontrolling interests	(4		)		1
Comprehensive Income Attributable to Southern Power	$	58			$	51

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 Three Months Ended March 31,
	2017				2016
	(in millions)
Operating Activities:
Net income	$	66			$	51
Adjustments to reconcile net income to net cash provided from (used for) operating activities —
Depreciation and amortization, total	127				75
Deferred income taxes	36				(132		)
Amortization of investment tax credits	(14		)		(7		)
Deferred revenues	(27		)		(26		)
Other, net	5				9
Changes in certain current assets and liabilities —
-Receivables	(7		)		(3		)
-Prepaid income taxes	(21		)		(31		)
-Other current assets	(6		)		1
-Accounts payable	(38		)		(12		)
-Accrued taxes	(40		)		(37		)
-Other current liabilities	15				2
Net cash provided from (used for) operating activities	96				(110		)
Investing Activities:
Business acquisitions	(1,020		)		(114		)
Property additions	(69		)		(767		)
Change in construction payables	(125		)		31
Payments pursuant to LTSAs	(31		)		(25		)
Investment in restricted cash	(13		)		(289		)
Distribution of restricted cash	26				292
Other investing activities	(3		)		(1		)
Net cash used for investing activities	(1,235		)		(873		)
Financing Activities:
Increase in notes payable, net	171				276
Distributions to noncontrolling interests	(18		)		(4		)
Capital contributions from noncontrolling interests	71				131
Purchase of membership interests from noncontrolling interests	—				(129		)
Payment of common stock dividends	(79		)		(68		)
Other financing activities	(12		)		—
Net cash provided from financing activities	133				206
Net Change in Cash and Cash Equivalents	(1,006		)		(777		)
Cash and Cash Equivalents at Beginning of Period	1,099				830
Cash and Cash Equivalents at End of Period	$	93			$	53
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $2 and $10 capitalized for 2017 and 2016, respectively)	$	28			$	15
Income taxes, net	(1		)		188
Noncash transactions — Accrued property additions at end of period	53				262

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

 

Assets		At March 31, 2017				At December 31, 2016
		(in millions)
Current Assets:
Cash and cash equivalents		$	93			$	1,099
Receivables —
Customer accounts receivable		111				102
Other accounts receivable		32				34
Affiliated		62				57
Fossil fuel stock		14				15
Materials and supplies		343				337
Prepaid income taxes		95				74
Other current assets		31				39
Total current assets		781				1,757
Property, Plant, and Equipment:
In service		13,493				12,728
Less: Accumulated provision for depreciation		1,598				1,484
Plant in service, net of depreciation		11,895				11,244
Construction work in progress		328				398
Total property, plant, and equipment		12,223				11,642
Other Property and Investments:
Intangible assets, net of amortization of $28 and $22 at March 31, 2017 and December 31, 2016, respectively		430				436
Total other property and investments		430				436
Deferred Charges and Other Assets:
Prepaid LTSAs		120				101
Accumulated deferred income taxes		570				594
Other deferred charges and assets — affiliated		26				13
Other deferred charges and assets — non-affiliated		531				626
Total deferred charges and other assets		1,247				1,334
Total Assets		$	14,681			$	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 March 31, 2017				At December 31, 2016
		(in millions)
Current Liabilities:
Securities due within one year		$	560			$	560
Notes payable		380				209
Accounts payable —
Affiliated		76				88
Other		129				278
Accrued taxes —
Accrued income taxes		48				148
Other accrued taxes		13				7
Accrued interest		47				36
Acquisitions payable		—				461
Contingent consideration		14				46
Other current liabilities		69				70
Total current liabilities		1,336				1,903
Long-term Debt		5,088				5,068
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		157				152
Accumulated deferred investment tax credits		1,879				1,839
Asset retirement obligations		67				64
Other deferred credits and liabilities		288				304
Total deferred credits and other liabilities		2,391				2,359
Total Liabilities		8,815				9,330
Redeemable Noncontrolling Interests		164				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		714				724
Accumulated other comprehensive income		24				35
Total common stockholder's equity		4,409				4,430
Noncontrolling interests		1,293				1,245
Total stockholders' equity		5,702				5,675
Total Liabilities and Stockholders' Equity		$	14,681			$	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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FIRST QUARTER 2017 vs. FIRST QUARTER 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 three months ended March 31, 2017, Southern Power acquired or completed the construction of, and placed in service, approximately 396 MWs of solar and wind facilities. In addition, Southern Power continued the construction of approximately 447 MWs of additional solar and natural gas facilities, of which 102 MWs from a solar facility were placed in service subsequent to March 31, 2017. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.

At March 31, 2017, Southern Power had an average investment coverage ratio of 91% through 2021 and 90% through 2026, with an average remaining contract duration of approximately 16 years. These ratios include the PPAs and capacity associated with facilities currently under construction and acquisitions discussed herein. See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein for additional information.

Southern Power continues to focus on several key performance indicators, including, but not limited to, peak season equivalent forced outage rate, contract availability, and net income.

RESULTS OF OPERATIONS

Net Income

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

Net income attributable to Southern Power for the first quarter 2017 was $70 million compared to $50 million for the corresponding period in 2016. The increase was primarily due to increased federal income tax benefits from wind PTCs and increased renewable energy sales, partially offset by increases in depreciation, operations and maintenance expenses, and interest expense from debt issuances, primarily related to Southern Power's new generating facilities.

Operating Revenues

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

Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas and biomass generating facilities, and PPA energy revenues, which include sales from Southern Power's natural gas, biomass, solar, and wind facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into the wholesale market. To the extent Southern Power (excluding its subsidiaries) has capacity not contracted under a PPA, it may sell power into the power pool.

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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:

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

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

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

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

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

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Fuel and Purchased Power Expenses

Fuel costs constitute the single largest expense for Southern Power. In addition, Southern Power purchases a portion of its electricity needs from the wholesale market. Details of Southern Power's generation and purchased power were as follows:

	First Quarter 2017	First Quarter 2016
	(in billions of KWHs)
Generation	9.7	7.7
Purchased power	0.9	0.6
Total generation and purchased power	10.6	8.3
Total generation and purchased power excluding solar, wind, and tolling agreements	4.9	5.3

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

Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.

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

		First Quarter 2017 vs. First Quarter 2016
		(change in millions)				(% change)
Fuel		$	41			45.1
Purchased power		11				57.9
Total fuel and purchased power expenses		$	52

In the first quarter 2017, total fuel and purchased power expenses increased $52 million, or 47%, compared to the corresponding period in 2016. Fuel expense increased $41 million primarily due to a $54 million increase in the average cost of natural gas per KWH generated, partially offset by a $13 million decrease in the volume of KWHs generated. Purchased power expense increased $11 million due to a $9 million increase in the volume of KWHs purchased and a $2 million increase associated with the average cost of purchased power.

Other Operations and Maintenance Expenses

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

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

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solar, wind, and gas facilities and a $4 million increase associated with employee compensation and expenses in support of Southern Power's overall growth strategy, partially offset by a $7 million decrease in scheduled outage and maintenance expenses.

Depreciation and Amortization

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

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

Interest Expense, net of Amounts Capitalized

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

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

Other Income (Expense), Net

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

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

Income Taxes (Benefit)

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

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

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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 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 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 units within the power pool, and operational limitations. For additional information relating to these factors, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.

Power Sales Agreements

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

At March 31, 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.

On April 25, 2017, the EPA published a notice announcing it would reconsider the effluent guidelines rule, which had been finalized in November 2015. As part of its planned reconsideration, the EPA also announced it is

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administratively staying the compliance deadlines under the rule and will conduct additional rulemaking to that effect.

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

Global Climate Issues

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

On March 28, 2017, the 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. The ultimate outcome of this matter cannot be determined at this time.

Acquisitions

During the three months ended March 31, 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 amount of revenue recognized by Southern Power related to the Bethel facility included in the condensed consolidated statements of income during the first quarter 2017 is $4 million. The aggregate amount of net income, excluding impacts from PTCs, recognized by Southern Power during the three months ended March 31, 2017 included in the condensed consolidated statements of income was 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.

Construction Projects

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

Construction Projects Completed and in Progress

During the three months ended March 31, 2017, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through March 31, 2017, total costs of construction incurred for these three projects were $401 million, of which $203 million remained in CWIP for the Lamesa and Mankato facilities acquired in 2016. Total aggregate construction costs, excluding the acquisition costs, are expected to be $530 million to $590 million for these two facilities that were under construction at March 31, 2017. The ultimate outcome of these matters cannot be determined at this time.

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Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Counterparties	PPA Contract Period
Project Completed During the Three Months Ended March 31, 2017
East Pecos	Solar	120	Pecos County, TX	March 2017	Austin Energy	15 years
Projects Under Construction as of March 31, 2017
Lamesa	Solar	102	Dawson County, TX	April 2017	City of Garland, Texas	15 years
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 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.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

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policies and estimates related to Revenue Recognition, Impairment of Long-Lived Assets and Intangibles, Acquisition Accounting, and ITCs.

Recently Issued Accounting Standards

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While Southern Power expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. Southern Power's ongoing evaluation of revenue streams and related contracts includes the evaluation of identified revenue streams tied to longer term contractual arrangements, such as certain capacity payments under PPAs that are expected to be excluded from the scope of ASC 606 and included in the scope of the current leasing guidance (ASC Topic 840).

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Power must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. However, given Southern Power's core activities of selling generation capacity and energy to high credit rated customers, Southern Power currently does not expect the new standard to have a significant impact to net income. Southern Power has not elected a transition method as the ultimate impact of the new standard has not yet been determined.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Power in Item 7 of the Form 10-K for additional information. Southern Power's financial condition remained stable at March 31, 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 $96 million for the first three months of 2017 compared to net cash used for operating activities of $110 million for the first three months of 2016. The increase in net cash provided from operating activities was primarily due to an increase in renewable energy sales arising from new solar and wind facilities and a decrease in income taxes paid, partially offset by an increase in interest paid. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" of Southern Power in Item 7 of the Form 10-K for additional information. Net cash used for investing activities totaled $1.2 billion for the first three months of 2017 primarily due to payments for renewable acquisitions and the construction of renewable facilities. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information. Net cash provided from financing activities totaled $133 million for the first three months of 2017 primarily due to an increase in 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 three months of 2017 include a $1.0 billion decrease in cash and cash equivalents and a $765 million increase in property, plant, and equipment in-service primarily related to acquisitions, as well as a $70 million decrease in CWIP primarily due to East Pecos being placed in service, partially offset by equipment purchased for wind projects. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, leases, unrecognized tax benefits, and other purchase commitments. Approximately $560 million will be required to repay maturities of long-term debt through March 31, 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, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.

Southern Power's current liabilities sometimes exceed current assets due to the use of short-term debt as a funding source, and construction payables, as well as fluctuations in cash needs, due to both seasonality and the stage of acquisitions and construction projects. In 2017, Southern Power expects to utilize the debt capital markets, bank term loans, and commercial paper markets as the source of funds for the majority of its debt maturities.

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

Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility (as defined below), bank term loans, and operating cash flows.

Southern Power's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes, including maturing debt. Southern Power's subsidiaries are not borrowers under the commercial paper program.

Details of commercial paper were as follows:

	Short-term Debt at March 31, 2017						Short-term Debt During the Period (*)
	Amount Outstanding			Weighted Average Interest Rate			Average Amount Outstanding				Weighted Average Interest Rate			Maximum Amount Outstanding
	(in millions)						(in millions)							(in millions)
Commercial paper	$	381		1.3	%		$	144			1.1	%		$	381

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Company Credit Facility

At March 31, 2017, Southern Power had a committed credit facility (Facility) of $600 million expiring in 2020, of which $76 million has been used for letters of credit and $524 million remains unused. Southern Power's subsidiaries are not borrowers under the Facility. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. Subject to applicable market conditions, Southern Power expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 6 to the financial statements of Southern Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

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

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 March 31, 2017, the total amount available under the facility was $67 million. Southern Power's subsidiaries are not parties to the facility.

Subsidiary Project Credit Facility

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

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

Credit Rating Risk

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

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

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

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	38
At BBB- and/or Baa3	$	409
At BB+ and/or Ba1(*)	$	1,188

(*)	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 three months ended March 31, 2017.

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

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AND SUBSIDIARY COMPANIES

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

 

	Successor					Predecessor
	For the Three Months Ended March 31,					For the Three Months Ended March 31,
	2017					2016
	(in millions)					(in millions)
Operating Revenues:
Natural gas revenues (includes revenue taxes of $48 and $40 for the periods presented, respectively)	$	1,530				$	1,302
Other revenues	30					32
Total operating revenues	1,560					1,334
Operating Expenses:
Cost of natural gas	719					571
Cost of other sales	7					7
Other operations and maintenance	253					241
Depreciation and amortization	120					102
Taxes other than income taxes	70					62
Merger-related expenses	—					3
Total operating expenses	1,169					986
Operating Income	391					348
Other Income and (Expense):
Earnings from equity method investments	39					1
Interest expense, net of amounts capitalized	(46		)			(48		)
Other income (expense), net	5					3
Total other income and (expense)	(2		)			(44		)
Earnings Before Income Taxes	389					304
Income taxes	150					111
Net Income	239					193
Less: Net income attributable to noncontrolling interest	—					11
Net Income Attributable to Southern Company Gas	$	239				$	182

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 

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

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 Three Months Ended March 31,					For the Three Months Ended March 31,
	2017					2016
	(in millions)					(in millions)
Operating Activities:
Net income	$	239				$	193
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	120					102
Deferred income taxes	46					14
Pension, postretirement, and other employee benefits	(6		)			1
Stock based compensation expense	11					5
Mark-to-market adjustments	(82		)			5
Other, net	21					(11		)
Changes in certain current assets and liabilities —
-Receivables	117					34
-Natural gas for sale, net of temporary LIFO liquidation	411					363
-Prepaid income taxes	24					151
-Other current assets	19					27
-Accounts payable	(216		)			(64		)
-Accrued taxes	19					84
-Accrued compensation	(14		)			(46		)
-Other current liabilities	49					(17		)
Net cash provided from operating activities	758					841
Investing Activities:
Property additions	(301		)			(222		)
Cost of removal, net of salvage	(11		)			(15		)
Change in construction payables, net	(12		)			2
Investment in unconsolidated subsidiaries	(81		)			(5		)
Other investing activities	—					2
Net cash used for investing activities	(405		)			(238		)
Financing Activities:
Decrease in notes payable, net	(234		)			(453		)
Redemptions and repurchases — First mortgage bonds	—					(75		)
Distributions to noncontrolling interest	—					(19		)
Payment of common stock dividends	(111		)			(64		)
Other financing activities	1					9
Net cash used for financing activities	(344		)			(602		)
Net Change in Cash and Cash Equivalents	9					1
Cash and Cash Equivalents at Beginning of Period	19					19
Cash and Cash Equivalents at End of Period	$	28				$	20
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $3 and $1 capitalized for 2017 and 2016, respectively)	$	41				$	53
Income taxes, net	—					(132		)
Noncash transactions — Accrued property additions at end of period	53					51

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 March 31, 2017				At December 31, 2016
		(in millions)
Current Assets:
Cash and cash equivalents		$	28			$	19
Receivables —
Energy marketing receivable		493				623
Customer accounts receivable		453				364
Unbilled revenues		173				239
Other accounts and notes receivable		69				76
Accumulated provision for uncollectible accounts		(37		)		(27		)
Materials and supplies		25				26
Natural gas for sale		346				631
Prepaid income taxes		—				24
Prepaid expenses		54				55
Assets from risk management activities, net of collateral		138				128
Other regulatory assets, current		60				81
Other current assets		16				11
Total current assets		1,818				2,250
Property, Plant, and Equipment:
In service		14,660				14,508
Less: Accumulated depreciation		4,498				4,439
Plant in service, net of depreciation		10,162				10,069
Construction work in progress		625				496
Total property, plant, and equipment		10,787				10,565
Other Property and Investments:
Goodwill		5,967				5,967
Equity investments in unconsolidated subsidiaries		1,604				1,541
Other intangible assets, net of amortization of $60 and $34 at March 31, 2017 and December 31, 2016, respectively		340				366
Miscellaneous property and investments		21				21
Total other property and investments		7,932				7,895
Deferred Charges and Other Assets:
Other regulatory assets, deferred		958				973
Other deferred charges and assets		188				170
Total deferred charges and other assets		1,146				1,143
Total Assets		$	21,683			$	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 March 31, 2017				At December 31, 2016
		(in millions)
Current Liabilities:
Securities due within one year		$	22			$	22
Notes payable		1,023				1,257
Energy marketing trade payables		471				597
Accounts payable		241				348
Customer deposits		131				153
Accrued taxes —
Accrued income taxes		50				26
Other accrued taxes		63				68
Accrued interest		59				48
Accrued compensation		43				58
Liabilities from risk management activities, net of collateral		18				62
Other regulatory liabilities, current		148				102
Accrued environmental remediation, current		66				69
Temporary LIFO liquidation		126				—
Other current liabilities		124				108
Total current liabilities		2,585				2,918
Long-term Debt		5,246				5,259
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		2,059				1,975
Employee benefit obligations		434				441
Other cost of removal obligations		1,630				1,616
Accrued environmental remediation, deferred		343				357
Other regulatory liabilities, deferred		54				51
Other deferred credits and liabilities		88				127
Total deferred credits and other liabilities		4,608				4,567
Total Liabilities		12,439				12,744
Common Stockholder's Equity:
Common stock, par value $0.01 per share —
Authorized — 100 million shares
Outstanding — 100 shares		—				—
Paid in capital		9,104				9,095
Retained earnings (accumulated deficit)		116				(12		)
Accumulated other comprehensive income		24				26
Total stockholder's equity		9,244				9,109
Total Liabilities and Stockholder's Equity		$	21,683			$	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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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through utilities in seven states – Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee, and Maryland. Southern Company Gas and its subsidiaries are also involved in several other complementary businesses.

Southern Company Gas has four reportable segments – gas distribution operations, gas marketing services, wholesale gas services, and gas midstream operations – and one non-reportable segment – all other. For additional information on these segments, see Note (K) to the Condensed Financial Statements herein and "BUSINESS – Southern Company Gas" in Item 1 of the Form 10-K.

Many factors affect the opportunities, challenges, and risks of Southern Company Gas' business. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow natural gas sales, and to effectively manage and secure timely recovery of costs. Southern Company Gas has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Southern Company Gas for the foreseeable future.

Merger with Southern Company

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

See Note (I) to the Condensed Financial Statements herein for additional information relating to the Merger.

Investment in SNG

In September 2016, Southern Company Gas paid approximately $1.4 billion to acquire a 50% equity interest in SNG. On March 31, 2017, Southern Company Gas made an additional $50 million contribution to maintain its 50% equity interest in SNG. Southern Company Gas recorded equity investment income of $34 million from this investment in the first quarter 2017. See Note (J) to the Condensed Financial Statements herein and Notes 4 and 11 to the financial statements of Southern Company Gas under "Equity Method Investments – SNG" and "Investment in SNG," respectively, in Item 8 of the Form 10-K for additional information.

Other Matters

In October 2016, Southern Company Gas completed its purchase of Piedmont's 15% interest in SouthStar, which eliminated the noncontrolling interest associated with SouthStar.

Operating Metrics

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

Heating Degree Days

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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

(a)	Normal represents the 10-year average from January 1, 2007 through March 31, 2016 for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, based on information obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center.

(b)	The 10-year average Heating Degree Days established by the Illinois Commission in Nicor Gas' 2009 rate case is 2,902 for the first three months from 1998 through 2007.

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

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

Customer Count

The number of customers at gas distribution operations and energy customers at gas marketing services can be impacted by natural gas prices, economic conditions, and competition from alternative fuels. Gas marketing services' customers are primarily located in Georgia and Illinois. The following table provides the number of customers served by Southern Company Gas at March 31, 2017 and 2016.

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

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

Gas marketing services' market share in Georgia was flat at March 31, 2017 compared to March 31, 2016 despite the highly competitive marketing environment, which Southern Company Gas expects for the foreseeable future. Southern Company Gas will continue efforts at gas marketing services to enter into targeted markets and expand its energy customers and service contracts.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Volumes of Natural Gas Sold

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

	First Quarter						2017 vs. 2016
	2017			2016			% Change
Gas distribution operations (mmBtu in millions)
Firm	263			289			(9.0	)%
Interruptible	25			26			(3.8	)%
Total	288			315			(8.6	)%
Gas marketing services (mmBtu in millions)
Firm:
Georgia	12			17			(29.4	)%
Illinois	5			6			(16.7	)%
Other emerging markets	5			5			—	%
Interruptible:
Large commercial and industrial	4			4			—	%
Total	26			32			(18.8	)%
Wholesale gas services (mmBtu in millions/day)
Daily physical sales	6.7			7.9			(15.2	)%

Seasonality of Results

During 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 first quarter 2017 was $239 million. 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 was positively impacted by $3 million due to the pushdown of acquisition accounting related to the Merger. Net income for the successor period included $15 million in after-tax earnings from the SNG investment, net of related interest expense, as well as $29 million and $48 million in after-tax mark-to-market gains from derivative instruments and revenue from commercial activity, respectively, at wholesale gas services driven by changes in natural gas price volatility. Also reflected in net income for this period was an increase of $11 million, after-tax, from additional infrastructure replacement programs at gas distribution operations and a base rate increase at Atlanta Gas Light effective March 1, 2017, partially offset by a reduction of $8 million, after-tax, resulting from warmer-than-normal weather, net of hedging.

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Net income attributable to Southern Company Gas for the predecessor first quarter 2016 was $182 million. Net income attributable to the noncontrolling interest in SouthStar for the predecessor period was $11 million. Net income of $193 million for the predecessor period reflected $12 million and $26 million in after-tax mark-to-market gains from derivative instruments and commercial activity revenue, respectively, at wholesale gas services due to changes in natural gas price volatility in the period, partially offset by a decrease of $3 million, after-tax, attributable to warmer-than-normal weather, net of hedging.

Natural Gas Revenues

Natural gas revenues for the successor first quarter 2017 and the predecessor first quarter 2016 were $1.5 billion and $1.3 billion, respectively.

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

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

Natural gas distribution rates include provisions to adjust billings for fluctuation in natural gas costs. Therefore, recoverable natural gas revenues generally equal the cost of natural gas and do not affect net income from gas distribution operations.

Cost of Natural Gas

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

Other Operations and Maintenance Expenses

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

Depreciation and Amortization

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

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Taxes Other Than Income Taxes

For the successor first quarter 2017 and the predecessor first quarter 2016, taxes other than income taxes were $70 million and $62 million, respectively, which consisted primarily of revenue tax expenses, property taxes, and payroll taxes. Taxes other than income taxes in the successor period reflected increased revenue-based taxes due to higher revenues at gas distribution operations in the period.

Earnings from Equity Method Investments

For the successor first quarter 2017, earnings from equity method investments were $39 million, which primarily consists of $34 million in earnings from SNG and $3 million in earnings from PennEast Pipeline. For the predecessor first quarter 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 the successor first quarter 2017, interest expense, net of amounts capitalized, was $46 million, reflecting the $9 million reduction resulting from the fair value adjustment of long-term debt in acquisition accounting, partially offset by additional interest expense on new debt issuances in 2016.

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

Income Taxes

For the successor first quarter 2017, income taxes were $150 million, driven by pre-tax earnings.

For the predecessor first quarter 2016, income taxes were $111 million.

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, which were evaluated on a consolidated basis for those periods. EBIT is used herein to discuss the results of Southern Company Gas' segments for the predecessor period, as EBIT was the primary measure of segment profit or loss for that period. Subsequent to the Merger, Southern Company Gas changed its segment performance measure from EBIT to net income to better align with the performance measure utilized by Southern Company. EBIT for the successor first quarter 2017 presented herein is considered a non-GAAP measure. Southern Company Gas also discusses consolidated EBIT, which is considered a non-GAAP measure for all periods presented. The presentation of consolidated EBIT is believed to provide useful supplemental information regarding a consolidated measure of profit or loss. Southern Company Gas further believes that the presentation of segment EBIT for the successor first quarter 2017 is useful as it allows for a measure of comparability to the other companies with different capital and legal structures, which accordingly may be subject to different interest rates and effective tax rates. The applicable reconciliations of net income to consolidated EBIT and segment EBIT, respectively, are provided herein.

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

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margin before overhead costs. The applicable reconciliation of operating income to adjusted operating margin is provided herein.

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

	Successor					Predecessor
	First Quarter 2017					First Quarter 2016
	(in millions)					(in millions)
Operating Income	$	391				$	348
Other operating expenses(a)	443					408
Revenue taxes(b)	(47		)			(39		)
Adjusted Operating Margin	$	787				$	717

(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.

	Predecessor
	First Quarter 2016
	(in millions)
Consolidated Net Income Attributable to Southern Company Gas	$	182
Net income attributable to noncontrolling interest	11
Income taxes	111
Interest expense, net of amounts capitalized	48
EBIT	$	352

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
	First Quarter 2017													First Quarter 2016
	Adjusted Operating				Operating				Net					Adjusted Operating				Operating
	Margin(*)				Expenses(*)				Income					Margin(*)				Expenses(*)				EBIT
	(in millions)													(in millions)
Gas distribution operations	$	542			$	313			$	117				$	525			$	291			$	235
Gas marketing services	105				53				31					124				44				80
Wholesale gas services	131				15				68					60				17				44
Gas midstream operations	9				12				15					9				12				(1		)
All other	2				5				8					2				7				(5		)
Intercompany eliminations	(2		)		(2		)		—					(3		)		(2		)		(1		)
Consolidated	$	787			$	396			$	239				$	717			$	369			$	352

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

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Gas Distribution Operations

Gas distribution operations is the largest component of Southern Company Gas' business and is subject to regulation and oversight by agencies in each of the states it serves. These agencies approve natural gas rates designed to provide Southern Company Gas the opportunity to generate revenues to recover the cost of natural gas delivered to its customers and its fixed and variable costs, such as depreciation, interest, maintenance, and overhead costs, as well as to earn a reasonable return on its investments.

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

Successor first quarter 2017

Net income of $117 million includes $542 million in adjusted operating margin, $313 million in operating expenses, and $4 million in other income (expense), net, which resulted in EBIT of $233 million. Net income also includes $40 million in interest expense and $76 million in income tax expense. Adjusted operating margin reflects $19 million in additional revenue from the continued investment in infrastructure replacement programs and a base rate increase at Atlanta Gas Light effective March 1, 2017, partially offset by a $6 million negative impact of warmer-than-normal weather, net of hedging. Operating expenses reflect additional depreciation due to continued investment in infrastructure programs, additional employee compensation in the period due to the timing of accruals for certain expenses, and increased pipeline compliance and maintenance activities.

Predecessor first quarter 2016

EBIT of $235 million includes $525 million in adjusted operating margin, $291 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 $6 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. 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.

Successor first quarter 2017

Net income of $31 million includes $105 million in adjusted operating margin and $53 million in operating expenses, which resulted in EBIT of $52 million. Net income also includes $1 million in interest expense and $20 million in income tax expense. As a result of purchasing the remaining interest in SouthStar in October 2016, there was no noncontrolling interest and all net income from gas marketing services was attributable to Southern Company Gas in this period. Adjusted operating margin, which includes gas marketing and warranty sales, reflects $2 million of additional revenue as a result of fair value adjustments to certain assets and liabilities in the application of acquisition accounting, as well as a $7 million negative impact of warmer-than-normal weather, net of hedging and $7 million in unrealized hedge losses in the period. 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, and a reduction in litigation-related expense.

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Predecessor first quarter 2016

EBIT of $80 million includes $124 million in adjusted operating margin and $44 million in operating expenses. Adjusted operating margin reflects revenue from gas marketing and warranty sales, $2 million in unrealized hedge gains, and a $1 million positive impact of weather, net of hedging, despite warmer-than-normal weather in the period. Operating expenses primarily reflect marketing, legal, and bad debt expenses. Earnings in the predecessor period include $11 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 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.

Successor first quarter 2017

Net income of $68 million includes $131 million in adjusted operating margin and $15 million in operating expenses, which resulted in EBIT of $116 million. Also included is $2 million in interest expense and $46 million in income tax expense. Operating expenses primarily reflect employee compensation and benefits.

Predecessor first quarter 2016

EBIT of $44 million includes $60 million in adjusted operating margin, $17 million in operating expense, and $1 million in other income (expense), net. Operating expenses primarily reflect employee compensation and benefits.

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

	Successor					Predecessor
	First Quarter 2017					First Quarter 2016
	(in millions)					(in millions)
Commercial activity recognized	$	80				$	43
Gain (loss) on storage derivatives	4					(2		)
Gain (loss) on transportation and forward commodity derivatives	44					22
LOCOM adjustments, net of current period recoveries	—					(3		)
Purchase accounting adjustments to fair value inventory and contracts	3					—
Adjusted Operating Margin	$	131				$	60

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. Increases in natural gas supply and warmer-than-normal weather during the 2016/2017 Heating Season and the resulting higher natural gas inventories at the end of 2016 caused natural gas prices to decline in the early part of 2017. However, as natural gas prices and forward storage or time spreads increased, largely in the first quarter 2017, wholesale gas services was able to capture higher storage values to accommodate the increase in natural gas supply. Wholesale gas services experienced low volatility in 2016 due partly to weather and Southern Company Gas anticipates continued low volatility in certain areas of wholesale gas services' portfolio.

Change in Storage and Transportation Derivatives

Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the U.S. The volatility of natural gas commodity prices has

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a significant impact on Southern Company Gas' customer rates, long-term competitive position against other energy sources, and the ability of wholesale gas services to capture value from locational and seasonal spreads. In 2017 and 2016, there was little price volatility; however, the potential exists for market fundamentals indicating some level of increased volatility that would benefit Southern Company Gas' portfolio of pipeline transportation capacity. Additionally, during the first quarter 2017, forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions resulted in storage derivative gains. Transportation and forward commodity derivative gains are primarily the result of narrowing transportation basis spreads due to continued supply constraints 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 March 31, 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 $2.74)			Expected net operating gains(a)				Physical transportation transactions – expected net operating losses(b)
	(in mmBtu in millions)			(in millions)				(in millions)
2017	40.3			$	14			$	(21	)
2018 and thereafter	5.2			4				(23		)
Total at March 31, 2017	45.5			$	18			$	(44	)

(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, based on current expectations, primarily will be reversed during the remainder of 2017 when the related transactions occur and are recognized. For more information on wholesale gas services' energy marketing and risk management activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K.

Gas Midstream Operations

Gas midstream operations consists primarily of gas pipeline investments, with storage and fuels also aggregated into this segment. Gas pipeline investments consist of the SNG interest, Horizon Pipeline, Atlantic Coast Pipeline, PennEast Pipeline, Dalton Pipeline, and Magnolia Enterprise Holdings, Inc.

Successor first quarter 2017

Net income of $15 million includes $9 million in adjusted operating margin, $12 million in operating expenses, $38 million in earnings from equity method investments, which consists primarily of equity in earnings from the

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

Predecessor first quarter 2016

Loss before interest and taxes of $1 million includes $9 million in adjusted operating margin, $12 million in operating expenses, and $2 million of other income (expense), net.

All Other

All other includes Southern Company Gas' investment in Triton, AGL Services Company, and Southern Company Gas Capital, as well as various corporate operating expenses that are not allocated to the reportable segments and interest income/(expense) associated with affiliate financing arrangements. For the successor first quarter 2017 and the predecessor first quarter 2016, these operating expenses included Merger-related expenses of less than $1 million and $3 million, respectively.

Segment Reconciliations

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

	Successor
	First Quarter 2017
	Gas Distribution Operations			Gas Marketing Services			Wholesale Gas Services			Gas Midstream Operations			All Other			Intercompany Elimination			Consolidated
	(in millions)
Consolidated Net Income	$	117		$	31		$	68		$	15		$	8		$	—		$	239
Income taxes	76			20			46			12			(4		)	—			150
Interest expense, net of amounts capitalized	40			1			2			9			(6		)	—			46
EBIT	$	233		$	52		$	116		$	36		$	(2	)	$	—		$	435

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

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	Predecessor
	First Quarter 2016
	Gas Distribution Operations			Gas Marketing Services			Wholesale Gas Services			Gas Midstream Operations			All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	234		$	80		$	43		$	(3	)	$	(5	)	$	(1	)	$	348
Other operating expenses(a)	330			44			17			12			7			(2		)	408
Revenue tax expense(b)	(39		)	—			—			—			—			—			(39		)
Adjusted Operating Margin	$	525		$	124		$	60		$	9		$	2		$	(3	)	$	717

(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 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 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.

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.

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In September 2016, Southern Company Gas acquired a 50% equity interest in SNG. See OVERVIEW – "Investment in SNG" and Note (J) 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.

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.

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.

Natural Gas Cost Recovery

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

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 Georgia PSC allowed the last monthly Pipeline Replacement Program surcharge increase, originally scheduled for October 2017, to occur 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 is based on a projected 12-month test year ending March 31, 2017 and an ROE of 10.25%. The New Jersey BPU is expected to issue an order on the filing in the third quarter 2017, after which rate adjustments will be effective.

On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and an ROE of

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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.

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 an 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 the pending base rate cases cannot be determined at this time.

Regulatory Infrastructure Programs

Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs.

Nicor Gas

In 2014, the Illinois Commission approved Nicor Gas' nine-year regulatory infrastructure program, Investing in Illinois. Under this program, Nicor Gas placed into service $24 million of qualifying assets during the first quarter 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 $38 million during the first quarter 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 $3 million during the first quarter 2017.

Virginia Natural Gas

In March 2016, the Virginia Commission approved an extension to the SAVE program, under which Virginia Natural Gas invested $7 million during the first quarter 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 $3 million during the first quarter 2017.

Other Matters

Southern Company Gas is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the

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ordinary course of business. The ultimate outcome of such pending or potential litigation against Southern Company Gas 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 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

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While Southern Company Gas expects most of its revenue to be included in the scope of ASC 606, it has not fully completed its evaluation of all revenue arrangements. The majority of Southern Company Gas' revenue, including energy provided to customers, is from tariff offerings that provide natural gas without a defined contractual term. For such arrangements, Southern Company Gas expects that the revenue from contracts with these customers will continue to be equivalent to the natural gas supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.

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

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The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. Southern Company Gas must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, Southern Company Gas has not elected its transition method.

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 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 first quarter 2017 and the predecessor first quarter 2016. See OVERVIEW – "Merger with Southern Company" herein for additional information.

Southern Company Gas' financial condition remained stable at March 31, 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. Elizabethtown Gas is restricted by its dividend policy as established by the New Jersey BPU in the amount it can dividend to its parent company to the extent of 70% of its quarterly net income. Additionally, as stipulated in the New Jersey BPU's order approving the Merger, Southern Company Gas is prohibited from paying dividends to its parent company, Southern Company, if Southern Company Gas' senior unsecured debt rating falls below investment grade. As of March 31, 2017, the amount of subsidiary retained earnings and net income available to dividend totaled $722 million. These restrictions

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did not have any impact on Southern Company Gas' ability to meet its cash obligations, nor does management expect such restrictions to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.

Net cash provided from operating activities totaled $758 million for the successor first quarter 2017 and $841 million for the predecessor first quarter 2016. These cash flows were primarily driven by the sale of natural gas inventory during the respective periods.

Net cash used for investing activities totaled $405 million for the successor first quarter 2017, primarily due to gross property additions related to capital expenditures for infrastructure replacement programs at gas distribution operations and capital contributed to equity method investments in pipelines. Net cash used for investing activities totaled $238 million for the predecessor first quarter 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 $344 million for the successor first quarter 2017, primarily due to net repayments of commercial paper borrowings and common stock dividend payments to Southern Company. Net cash used for financing activities totaled $602 million for the predecessor first quarter 2016, primarily due to net repayments of commercial paper borrowings, the redemption of long-term debt, and common stock dividend payments to shareholders. 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 March 31, 2017 include an increase of $222 million in total property, plant, and equipment primarily due to capital expenditures for infrastructure replacement programs and decreases of $411 million in natural gas for sale, including temporary LIFO liquidation due to the use of natural gas stored during the first quarter 2017, and $234 million in notes payable related primarily to net repayments of commercial paper borrowings at Nicor Gas. Other significant balance sheet changes include decreases of $107 million in accounts payable as well as $130 million and $126 million in energy marketing receivable and energy marketing payables, respectively, due to lower natural gas prices.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company Gas in Item 7 of the Form 10-K for a description of Southern Company Gas' capital requirements for its infrastructure programs, scheduled maturities of long-term debt and the related interest, as well as pipeline charges, storage capacity, and gas supply, operating leases, asset management agreements, standby letters of credit and performance/surety bonds, financial derivative obligations, pension and other postretirement benefit plans, and other purchase commitments, primarily related to environmental remediation liabilities. Approximately $22 million will be required through March 31, 2018 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

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

Sources of Capital

Southern Company Gas plans to obtain the funds to meet its future capital needs through operating cash flows, short-term debt borrowings under its commercial paper programs, external securities issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S

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DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company Gas in Item 7 of the Form 10-K for additional information.

At March 31, 2017, Southern Company Gas' current liabilities exceeded current assets by $767 million. Southern Company Gas' current liabilities frequently exceed current assets because of commercial paper borrowings used to fund its daily operations, scheduled maturities of long-term debt, and significant seasonal fluctuations in cash needs. Southern Company Gas intends to utilize operating cash flows, commercial paper, and debt securities issuances, as market conditions permit, as well as equity contributions from Southern Company to fund its short-term capital needs. Southern Company Gas has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.

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

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

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 have been issued totaling $200 million.

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

The Southern Company Gas Credit Facility and the Nicor Gas Credit Facility included in the table above each contain a covenant that limits the ratio of debt to capitalization (as defined in each facility) to a maximum of 70% and contain cross acceleration provisions to other indebtedness (including guarantee obligations) of the applicable company. Such cross acceleration provisions to other indebtedness would trigger an event of default if Southern Company Gas defaulted on indebtedness, the payment of which was then accelerated. At March 31, 2017, each of the applicable companies was in compliance with all such covenants. Neither of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

Subject to applicable market conditions, the applicable company expects to renew or replace its bank credit arrangements 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.

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Details of short-term borrowings were as follows:

	Short-term Debt at March 31, 2017							Short-term Debt During the Period(*)
	Amount Outstanding				Weighted Average Interest Rate			Average Amount Outstanding				Weighted Average Interest Rate			Maximum Amount Outstanding
Commercial paper:	(in millions)							(in millions)							(in millions)
Southern Company Gas Capital	$	715			1.28	%		$	630			1.09	%		$	733
Nicor Gas	308				1.16			410				0.98			525
Short-term loans:
Southern Company Gas	—				—			1				1.91			113
Total	$	1,023			1.24	%		$	1,041			1.04	%

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

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

Credit Rating Risk

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

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change below BBB- and/or Baa3. These contracts are for physical gas purchases and sales and energy price risk management. The maximum potential collateral requirements under these contracts at March 31, 2017 were $13 million.

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

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

Financing Activities

The long-term debt on Southern Company Gas' consolidated balance sheets includes both principal and non-principal components. As of March 31, 2017, the non-principal components totaled $556 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 addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company Gas plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

Market Price Risk

Other than the items discussed below, there were no material changes to Southern Company Gas' disclosures about market price risk during the successor first quarter 2017. For an in-depth discussion of Southern Company Gas' market price risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K. Also, see Notes (C) and (H) to the Condensed Financial Statements herein for information relating to derivative instruments.

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Southern Company Gas is exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas distribution utilities of Southern Company Gas that sell natural gas directly to its end-use customers have limited exposure to market volatility of natural gas prices. Certain natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. For the weather risk associated with Nicor Gas, Southern Company Gas has a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather. In addition, certain non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Some of these economic hedge activities may not qualify, or are not designated, for hedge accounting treatment. The following table illustrates the change in the net fair value of Southern Company Gas' derivative instruments during the periods presented, and provides details of the net fair value of contracts outstanding as of the dates presented.

	Successor					Predecessor
	First Quarter					First Quarter
	2017					2016
	(in millions)					(in millions)
Contracts outstanding at beginning of period, assets (liabilities), net	$	12				$	75
Contracts realized or otherwise settled	4					(85		)
Current period changes(a)	48					(34		)
Contracts outstanding at the end of period, assets (liabilities), net	64					(44		)
Netting of cash collateral	92					165
Cash collateral and net fair value of contracts outstanding at end of period(b)	$	156				$	121

(a)	Current period changes also include the fair value of new contracts entered into during the period, if any.

(b)	Net fair value of derivative instruments outstanding includes premiums and the intrinsic values associated with weather derivatives of $19 million at March 31, 2017 and $9 million at March 31, 2016.

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

					Fair Value Measurements
					Successor – March 31, 2017
	Total Fair Value				Maturity
					Year 1				Years 2 & 3				Years 4 and thereafter
	(in millions)
Level 1(a)	$	(28	)		$	(2	)		$	(21	)		$	(5	)
Level 2(b)	92				57				29				6
Level 3	—				—				—				—
Fair value of contracts outstanding at end of period(c)	$	64			$	55			$	8			$	1

(a)	Valued using NYMEX futures prices.

(b)	Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.

(c)	Excludes cash collateral of $92 million at March 31, 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	170
B	Contingencies and Regulatory Matters	175
C	Fair Value Measurements	196
D	Stockholders' Equity	200
E	Financing	202
F	Retirement Benefits	205
G	Income Taxes	208
H	Derivatives	210
I	Acquisitions	221
J	Joint Ownership Agreements	224
K	Segment and Related Information	226

INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT

The following unaudited notes to the condensed financial statements are a combined presentation. The list below indicates the registrants to which each footnote applies.

Registrant	Applicable Notes
Southern Company	A, B, C, D, E, F, G, H, I, J, K
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 March 31, 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 months ended March 31, 2017 and financial condition as of March 31, 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

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers, replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While the registrants expect most of their revenue to be included in the scope of ASC 606, they have not fully completed the evaluation of all revenue arrangements. The majority of Southern Company's, the traditional electric operating companies', and Southern Company Gas' revenue, including energy provided to customers, is from tariff offerings that provide electricity or natural gas without a defined contractual term. For such arrangements, the registrants expect that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of ASC 606 will not result in a significant shift in the timing of revenue recognition for such sales.

The registrants' ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments and unregulated sales to customers. Some revenue arrangements, such as certain PPAs and alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and presented separately from revenues under ASC 606 on the registrants' financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues, including the applicability of ASC 606 to contributions in aid of construction (CIAC). Although final implementation guidance has not been issued, Southern Company, the traditional electric operating companies, and Southern Company Gas expect CIAC to be out of the scope of ASC 606. Given Southern Power's core activities of selling generation capacity and energy to high credit rated customers, Southern Power currently does not expect the new standard to have a significant impact to net income.

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The registrants must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, the registrants have not elected a transition method.

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, the traditional

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(UNAUDITED)

electric operating companies, and Southern Company Gas are currently evaluating the new standard. The presentation changes required for net periodic pension and postretirement benefit costs will result in a decrease in Southern Company's, the traditional electric operating companies', and Southern Company Gas' operating income and an increase in other income for 2016 and 2017 and are expected to result in a decrease in operating income and an increase in other income for 2018. The adoption of ASU 2017-07 is not expected to have a material impact on Southern Company's, the traditional electric operating companies', or Southern Company Gas' financial statements.

Affiliate Transactions

Prior to the completion of Southern Company Gas' acquisition of its 50% equity interest in SNG, SCS (as agent for Alabama Power, Georgia Power, and Southern Power) and Southern Company Gas had entered into long-term interstate natural gas transportation agreements with SNG. The interstate transportation service provided to Alabama Power, Georgia Power, Southern Power, and Southern Company Gas by SNG pursuant to these agreements is governed by the terms and conditions of SNG's natural gas tariff and is subject to FERC regulation. For the three months ended March 31, 2017, transportation costs under these agreements for Alabama Power, Georgia Power, Southern Power, and Southern Company Gas were approximately $1 million, $26 million, $6 million, and $9 million, respectively.

SCS, as agent for Southern Power, has agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. For the three months ended March 31, 2017, natural gas purchases made by Southern Power from Southern Company Gas' subsidiaries were approximately $23 million.

Goodwill and Other Intangible Assets

As of March 31, 2017 and December 31, 2016, goodwill was as follows:

	Goodwill
	(in millions)
Southern Company	$	6,251
Southern Power	$	2
Southern Company Gas
Gas distribution operations	$	4,702
Gas marketing services	1,265
Southern Company Gas total	$	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:

	As of March 31, 2017										As of 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	$	268		$	(44	)	$	224			$	268		$	(32	)	$	236
Trade names	158			(8		)	150				158			(5		)	153
Patents	4			—			4				4			—			4
Backlog	5			(1		)	4				5			(1		)	4
Storage and transportation contracts	64			(15		)	49				64			(2		)	62
Software and other	2			(1		)	1				2			—			2
PPA fair value adjustments	456			(28		)	428				456			(22		)	434
Total other intangible assets subject to amortization	$	957		$	(97	)	$	860			$	957		$	(62	)	$	895
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	$	75		$	—		$	75			$	75		$	—		$	75
Total other intangible assets	$	1,032		$	(97	)	$	935			$	1,032		$	(62	)	$	970
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	456		$	(28	)	$	428			$	456		$	(22	)	$	434
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	221		$	(41	)	$	180			$	221		$	(30	)	$	191
Trade names	115			(4		)	111				115			(2		)	113
Wholesale gas services
Storage and transportation contracts	64			(15		)	49				64			(2		)	62
Total other intangible assets subject to amortization	$	400		$	(60	)	$	340			$	400		$	(34	)	$	366

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Amortization associated with other intangible assets was as follows:

	Three Months Ended
	March 31, 2017
	(in millions)
Southern Company	$	35
Southern Power	$	6
Southern Company Gas	$	26

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 March 31, 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 recorded no LOCOM adjustment in the successor first quarter 2017 and recorded a $3 million LOCOM adjustment in the predecessor first quarter 2016.

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(B)	CONTINGENCIES AND REGULATORY MATTERS

See Note 3 to the financial statements of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits, other contingencies, and regulatory matters.

General Litigation Matters

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

The ultimate outcome of such pending or potential litigation against each registrant and any subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.

Southern Company

On January 20, 2017, a purported securities class action complaint was filed against Southern Company, certain of its officers, and certain of Mississippi Power's former 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 of Mississippi Power's former officers made materially false and misleading statements regarding the Kemper IGCC in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. Southern Company believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in this matter, and the ultimate outcome of this matter cannot be determined at this time.

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 of Mississippi Power's former 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. Southern Company believes that this legal challenge has no merit; however, an adverse outcome in this proceeding could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in this matter, and the ultimate outcome of this matter cannot be determined at this time.

Georgia Power

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

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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 Company Gas

Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. were defendants in a putative class action initially filed in 2011 in state court in Cook County, Illinois. The plaintiffs purported to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously alleged that the marketing, sale, and billing of the Gas Line Comfort Guard product violated the Illinois Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. The plaintiffs sought, on behalf of the classes they purported to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On February 8, 2017, the judge denied the plaintiffs' motion for class certification and Southern Company Gas' motion for summary judgment. On March 7, 2017, the parties reached a settlement, which was finalized and effective on April 3, 2017. The settlement did not have a material impact on Southern Company's or Southern Company Gas' financial statements.

Environmental 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 as of March 31, 2017 was $13 million. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $52 million as of March 31, 2017. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power's substations. The schedule for completion of the remediation 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 as of March 31, 2017 was $409 million 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

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

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

In March 2016, Mississippi Power reached a settlement agreement with its wholesale customers, which was subsequently approved by the FERC, for an increase in wholesale base revenues under the MRA cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in 2015. The settlement agreement became effective for services rendered beginning May 1, 2016, resulting in an estimated annual revenue increase of $7 million under the MRA cost-based electric tariff. Additionally, under the settlement agreement, the tariff customers agreed to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking through an order issued by the Mississippi PSC in December 2015 (In-Service Asset Rate Order). This regulatory treatment primarily includes (i) recovery of the Kemper IGCC assets currently operational and providing service to customers and other related costs, (ii) amortization of the Kemper IGCC-related regulatory assets included in rates under the settlement agreement over the 36 months ending April 30, 2019, (iii) Kemper IGCC-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper IGCC CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC is estimated to be approximately $18 million until the end of May 2017 when the Kemper IGCC is projected to be placed in service.

Fuel Cost Recovery

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

See Note 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

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

In December 2016, the traditional electric operating companies and Southern Power filed an amendment to their market-based rate tariff that proposed certain changes to the energy auction, as well as several non-tariff changes. On February 2, 2017, the FERC issued an order accepting all such changes subject to an additional condition of cost-based price caps for certain sales outside of the energy auction, finding that all of these changes would provide adequate alternative mitigation for the traditional electric operating companies' and Southern Power's potential to exert market power in certain areas served by the traditional electric operating companies and in some adjacent areas. On February 23, 2017, the traditional electric operating companies and Southern Power accepted the terms of the order in a compliance filing. While the FERC's February 2, 2017 order references the market power proceeding discussed above, it remains a separate, ongoing matter.

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

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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	March 31, 2017			December 31, 2016
		(in millions)
Rate CNP Compliance(*)	Deferred under recovered regulatory clause revenues	$	—		$	9
Rate CNP PPA	Over recovered regulatory clause revenues	3			—
	Deferred under recovered regulatory clause revenues	—			142
Retail Energy Cost Recovery	Other regulatory liabilities, current	40			76
Natural Disaster Reserve	Other regulatory liabilities, deferred	66			69

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

Georgia Power

Rate Plans

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

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

Integrated Resource Plan

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

On March 7, 2017, the Georgia PSC approved Georgia Power's decision to suspend work at a future generation site in Stewart County, Georgia, due to changing economics, including load forecasts and lower fuel costs. The timing

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of recovery for costs of approximately $50 million incurred through March 31, 2017 will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

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

As of March 31, 2017 and December 31, 2016, Georgia Power's over recovered fuel balance totaled $18 million and $84 million, respectively, 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, the Vogtle Construction Litigation (as defined below), and the Contractor Settlement Agreement (as defined below).

Vogtle 3 and 4 Agreement and Contractor Bankruptcy

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

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

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

Under the Toshiba Guarantee, Toshiba has guaranteed certain payment obligations of the Contractor, including any liability of the Contractor for abandonment of work. However, due to Toshiba's financial situation described below, substantial risk regarding the Vogtle Owners' ability to fully collect under the Toshiba Guarantee exists. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed. In the event of such notice, the Vogtle Owners would be able to draw on the entire balance of the Westinghouse Letters of Credit. The Westinghouse Letters of Credit remain in place in accordance with the terms of the Vogtle 3 and 4 Agreement.

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

The Interim Assessment Agreement provides, among other items, that (i) Georgia Power will be obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the Contractor for subcontractors and vendors for services performed or goods provided during the Interim Assessment Period, with these amounts to be paid to the Contractor, except for amounts accrued for Fluor, which will be paid directly to Fluor; (ii) during the Interim Assessment Period, the Contractor shall provide certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extent as contemplated by the Vogtle 3 and 4 Agreement, and Georgia Power, on behalf of the Vogtle Owners, will make payments of $5.4 million per week for these services; (iii) Georgia Power will have the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who have accounts past due with the Contractor; (iv) during the Interim Assessment Period, the Contractor will use its commercially reasonable efforts to provide information reasonably requested by Georgia Power as is necessary to continue construction and investigate the completion status of Plant Vogtle Units 3 and 4; (v) the Contractor will reject or accept the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) during the Interim Assessment Period, Georgia Power will not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserve all rights and remedies under the Vogtle 3 and 4 Agreement, all related security and collateral, under applicable law.

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A number of subcontractors to the Contractor, including Fluor Enterprises, have alleged non-payment by the Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken, and continues to take, action to remove liens filed by these subcontractors through the posting of surety bonds.

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

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

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

The Contractor's bankruptcy filing is expected to have a material impact on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 and could have a material impact on Southern Company's and Georgia Power's financial statements. In addition, an inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's and Georgia Power's financial statements.

The ultimate outcome of these matters also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and cannot be determined at this time.

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.

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

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

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

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

Other Matters

As of March 31, 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 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 as construction proceeds. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based

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compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

As construction continues, the risk remains that challenges with labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost. Georgia Power's previously estimated owner's costs of approximately $10 million per month and financing costs of approximately $30 million per month for Plant Vogtle Units 3 and 4 are being evaluated as part of the comprehensive schedule and cost-to-complete analysis being performed as a result of the Contractor's bankruptcy.

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

Gulf Power

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

Retail Base Rate Cases

See Note 3 to the financial statements of Southern Company and Gulf Power under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" and "Retail Regulatory Matters – Retail Base Rate Cases," respectively, in Item 8 of 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 may not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. For 2014 and 2015, Gulf Power recognized reductions in depreciation of $8.4 million and $20.1 million, respectively. No net reduction in depreciation was recorded in 2016. In the first quarter 2017, Gulf Power recognized reductions in depreciation totaling $25.5 million. The 2013 Rate Case Settlement Agreement remains in effect through June 30, 2017.

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

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Cost Recovery Clauses

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

Regulatory Clause	Balance Sheet Line Item	March 31, 2017			December 31, 2016
		(in millions)
Fuel Cost Recovery	Other regulatory liabilities, current	$	5		$	15
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	4			—
Environmental Cost Recovery	Under recovered regulatory clause revenues	40			13
Energy Conservation Cost Recovery	Under recovered regulatory clause revenues	3			4

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.

Mississippi Power

Performance Evaluation Plan

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's base rates.

On March 15, 2017, Mississippi Power submitted its annual PEP lookback filing for 2016, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time.

Energy Efficiency

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Energy Efficiency" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's energy efficiency programs.

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

Fuel Cost Recovery

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

At March 31, 2017, the amount of over-recovered retail fuel costs included on Mississippi Power's condensed balance sheet was $27 million compared to $37 million at December 31, 2016.

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Ad Valorem Tax Adjustment

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

On April 7, 2017, Mississippi Power submitted its annual ad valorem tax adjustment factor filing for 2017, which included an annual rate increase of 0.85%, or $8 million in annual retail revenues, primarily due to increased assessments. The ultimate outcome of this matter cannot be determined at this time.

Southern Company Gas

Natural Gas Cost Recovery

Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor 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.

On February 21, 2017, the Georgia PSC approved the Georgia Rate Adjustment Mechanism (GRAM) and a $20 million increase in annual base rate revenues for Atlanta Gas Light, effective March 1, 2017. GRAM adjusts base rates annually, up or down, based on the previously approved ROE of 10.75% and does not collect revenue through special riders and surcharges. Various infrastructure programs previously authorized by the Georgia PSC under Atlanta Gas Light's STRIDE program, which include the Integrated Vintage Plastic Replacement Program, Integrated System Reinforcement Program, and Integrated Customer Growth Program, will continue under GRAM and the recovery of and return on the infrastructure program investments will be included in annual base rate adjustments. The Georgia PSC will review Atlanta Gas Light's performance annually under GRAM.

Beginning with the next rate adjustment in June 2018, Atlanta Gas Light's recovery of the previously unrecovered Pipeline Replacement Program revenue through 2014, as well as the mitigation costs associated with the Pipeline Replacement Program that were not previously included in its rates, will also be included in GRAM. In connection with the GRAM approval, the Georgia PSC allowed the last monthly Pipeline Replacement Program surcharge increase, originally scheduled for October 2017, to occur effective March 1, 2017.

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 is based on a projected 12-month test year ending March 31, 2017 and an ROE of 10.25%. The New Jersey BPU is expected to issue an order on the filing in the third quarter 2017, after which rate adjustments will be effective.

On March 10, 2017, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $208 million increase in annual base rate revenues. The requested increase is based on a 2018 projected test year and an ROE of 10.7%. The Illinois Commission is expected to rule on the requested increase within the 11-month statutory time limit, after which rate adjustments will be effective.

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 an 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.

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

Regulatory Infrastructure Programs

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

Nicor Gas

In 2014, the Illinois Commission approved Nicor Gas' nine-year regulatory infrastructure program, Investing in Illinois. Under this program, Nicor Gas placed into service $24 million of qualifying assets during the first quarter 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 $38 million during the first quarter 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 $3 million during the first quarter 2017.

Virginia Natural Gas

In March 2016, the Virginia Commission approved an extension to the SAVE program, under which Virginia Natural Gas invested $7 million during the first quarter 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 $3 million during the first quarter 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 utilizes IGCC technology with an expected output capacity of 582 MWs. The Kemper IGCC is fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power

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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 and plans to operate approximately 61 miles of CO₂ pipeline infrastructure for the transport of captured CO₂ for use in enhanced oil recovery.

Kemper IGCC Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of 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, including the gasifiers and the gas clean-up facilities, represents first-of-a-kind technology. The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." Mississippi Power achieved integrated operation of both gasifiers on January 29, 2017, including the production of electricity from syngas in both combustion turbines. Mississippi Power continues to work toward achieving sustained operation sufficient to place the remainder of the plant in service. The plant has, however, produced and captured CO₂, and has produced sulfuric acid and ammonia, all of acceptable quality under the related off-take agreements. As a result of ongoing challenges associated with the ash removal and gas cleanup sour water systems, efforts to improve reliability and reach sustained operation of both gasifiers and production of electricity from syngas in both combustion turbines remain in process. Mississippi Power currently expects the remainder of the Kemper IGCC, including both gasifiers, will be placed in service by the end of May 2017. The schedule reflects the expected time needed to repair a leak in one of the particulate control devices for gasifier "A," make other minor modifications to each gasifier's ash removal systems, repair the sour water system, and establish sustained operation of both gasifiers for the production of electricity from syngas.

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

Cost Category	2010 Project Estimate(a)				Current Cost Estimate(b)				Actual Costs
	(in billions)
Plant Subject to Cost Cap(c)(e)	$	2.40			$	5.75			$	5.57
Lignite Mine and Equipment	0.21				0.23				0.23
CO2 Pipeline Facilities	0.14				0.12				0.12
AFUDC(d)	0.17				0.83				0.80
Combined Cycle and Related Assets Placed in Service – Incremental(e)	—				0.05				0.04
General Exceptions	0.05				0.10				0.09
Deferred Costs(e)	—				0.22				0.22
Additional DOE Grants(f)	—				(0.14		)		(0.14		)
Total Kemper IGCC(g)	$	2.97			$	7.16			$	6.93

(a)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions.

(b)	Amounts in the Current Cost Estimate include certain estimated post-in-service costs which are expected to be subject to the cost cap.

(c)

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

(d)

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

(e)

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

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

(g)

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

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

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

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

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

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

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

Rate Recovery of Kemper IGCC Costs

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

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

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

Of these amounts, approximately 29% is related to wholesale and approximately 71% is related to retail, including the 15% portion that was previously contracted to be sold to SMEPA. Mississippi Power and its wholesale customers have generally agreed to similar regulatory treatment for wholesale tariff purposes as approved by the Mississippi PSC for retail for Kemper IGCC-related costs. See "FERC Matters – Municipal and Rural Associations Tariff" and "Termination of Proposed Sale of Undivided Interest" herein for further information.

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 will not seek recovery of the $68 million in additional estimated costs from customers if incurred.

Mississippi Power responded to numerous requests for information from interested parties in the discovery docket, which is now complete. Mississippi Power expects the Mississippi PSC to address these matters in connection with the 2017 Rate Case.

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Economic Viability Analysis

In the fourth quarter 2016, as a part of its Integrated Resource Plan process, the Southern Company system completed its regular annual updated fuel forecast, the 2017 Annual Fuel Forecast. This updated fuel forecast reflected significantly lower long-term estimated costs for natural gas than were previously projected.

As a result of the updated long-term natural gas forecast, as well as the revised operating expense projections reflected in the discovery docket filings discussed above, on February 21, 2017, Mississippi Power filed an updated project economic viability analysis of the Kemper IGCC as required under the 2012 MPSC CPCN Order confirming authorization of the Kemper IGCC. The project economic viability analysis measures the life cycle economics of the Kemper IGCC compared to feasible alternatives, natural gas combined cycle generating units, under a variety of scenarios and considering fuel, operating and capital costs, and operating characteristics, as well as federal and state taxes and incentives. The reduction in the projected long-term natural gas prices in the 2017 Annual Fuel Forecast and, to a lesser extent, the increase in the estimated Kemper IGCC operating costs, negatively impact the updated project economic viability analysis.

Mississippi Power expects the Mississippi PSC to address this matter in connection with the 2017 Rate Case.

2017 Rate Case

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

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

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

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

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

2015 Rate Case

On August 13, 2015, the Mississippi PSC approved Mississippi Power's request for interim rates, which presented an alternative rate proposal (In-Service Asset Proposal) designed to recover Mississippi Power's costs associated 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. Mississippi Power is required to file the 2017 Rate Case by June 3, 2017.

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

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

On February 12, 2015, the Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public

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notice for the related proceedings. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million collected under the 2013 MPSC Rate Order, along with associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation described above.

Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC. Through March 31, 2017, AFUDC recorded since the original May 2014 estimated in-service date for the Kemper IGCC has totaled $445 million, which will continue to accrue at approximately $16 million per month until the remainder of the plant is placed in service. Mississippi Power has not recorded any AFUDC on Kemper IGCC costs in excess of the $2.88 billion cost cap, except for Cost Cap Exception amounts.

2012 MPSC CPCN Order

The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters including availability factor, heat rate, lignite heat content, and chemical revenue based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with the 2017 Rate Case and future proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Southern Company's or Mississippi Power's financial statements. See "Prudence" herein for additional information.

Regulatory Assets and Liabilities

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

In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015 and the second quarter 2016, in connection with the implementation of retail and wholesale rates, respectively, Mississippi Power began expensing certain ongoing project costs and certain retail debt carrying costs (associated with assets placed in service and other non-CWIP accounts) that previously were deferred as regulatory assets and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order and the settlement agreement with wholesale customers. As of March 31, 2017, the balance associated with these regulatory assets was $86 million, of which $24 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $111 million as of March 31, 2017. The amortization period for these assets is expected to be determined by the Mississippi PSC in the 2017 Rate Case. See "FERC Matters" herein for additional information related to the 2016 settlement agreement with wholesale customers.

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

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

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

Lignite Mine and CO₂ Pipeline Facilities

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

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

In addition, Mississippi Power has constructed and will operate the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery. Mississippi Power entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC (Treetop), pursuant to which Denbury would purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop would purchase 30% of the CO₂ captured from the Kemper IGCC. On June 3, 2016, Mississippi Power cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury's agreement to purchase 100% of the CO₂ captured from the Kemper IGCC, an initial contract term of 16 years, and termination rights if Mississippi Power has not satisfied its contractual obligation to deliver captured CO₂ by July 1, 2017, in addition to Denbury's existing termination rights in the event of a change in law, force majeure, or an event of default by Mississippi Power. Any termination or material modification of the agreement with Denbury could impact the operations of the Kemper IGCC and result in a material reduction in Mississippi Power's revenues to the extent Mississippi Power is not able to enter into other similar contractual arrangements or otherwise sequester the CO₂ produced. Additionally, sustained oil price reductions could result in significantly lower revenues than Mississippi Power originally forecasted to be available to offset customer rate impacts, which could have a material impact on Mississippi Power's financial statements.

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 matures on July 31, 2018.

Litigation

On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. On August 12, 2016, Southern Company and Mississippi Power removed the case to the U.S. District Court for the Southern

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District of Mississippi. The plaintiffs filed a request to remand the case back to state court, which was granted on November 17, 2016. The individual plaintiff, John Carlton Dean, alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. On December 7, 2016, Southern Company and Mississippi Power filed motions to dismiss, which the Circuit Court is expected to address in the second quarter 2017.

On June 9, 2016, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO₂ contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages. Southern Company, Mississippi Power, and SCS have moved to compel arbitration pursuant to the terms of the CO₂ contract, which the court is expected to address in the second quarter 2017.

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

Baseload Act

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

Income Tax Matters

See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle – Bonus Depreciation," " – Investment Tax Credits," and " – Section 174 Research and Experimental Deduction" in Item 8 of the Form 10-K and Note (G) under "Section 174 Research and Experimental Deduction" for additional information on bonus depreciation, investment tax credits, and the Section 174 research and experimental deduction.

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(C)	FAIR VALUE MEASUREMENTS

As of March 31, 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 March 31, 2017:	Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Net Asset Value as a Practical Expedient (NAV)				Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives(a)(b)	$	274			$	213			$	—			$	—			$	487
Interest rate derivatives	—				13				—				—				13
Nuclear decommissioning trusts(c)	714				942				—				21				1,677
Cash equivalents	589				—				—				—				589
Other investments	9				—				1				—				10
Total	$	1,586			$	1,168			$	1			$	21			$	2,776
Liabilities:
Energy-related derivatives(a)(b)	$	303			$	155			$	—			$	—			$	458
Interest rate derivatives	—				32				—				—				32
Foreign currency derivatives	—				62				—				—				62
Contingent consideration	—				—				20				—				20
Total	$	303			$	249			$	20			$	—			$	572
Alabama Power
Assets:
Energy-related derivatives	$	—			$	11			$	—			$	—			$	11
Nuclear decommissioning trusts:(d)
Domestic equity	405				77				—				—				482
Foreign equity	52				51				—				—				103
U.S. Treasury and government agency securities	—				28				—				—				28
Corporate bonds	22				143				—				—				165
Mortgage and asset backed securities	—				18				—				—				18
Private Equity	—				—				—				21				21
Other	—				7				—				—				7
Cash equivalents	555				—				—				—				555
Total	$	1,034			$	335			$	—			$	21			$	1,390
Liabilities:
Energy-related derivatives	$	—			$	10			$	—			$	—			$	10

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	Fair Value Measurements Using:
As of March 31, 2017:	Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Net Asset Value as a Practical Expedient (NAV)				Total
	(in millions)
Georgia Power
Assets:
Energy-related derivatives	$	—			$	24			$	—			$	—			$	24
Interest rate derivatives	—				2				—				—				2
Nuclear decommissioning trusts:(d) (e)
Domestic equity	216				1				—				—				217
Foreign equity	—				137				—				—				137
U.S. Treasury and government agency securities	—				196				—				—				196
Municipal bonds	—				70				—				—				70
Corporate bonds	—				168				—				—				168
Mortgage and asset backed securities	—				41				—				—				41
Other	19				5				—				—				24
Cash equivalents	—				—				—				—				—
Total	$	235			$	644			$	—			$	—			$	879
Liabilities:
Energy-related derivatives	$	—			$	13			$	—			$	—			$	13
Interest rate derivatives	—				4				—				—				4
Total	$	—			$	17			$	—			$	—			$	17
Gulf Power
Assets:
Energy-related derivatives	$	—			$	2			$	—			$	—			$	2
Cash equivalents	21				—				—				—				21
Total	$	21			$	2			$	—			$	—			$	23
Liabilities:
Energy-related derivatives	$	—			$	31			$	—			$	—			$	31
Mississippi Power
Assets:
Energy-related derivatives	$	—			$	3			$	—			$	—			$	3
Interest rate derivatives	—				4				—				—				4
Total	$	—			$	7			$	—			$	—			$	7
Liabilities:
Energy-related derivatives	$	—			$	12			$	—			$	—			$	12

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	Fair Value Measurements Using:
As of March 31, 2017:	Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Net Asset Value as a Practical Expedient (NAV)				Total
	(in millions)
Southern Power
Assets:
Energy-related derivatives	$	—			$	15			$	—			$	—			$	15
Liabilities:
Energy-related derivatives	$	—			$	5			$	—			$	—			$	5
Foreign currency derivatives	—				62				—				—				62
Contingent consideration	—				—				20				—				20
Total	$	—			$	67			$	20			$	—			$	87
Southern Company Gas
Assets:
Energy-related derivatives(a)(b)	$	274			$	158			$	—			$	—			$	432
Liabilities:
Energy-related derivatives(a)(b)	$	303			$	84			$	—			$	—			$	387

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

(b)	Excludes cash collateral of $92 million.

(c)	For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.

(d)	Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies.

(e)	Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of March 31, 2017, approximately $56 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program.

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds at Southern Company, including reinvested interest and dividends and excluding the funds' expenses, increased by $63 million and $20 million for the three months ended March 31, 2017 and 2016, respectively. Alabama Power recorded an increase in fair value of $34 million and $11 million for the three months ended March 31, 2017 and 2016, respectively, as a change in regulatory liabilities related to its AROs. Georgia Power recorded an increase in fair value of $29 million and $9 million for the three months ended March 31, 2017 and 2016, respectively, as a change in its regulatory asset related to its AROs.

Valuation Methodologies

The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of

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

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

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

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

As of March 31, 2017, the fair value measurements of private equity investments held in the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:

As of March 31, 2017:	Fair Value				Unfunded Commitments				Redemption Frequency		Redemption Notice Period
	(in millions)
Southern Company	$	21			$	22			Not Applicable		Not Applicable
Alabama Power	$	21			$	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, a fund that invests 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 March 31, 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	$	45,881			$	46,828
Alabama Power	$	7,439			$	7,807
Georgia Power	$	11,362			$	11,777
Gulf Power	$	1,079			$	1,110
Mississippi Power	$	2,977			$	2,909
Southern Power	$	5,648			$	5,694
Southern Company Gas	$	5,268			$	5,487

The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas.

(D)	STOCKHOLDERS' EQUITY

Earnings per Share

For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:

	Three Months Ended March 31, 2017			Three Months Ended March 31, 2016
	(in millions)
As reported shares	993			916
Effect of options and performance share award units	7			6
Diluted shares	1,000			922

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 months ended March 31, 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									Noncontrolling Interests(*)
	(in thousands)					(in millions)
Balance at December 31, 2016	991,213		(819	)		$	24,758		$	609		$	1,245			$	26,612
Consolidated net income attributable to Southern Company	—		—			658			—			—				658
Other comprehensive income (loss)	—		—			(9		)	—			—				(9		)
Stock issued	4,240		—			186			—			—				186
Stock-based compensation	—		—			57			—			—				57
Cash dividends on common stock	—		—			(556		)	—			—				(556		)
Contributions from noncontrolling interests	—		—			—			—			71				71
Distributions to noncontrolling interests	—		—			—			—			(18		)		(18		)
Net income attributable to noncontrolling interests	—		—			—			—			(4		)		(4		)
Other	—		(35	)		—			—			(1		)		(1		)
Balance at March 31, 2017	995,453		(854	)		$	25,094		$	609		$	1,293			$	26,996
Balance at December 31, 2015	915,073		(3,352	)		$	20,592		$	609		$	781			$	21,982
Consolidated net income attributable to Southern Company	—		—			489			—			—				489
Other comprehensive income (loss)	—		—			(114		)	—			—				(114		)
Stock issued	6,572		—			270			—			—				270
Stock-based compensation	—		—			57			—			—				57
Cash dividends on common stock	—		—			(497		)	—			—				(497		)
Contributions from noncontrolling interests	—		—			—			—			129				129
Distributions to noncontrolling interests	—		—			—			—			(4		)		(4		)
Purchase of membership interests from noncontrolling interests	—		—			—			—			(129		)		(129		)
Net income attributable to noncontrolling interests	—		—			—			—			1				1
Other	—		(35	)					—			—				—
Balance at March 31, 2016	921,645		(3,387	)		$	20,797		$	609		$	778			$	22,184

(*)

Related to Southern Power Company and excludes redeemable noncontrolling interests. Subsequent to March 31, 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 March 31, 2017, Mississippi Power's current liabilities exceeded current assets by approximately $1.2 billion primarily due to a $1.2 billion unsecured term loan that matures on March 30, 2018 and $35 million in senior notes that mature on November 15, 2017, as well as $36 million of short-term notes payable, $40 million of tax-exempt variable rate demand obligations, and $50 million of pollution control bonds that are required to be remarketed over the next 12 months. Mississippi Power expects the funds needed to satisfy maturing debt obligations will exceed amounts available from operating cash flows, lines of credit, and other external sources. Accordingly, Mississippi Power intends to satisfy these obligations through loans and/or equity contributions from Southern Company. Specifically, Mississippi Power has been informed by Southern Company that, in the event sufficient funds are not available from external sources, Southern Company intends to provide Mississippi Power with loans and/or equity contributions sufficient to fund the remaining indebtedness scheduled to mature and other cash needs over the next 12 months. Therefore, Mississippi Power's financial statement presentation contemplates continuation of Mississippi Power as a going concern as a result of Southern Company's anticipated ongoing financial support of Mississippi Power, consistent with GAAP. For additional information, see Notes 1 and 6 to the financial statements of Mississippi Power under "Recently Issued Accounting Standards" and "Going Concern," respectively, in Item 8 of the Form 10-K.

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.

Advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.

Future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, accuracy of project-related representations and warranties, delivery of updated project-related information, absence of liens on Georgia Power's ownership interest in Plant Vogtle Units 3 and 4 other than permitted liens, evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs. The Contractor's bankruptcy and failure to perform its obligations under the Vogtle 3 and 4 Agreement could impact Georgia Power's ability to make further borrowings under the Loan Guarantee Agreement.

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 Vogtle 3 and 4 Agreement under certain circumstances; (ii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (iii) 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. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility.

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

In connection with any cancellation of Plant Vogtle Units 3 and 4 that results in a mandatory prepayment event, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume Georgia Power's rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of Georgia Power's ownership interest in Plant Vogtle Units 3 and 4.

See Note (B) under "Regulatory Matters – Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

Bank Credit Arrangements

Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional electric operating companies' pollution control revenue bonds. The amount of variable rate pollution control revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of March 31, 2017 was approximately $1.9 billion (comprised of approximately $890 million at Alabama Power, $868 million at Georgia Power, $82 million at Gulf Power, and $40 million at Mississippi Power). In addition, at March 31, 2017, the traditional electric operating companies had approximately $386 million (comprised of approximately $250 million at Georgia Power, $86 million at Gulf Power, and $50 million at Mississippi Power) of fixed rate 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.

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

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

(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 $1.3 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.

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

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Financing Activities

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

Company(a)	Senior Note Issuances				Senior Note Maturities and Redemptions				Other Long-Term Debt Issuances				Other Long-Term Debt Redemptions and Maturities(b)
	(in millions)
Southern Company(c)	$	—			$	—			$	—			$	400
Alabama Power	550				200				—				—
Georgia Power	850				—				—				2
Gulf Power	—				—				6				—
Southern Power	—				—				3				2
Other	—				—				—				4
Southern Company Consolidated	$	1,400			$	200			$	9			$	408

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

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

(c)	Represents the Southern Company parent entity.

Southern Company

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

Alabama Power

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

Georgia Power

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

Gulf Power

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

Mississippi Power

On February 28, 2017, Mississippi Power amended $551 million in promissory notes to Southern Company extending the maturity dates of the notes from December 1, 2017 to July 31, 2018.

On March 31, 2017, Mississippi Power issued a $9 million short-term note bearing interest at 5% per annum, which was repaid on April 27, 2017.

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(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 operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.

In addition, Southern Company Gas has a qualified defined benefit, trusteed, pension plan covering certain eligible employees, which was closed in 2012 to new employees. This qualified pension plan is funded in accordance with requirements of ERISA. No mandatory contributions to the Southern Company Gas qualified pension plan are anticipated for the year ending December 31, 2017. Southern Company Gas also provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company Gas provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. Southern Company Gas also has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.

See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Company Gas in Item 8 of the Form 10-K for additional information.

Components of the net periodic benefit costs for the three months ended March 31, 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 March 31, 2017
Service cost	$	73			$	16			$	19			$	3			$	4
Interest cost	114				24				34				5				5
Expected return on plan assets	(224		)		(49		)		(71		)		(10		)		(10		)
Amortization:
Prior service costs	3				1				1				—				—
Net (gain)/loss	40				10				14				2				2
Net periodic pension cost (income)	$	6			$	2			$	(3	)		$	—			$	1
Three Months Ended March 31, 2016
Service cost	$	62			$	14			$	17			$	3			$	3
Interest cost	100				24				34				5				5
Expected return on plan assets	(187		)		(46		)		(64		)		(9		)		(9		)
Amortization:
Prior service costs	4				1				1				—				—
Net (gain)/loss	38				10				14				2				2
Net periodic pension cost	$	17			$	3			$	2			$	1			$	1

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Pension Plans	Southern Company Gas
	(in millions)
Successor – Three Months Ended March 31, 2017
Service cost	$	6
Interest cost	10
Expected return on plan assets	(18		)
Amortization:
Prior service costs	—
Net (gain)/loss	5
Net periodic pension cost	$	3
Predecessor – Three Months Ended March 31, 2016
Service cost	$	6
Interest cost	10
Expected return on plan assets	(16		)
Amortization:
Prior service costs	—
Net (gain)/loss	6
Net periodic pension cost	$	6

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

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Postretirement Benefits	Southern Company Gas
	(in millions)
Successor – Three Months Ended March 31, 2017
Service cost	$	1
Interest cost	3
Expected return on plan assets	(2		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	1
Net periodic postretirement benefit cost	$	2
Predecessor – Three Months Ended March 31, 2016
Service cost	$	1
Interest cost	3
Expected return on plan assets	(2		)
Amortization:
Prior service costs	(1		)
Net (gain)/loss	1
Net periodic postretirement benefit cost	$	2

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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 March 31, 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 acquisition of additional renewable projects and carrying back the federal net operating loss, as well as potential tax reform legislation on existing renewable incentives, could further delay existing tax credit carryforwards. The ultimate outcome of these matters cannot be determined at this time.

Effective Tax Rate

Southern Company

Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity, and federal income tax benefits from ITCs and PTCs.

Southern Company's effective tax rate was 32.1% for the three months ended March 31, 2017 compared to 30.2% for the corresponding period in 2016. The effective tax rate increase was primarily due to higher pre-tax earnings resulting from the Merger with Southern Company Gas and decreased tax benefits from ITCs, partially offset by an increase in tax benefits from wind PTCs and state apportionment rate changes.

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 (58.7)% for the three months ended March 31, 2017 compared to (850.4)% for the corresponding period in 2016. The effective tax rate increase was primarily due to the estimated probable losses on construction of the Kemper IGCC.

Southern Power

Southern Power's effective tax (benefit) rate was (385.9)% for the three months ended March 31, 2017 compared to (84.0)% 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.

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(UNAUDITED)

Changes during the three months ended March 31, 2017 for unrecognized tax benefits were as follows:

	Mississippi Power				Southern Power				Southern Company
	(in millions)
Unrecognized tax benefits as of December 31, 2016	$	465			$	17			$	484
Tax positions from current periods	3				1				9
Tax positions from prior periods	—				—				7
Balance as of March 31, 2017	$	468			$	18			$	500

The tax positions from current and prior periods primarily relate to state tax benefits and charitable contribution carryforwards that will be impacted as a result of the proposed settlement of research and experimental (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 March 31, 2017												As of December 31, 2016
	Mississippi Power				Southern Power				Southern Company				Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	4			$	18			$	36			$	20
Tax positions not impacting the effective tax rate	464				—				464				464
Balance of unrecognized tax benefits	$	468			$	18			$	500			$	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 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

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(UNAUDITED)

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 Internal Revenue Code 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 $32 million as of March 31, 2017. 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.

(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 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

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(UNAUDITED)

Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.

Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in the statements of income.

Energy-related derivative contracts are accounted for under one of three methods:

•

Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.

•	Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.

•	Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

At March 31, 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(*)	503		2021		2024
Alabama Power	71		2020		—
Georgia Power	155		2020		—
Gulf Power	42		2020		—
Mississippi Power	37		2021		—
Southern Power	21		2017		2017
Southern Company Gas(*)	177		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 3.4 billion mmBtu and short natural gas positions of 3.2 billion mmBtu as of March 31, 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 10 million mmBtu for Southern Company, 4 million mmbtu for Georgia Power, 3 million mmBtu for Southern Power, and 1 million mmBtu for each of Alabama Power, Gulf Power, and Mississippi Power.

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(UNAUDITED)

For cash flow hedges of energy-related derivatives, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending March 31, 2018 are $10 million for Southern Power and immaterial for all other registrants.

Interest Rate Derivatives

Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

At March 31, 2017, the following interest rate derivatives were outstanding:

	Notional Amount				Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date		Fair Value Gain (Loss) at March 31, 2017
	(in millions)								(in millions)
Cash Flow Hedges of Forecasted Debt
Gulf Power	$	80			3-month LIBOR	2.32%	December 2026		$	—
Cash Flow Hedges of Existing Debt
Mississippi Power	900				1-month LIBOR	0.79%	March 2018		4
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		(21		)
Georgia Power	250				5.40%	3-month LIBOR + 4.02%	June 2018		—
Georgia Power	500				1.95%	3-month LIBOR + 0.76%	December 2018		(3		)
Georgia Power	200				4.25%	3-month LIBOR + 2.46%	December 2019		1
Southern Company Consolidated	$	3,980							$	(18	)

(*)	Represents the Southern Company parent entity.

The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending March 31, 2018 are immaterial for all registrants.

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(UNAUDITED)

Southern Company and certain subsidiaries have deferred gains and losses expected to be amortized into earnings through 2046.

Foreign Currency Derivatives

Southern Company and certain subsidiaries may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time that the hedged transactions affect earnings, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

At March 31, 2017, the following foreign currency derivatives were outstanding:

	Pay Notional			Pay Rate	Receive Notional			Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at March 31, 2017
	(in millions)				(in millions)					(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677		2.95%	€	600		1.00%	June 2022	$	(35	)
Southern Power	564			3.78%	500			1.85%	June 2026	(27		)
Total	$	1,241			€	1,100				$	(62	)

The estimated pre-tax gains (losses) related to foreign currency derivatives that will be reclassified from accumulated OCI to earnings for the next 12-month period ending March 31, 2018 are $24 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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(UNAUDITED)

The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:

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

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(UNAUDITED)

	As of March 31, 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	$	9		$	5		$	13		$	5
Other deferred charges and assets/Other deferred credits and liabilities	2			5			7			4
Total derivatives designated as hedging instruments for regulatory purposes	$	11		$	10		$	20		$	9
Gross amounts recognized	$	11		$	10		$	20		$	9
Gross amounts offset	$	(6	)	$	(6	)	$	(8	)	$	(8	)
Net amounts recognized in the Balance Sheets	$	5		$	4		$	12		$	1
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	20		$	2		$	30		$	1
Other deferred charges and assets/Other deferred credits and liabilities	4			11			14			7
Total derivatives designated as hedging instruments for regulatory purposes	$	24		$	13		$	44		$	8
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	2		$	—		$	2		$	—
Other deferred charges and assets/Other deferred credits and liabilities	—			4			—			3
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	2		$	4		$	2		$	3
Gross amounts recognized	$	26		$	17		$	46		$	11
Gross amounts offset	$	(6	)	$	(6	)	$	(8	)	$	(8	)
Net amounts recognized in the Balance Sheets	$	20		$	11		$	38		$	3
Gulf Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Liabilities from risk management activities	$	2		$	14		$	4		$	12
Other deferred charges and assets/Other deferred credits and liabilities	—			17			1			17
Total derivatives designated as hedging instruments for regulatory purposes	$	2		$	31		$	5		$	29
Gross amounts recognized	$	2		$	31		$	5		$	29
Gross amounts offset	$	(2	)	$	(2	)	$	(4	)	$	(4	)
Net amounts recognized in the Balance Sheets	$	—		$	29		$	1		$	25

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(UNAUDITED)

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

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(UNAUDITED)

	As of March 31, 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	$	14		$	2		$	24		$	3
Other deferred charges and assets/Other deferred credits and liabilities	—			—			1			—
Total derivatives designated as hedging instruments for regulatory purposes	$	14		$	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	$	1		$	1		$	4		$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	304		$	270		$	486		$	482
Other deferred charges and assets/Other deferred credits and liabilities	132			114			66			81
Total derivatives not designated as hedging instruments	$	436		$	384		$	552		$	563
Gross amounts of recognized	$	451		$	387		$	581		$	569
Gross amounts offset(*)	$	(272	)	$	(364	)	$	(435	)	$	(497	)
Net amounts recognized in the Balance Sheets	$	179		$	23		$	146		$	72

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

At March 31, 2017 and December 31, 2016, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at March 31, 2017
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	$	(19	)	$	(1	)	$	—		$	(12	)	$	(5	)	$	(1	)
Other regulatory assets, deferred	(32		)	(3		)	(7		)	(17		)	(5		)	—
Other regulatory liabilities, current(a)	33			5			18			—			1			9
Total energy-related derivative gains (losses)	$	(18	)	$	1		$	11		$	(29	)	$	(9	)	$	8

(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 $4 million at March 31, 2017.

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(UNAUDITED)

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2016
Derivative Category and Balance Sheet Location	Southern Company(c)			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas(c)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(16	)	$	(1	)	$	—		$	(9	)	$	(5	)	$	(1	)
Other regulatory assets, deferred	(19		)	—			—			(16		)	(3		)	—
Other regulatory liabilities, current(a)	56			8			29			1			1			17
Other regulatory liabilities, deferred(b)	12			4			7			—			—			1
Total energy-related derivative gains (losses)	$	33		$	11		$	36		$	(24	)	$	(7	)	$	17

(a)	Georgia Power includes other regulatory liabilities, current in other current liabilities.

(b)	Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.

(c)	Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $8 million at December 31, 2016.

For the three months ended March 31, 2017 and 2016, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments were as follows:

Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)								Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
									Statements of Income Location	Amount
	2017				2016					2017				2016
	(in millions)									(in millions)
Southern Company
Energy-related derivatives	$	(11	)		$	—			Depreciation and amortization	$	(4	)		$	(1	)
Interest rate derivatives	1				(190		)		Interest expense, net of amounts capitalized	(5		)		(3		)
Foreign currency derivatives	(4		)		—				Interest expense, net of amounts capitalized	(6		)		—
									Other income (expense), net(*)	17				—
Total	$	(14	)		$	(190	)			$	2			$	(4	)
Gulf Power
Energy-related derivatives	$	(1	)		$	—			Depreciation and amortization	$	—			$	—
Interest rate derivatives	—				(5		)		Interest expense, net of amounts capitalized	—				—
Total	$	(1	)		$	(5	)			$	—			$	—
Southern Power
Energy-related derivatives	$	(8	)		$	—			Depreciation and amortization	$	(4	)		$	(1	)
Foreign currency derivatives	(4		)		—				Interest expense, net of amounts capitalized	(6		)		—
									Other income (expense), net(*)	17				—
Total	$	(12	)		$	—				$	7			$	(1	)

(*)	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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(UNAUDITED)

For Southern Company Gas, the pre-tax effect of energy related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings for the three months ended March 31, 2017 and the predecessor period of January 1, 2016 through March 31, 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 March 31, 2017					Three Months Ended March 31, 2016				Statements of Income Location	Three Months Ended March 31, 2017					Three Months Ended March 31, 2016
	(in millions)					(in millions)					(in millions)					(in millions)
Energy-related derivatives	$	(2	)			$	—			Cost of natural gas	$	—				$	—
Interest rate derivatives	—					(45		)		Interest expense, net of amounts capitalized	—					1
Total	$	(2	)			$	(45	)			$	—				$	1

For the three months ended March 31, 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 months ended March 31, 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 March 31,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2017				2016
		(in millions)
Southern Company
Energy Related derivatives:	Natural gas revenues(*)	$	50			$	—
	Cost of natural gas	(3		)		—
Total derivatives in non-designated hedging relationships		$	47			$	—

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

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(UNAUDITED)

		Gain (Loss)
		Successor					Predecessor
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	Three Months Ended March 31, 2017					Three Months Ended March 31, 2016
		(in millions)					(in millions)
Southern Company Gas
Energy Related derivatives:	Natural gas revenues(*)	$	50				$	20
	Cost of natural gas	(3		)			(1		)
Total derivatives in non-designated hedging relationships		$	47				$	19

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

For the three months ended March 31, 2017 and 2016, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies and Southern Power.

For the three months ended March 31, 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 March 31,
Derivative Category	Statements of Income Location	2017				2016
		(in millions)
Southern Company
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	(8	)		$	20
Georgia Power
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	(1	)		$	14

For the three months ended March 31, 2017 and 2016, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt.

There was no material ineffectiveness recorded in earnings for any registrant for any period presented.

Contingent Features

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At March 31, 2017, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

At March 31, 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, $9 million for the traditional electric operating companies and Southern Power, and $2 million for Southern Company Gas. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade.

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(UNAUDITED)

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.

Alabama Power maintains 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 may be required to post collateral. At March 31, 2017, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At March 31, 2017, cash collateral held on deposit in broker margin accounts was $92 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.

(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.

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(UNAUDITED)

The Merger was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the purchase price allocation:

Southern Company Gas Purchase Price
	(in millions)
Current assets	$	1,557
Property, plant, and equipment	10,108
Goodwill	5,967
Intangible assets	400
Regulatory assets	1,118
Other assets	229
Current liabilities	(2,201		)
Other liabilities	(4,742		)
Long-term debt	(4,261		)
Noncontrolling interest	(174		)
Total purchase price	$	8,001

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $6.0 billion is recognized as goodwill, which is primarily attributable to positioning the Southern Company system to provide natural gas infrastructure to meet customers' growing energy needs and to compete for growth across the energy value chain. Southern Company anticipates that much of the value assigned to goodwill will not be deductible for tax purposes.

The valuation of identifiable intangible assets included customer relationships, trade names, and storage and transportation contracts with estimated lives of one to 28 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).

The results of operations for Southern Company Gas have been included in Southern Company's consolidated financial statements from the date of acquisition and consist of operating revenues of $1.6 billion and net income of $239 million for the three months ended March 31, 2017.

The following summarized unaudited pro forma consolidated statement of earnings information assumes that the acquisition of Southern Company Gas was completed on January 1, 2015. The summarized unaudited pro forma consolidated statement of earnings information includes adjustments for (i) intercompany sales, (ii) amortization of intangible assets, (iii) adjustments to interest expense to reflect current interest rates on Southern Company Gas debt and additional interest expense associated with borrowings by Southern Company to fund the Merger, and (iv) the elimination of nonrecurring expenses associated with the Merger.

	For the Three Months Ended March 31,
	2016
Operating revenues (in millions)	$	5,320
Net income attributable to Southern Company (in millions)	$	650
Basic EPS	$	0.70
Diluted EPS	$	0.69

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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Acquisition of PowerSecure

On May 9, 2016, Southern Company acquired all of the outstanding stock of PowerSecure, a provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, for $18.75 per common share in cash, resulting in an aggregate purchase price of $429 million. As a result, PowerSecure became a wholly-owned subsidiary of Southern Company.

The acquisition of PowerSecure was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the purchase price allocation:

PowerSecure Purchase Price
	(in millions)
Current assets	$	172
Property, plant, and equipment	46
Intangible assets	101
Goodwill	282
Other assets	4
Current liabilities	(114		)
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 $282 million was recognized as goodwill, which is primarily attributable to expected business expansion opportunities for PowerSecure. Southern Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes.

The valuation of identifiable intangible assets included customer relationships, trade names, patents, backlog, and software with estimated lives of one to 26 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).

The results of operations for PowerSecure have been included in Southern Company's consolidated financial statements from the date of acquisition and are immaterial to the consolidated financial results of Southern Company. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were immaterial to Southern Company's consolidated financial results for all periods presented.

Southern Power

See Note 2 to the financial statements of Southern Power and Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K for additional information.

Acquisitions During the Three Months Ended March 31, 2017

During the three months ended March 31, 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.

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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

The aggregate amount of revenue recognized by Southern Power related to the Bethel facility included in Southern Power's condensed consolidated statements of income during the first quarter 2017 is $4 million. The aggregate amount of net income, excluding impacts from PTCs, recognized by Southern Power during the three months ended March 31, 2017 included in Southern Power's condensed consolidated statements of income was 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 2016 acquisitions, subsequent to March 31, 2017, allocations of the purchase price to individual assets were finalized with no changes to amounts originally reported for Boulder 1, Grant Plains, Grant Wind, Passadumkeag, and Wake Wind.

Construction Projects Completed and in Progress

During the three months ended March 31, 2017, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through March 31, 2017, total costs of construction incurred for these three projects were $401 million, of which $203 million remained in CWIP for the Lamesa and Mankato facilities acquired in 2016. Total aggregate construction costs, excluding the acquisition costs, are expected to be $530 million to $590 million for these two facilities that were under construction at March 31, 2017. The ultimate outcome of these matters cannot be determined at this time.

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Project Completed During the Three Months Ended March 31, 2017
East Pecos	Solar	120	Pecos County, TX	March 2017	15 years
Projects Under Construction as of March 31, 2017
Lamesa	Solar	102	Dawson County, TX	April 2017	15 years
Mankato	Natural Gas	345	Mankato, MN	Second quarter 2019	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.

(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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments as of March 31, 2017 and December 31, 2016 and related income from those investments for the successor period ended March 31, 2017 and the predecessor period ended March 31, 2016 were as follows:

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

	Successor					Predecessor
Income Statement Information	Three Months Ended March 31, 2017					Three Months Ended March 31, 2016
	(in millions)					(in millions)
SNG	$	34				$	—
Horizon Pipeline	1					1
PennEast Pipeline	3					—
Atlantic Coast Pipeline	1					—
Total	$	39				$	1

Southern Natural Gas

In September 2016, Southern Company Gas, through a wholly-owned, indirect subsidiary, acquired a 50% equity interest in SNG, which is accounted for as an equity method investment. On March 31, 2017, Southern Company Gas made an additional $50 million contribution to maintain its 50% equity interest in SNG. See Note 11 to the financial statements of Southern Company Gas under "Investment in SNG" in Item 8 of the Form 10-K for additional information on this investment. Selected financial information of SNG for the first quarter 2017 is as follows:

Income Statement Information	Three Months Ended March 31, 2017
	(in millions)
Revenues	$	155
Operating income	$	84
Net income	$	66

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(K) SEGMENT AND RELATED INFORMATION

Southern Company

The primary business of the Southern Company system is electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through the seven natural gas distribution utilities in seven states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations.

Southern Company's reportable business segments are the sale of electricity by the four traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $100 million for the three months ended March 31, 2017 and $97 million for the three months ended March 31, 2016. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers; as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.

Financial data for business segments and products and services for the three months ended March 31, 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 March 31, 2017:
Operating revenues	$	3,786		$	450		$	(105	)	$	4,131		$	1,560		$	123		$	(43	)	$	5,771
Segment net income (loss)(a)(b)(c)	432			70			—			502			239			(84		)	1			658
Total assets at March 31, 2017	$	72,692		$	14,681		$	(306	)	$	87,067		$	21,683		$	2,574		$	(1,564	)	$	109,760
Three Months Ended March 31, 2016:
Operating revenues	$	3,769		$	315		$	(103	)	$	3,981		$	—		$	47		$	(36	)	$	3,992
Segment net income (loss)(a)(b)	465			50			—			515			—			(23		)	(3		)	489
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 $108 million ($67 million after tax) and $53 million ($33 million after tax) for the three months ended March 31, 2017 and 2016, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.

(c)	Segment net income (loss) for the traditional electric operating companies also includes a pre-tax charge for the write-down of Gulf Power's ownership of Plant Scherer Unit 3 of $33 million ($20 million after tax) for the three months ended March 31, 2017. See Note (B) under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" for additional information.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Products and Services

		Electric Utilities' Revenues
Period		Retail				Wholesale				Other				Total
		(in millions)
Three Months Ended March 31, 2017		$	3,394			$	531			$	206			$	4,131
Three Months Ended March 31, 2016		3,377				396				208				3,981

	Southern Company Gas' Revenues
Period	Gas Distribution Operations			Gas Marketing Services			Other			Total
	(in millions)
Three Months Ended March 31, 2017	$	1,132		$	288		$	140		$	1,560

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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Business segment financial data for the successor period January 1, 2017 through March 31, 2017 and the predecessor period January 1, 2016 through March 31, 2016 was as follows:

	Gas Distribution Operations			Gas Marketing Services			Wholesale Gas Services(*)			Gas Midstream Operations			Total			All Other			Eliminations			Consolidated
	(in millions)
Successor – January 1, 2017 through March 31, 2017:
Operating revenues	$	1,180		$	288		$	131		$	25		$	1,624		$	2		$	(66	)	$	1,560
Segment net income	117			31			68			15			231			8			—			239
Successor – Total assets at March 31, 2017	$	18,201		$	2,118		$	1,018		$	2,363		$	23,700		$	10,860		$	(12,877	)	$	21,683
Predecessor – January 1, 2016 through March 31, 2016:
Operating revenues	$	1,028		$	286		$	63		$	15		$	1,392		$	2		$	(60	)	$	1,334
Segment EBIT	235			80			44			(1		)	358			(5		)	(1		)	352
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 – January 1, 2017 through March 31, 2017	$	1,839			$	136			$	1,975			$	1,844			$	131
Predecessor – January 1, 2016 through March 31, 2016	$	1,443			$	81			$	1,524			$	1,461			$	63

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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 Westinghouse and WECTEC is expected to have a material impact on the construction cost and schedule of Plant Vogtle Units 3 and 4 and could have a material impact on the financial statements of Southern Company and Georgia Power, and any inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4, and therefore on the financial statements of Southern Company and Georgia Power.

See "Construction Risk" in Item 1A – Risk Factors of Southern Company and Georgia Power in the Form 10-K for a discussion of risks relating to major construction projects, including Plant Vogtle Units 3 and 4 and see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Nuclear Construction" herein and Note (E) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information.

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

The Interim Assessment Agreement provides, among other items, that (i) Georgia Power will be obligated to pay, on behalf of the Vogtle Owners, all costs accrued by the Contractor for subcontractors and vendors for services performed or goods provided during the Interim Assessment Period, with these amounts to be paid to the Contractor, except for amounts accrued for Fluor Corporation (Fluor), which will be paid directly to Fluor; (ii) during the Interim Assessment Period, the Contractor shall provide certain engineering, procurement, and management services for Plant Vogtle Units 3 and 4, to the same extent as contemplated by the engineering, procurement, and construction agreement with the Contractor (the Vogtle 3 and 4 Agreement), and Georgia Power, on behalf of the Vogtle Owners, will make payments of $5.4 million per week for these services; (iii) Georgia Power will have the right to make payments, on behalf of the Vogtle Owners, directly to subcontractors and vendors who have accounts past due with the Contractor; (iv) during the Interim Assessment Period, the Contractor will use its commercially reasonable efforts to provide information reasonably requested by Georgia Power as is necessary to continue construction and investigate the completion status of Plant Vogtle Units 3 and 4; (v) the Contractor will reject or accept the Vogtle 3 and 4 Agreement by the termination of the Interim Assessment Agreement; and (vi) during the Interim Assessment Period, Georgia Power will not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserve all rights and remedies under the Vogtle 3 and 4 Agreement, all related security and collateral, under applicable law.

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A number of subcontractors to the Contractor, including Fluor Enterprises, Inc. (Fluor Enterprises), have alleged non-payment by the Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken, and continues to take, action to remove liens filed by these subcontractors through the posting of surety bonds.

Georgia Power estimates the aggregate liability for the Vogtle Owners under the Interim Assessment Agreement and the removal of subcontractor liens to be approximately $470 million, of which Georgia Power's proportionate share would total approximately $215 million. As of March 31, 2017, $245 million of this aggregate liability had been paid or accrued. Georgia Power is evaluating remedies available to the Vogtle Owners for these payments, including draws under the $920 million of letters of credit delivered by Westinghouse (Westinghouse Letters of Credit) and enforcement of the Toshiba Guarantee.

The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million. In the event of an abandonment of work by the Contractor, the maximum liability of the Contractor under the Vogtle 3 and 4 Agreement is increased to 40% of the contract price (approximately $1.7 billion based on Georgia Power's ownership interest). The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for convenience, provided that the Vogtle Owners will be required to pay certain termination costs. In addition, the Vogtle Owners may terminate the Vogtle 3 and 4 Agreement for certain Contractor breaches, including abandonment of work by the Contractor.

Under the Toshiba Guarantee, Toshiba has guaranteed certain payment obligations of the Contractor, including any liability of the Contractor for abandonment of work. However, due to Toshiba's financial situation described below, substantial risk regarding the Vogtle Owners' ability to fully collect under the Toshiba Guarantee exists. In January 2016, Westinghouse delivered to the Vogtle Owners $920 million of letters of credit from financial institutions to secure a portion of the Contractor's potential obligations under the Vogtle 3 and 4 Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020 and require 60 days' written notice to Georgia Power in the event the Westinghouse Letters of Credit will not be renewed. In the event of such notice, the Vogtle Owners would be able to draw on the entire balance of the Westinghouse Letters of Credit. The Westinghouse Letters of Credit remain in place in accordance with the terms of the Vogtle 3 and 4 Agreement.

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

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

The Contractor's bankruptcy filing is expected to have a material impact on the construction cost and schedule of, as well as the cost recovery for, Plant Vogtle Units 3 and 4 and could have a material impact on Southern Company's

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and Georgia Power's financial statements. In addition, an inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a further material impact on the net cost to the Vogtle Owners to complete construction of Plant Vogtle Units 3 and 4 and, therefore, on Southern Company's and Georgia Power's financial statements.

The ultimate outcome of these matters also is dependent on the results of the assessments currently underway, as well as the related regulatory treatment, and cannot be determined at this time.

Item 5. Other Information.

On April 28, 2017, the Board of Directors of Gulf Power approved certain amendments to Section 7 of Gulf Power's Bylaws, effective as of July 1, 2017, to limit the service of directors, other than directors who are full-time executive employees of Gulf Power, Southern Company, or its affiliates, to no more than 12 years unless otherwise determined by the Board of Directors.

On May 1, 2017, the Board of Directors of Mississippi Power approved certain amendments to Section 2.02 of Mississippi Power's Bylaws, effective as of July 1, 2017, to limit the service of directors, other than directors who are full-time executive employees of Mississippi Power, Southern Company, or its affiliates, to no more than 12 years unless otherwise determined by the Board of Directors.

Item 6.    Exhibits.

The exhibits below with an asterisk (*) preceding the exhibit number are filed herewith. The remaining exhibits have previously been filed with the SEC and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements.

		(3) Articles of Incorporation and By-Laws
		Gulf Power
	*	(d)		By-Laws of Gulf Power, as amended, effective July 1, 2017.
		Mississippi Power
	*	(e)		By-Laws of Mississippi Power, as amended, effective July 1, 2017.
		(4) Instruments Describing Rights of Security Holders, Including Indentures
		Alabama Power
		(b)	-	Fifty-Sixth Supplemental Indenture to Senior Note Indenture, dated as of March 3, 2017, providing for the issuance of the Series 2017A 2.45% Senior Notes due March 30, 2022. (Designated in Form 8-K dated February 27, 2017, File No. 1-3164, as Exhibit 4.6.)
		Georgia Power
		(c)1	-	Fifty-Sixth Supplemental Indenture to Senior Note Indenture, dated as of March 3, 2017, providing for the issuance of the Series 2017A 2.00% Senior Notes due March 30, 2020. (Designated in Form 8-K dated February 28, 2017, File No. 1-6468, as Exhibit 4.2(a).)
		(c)2	-	Fifty-Seventh Supplemental Indenture to Senior Note Indenture, dated as of March 3, 2017, providing for the issuance of the Series 2017B 3.25% Senior Notes due March 30, 2027. (Designated in Form 8-K dated February 28, 2017, File No. 1-6468, as Exhibit 4.2(b).)

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		(10) Material Contracts
		Southern Company
#	*	(a)1	-	Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan.
#	*	(a)2	-	Form of Terms for Restricted Stock Unit with Performance Measure Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan.
#	*	(a)3	-	Letter Agreement among Southern Company Gas, Southern Company, and Andrew W. Evans and Performance Stock Unit Award Agreement, dated September 29, 2016.
#	*	(a)4	-	Form of Time-Vesting Restricted Stock Unit Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan.
#		(a)5	-	Nonqualified Savings Plan as amended and restated as of January 1, 2009, First Amendment effective December 18, 2009, Second Amendment effective January 1, 2013, and Third Amendment effective January 1, 2013. (Designated in Form 10-K for the year ended December 31, 2008, File No. 1-14174, as Exhibit 10.1.av and in Form 10-K for the year ended December 31, 2013, File No. 1-14174, as Exhibits 10.1.aa, 10.1.ab, and 10.1.ac.)
#		(a)6	-	Excess Benefit Plan as amended and restated as of January 1, 2009. (Designated in Form 10-K for the year ended December 31, 2008, File No. 1-14174, as Exhibit 10.1.az.)
		Alabama Power
#		(b)1	-	Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)1 herein.
#		(b)2	-	Form of Terms for Restricted Stock Unit with Performance Measure Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
		Georgia Power
#		(c)1	-	Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)1 herein.
#		(c)2	-	Form of Terms for Restricted Stock Unit with Performance Measure Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
	*	(c)3	-	Interim Assessment Agreement dated as of March 29, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse, WECTEC Staffing Services LLC, and WECTEC.
	*	(c)4	-	Amendment No. 1 to Interim Assessment Agreement dated as of March 29, 2017, by and among Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and The City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse, WECTEC Staffing Services LLC, and WECTEC.
		Gulf Power
#		(d)1	-	Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)1 herein.

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#		(d)2	-	Form of Terms for Restricted Stock Unit with Performance Measure Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
		Mississippi Power
#		(e)1	-	Form of Terms for Performance Share Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)1 herein.
#		(e)2	-	Form of Terms for Restricted Stock Unit with Performance Measure Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)2 herein.
	*	(e)3	-	Amended and Restated Promissory Note dated February 28, 2017 between Mississippi Power and Southern Company in the aggregate principal amount of up to $375,000,000.
	*	(e)4	-	Second Amended and Restated Promissory Note dated February 28, 2017 between Mississippi Power and Southern Company in the aggregate principal amount of $301,126,146.39.
	*	(e)5	-	Amended and Restated Promissory Note dated February 28, 2017 between Mississippi Power and Southern Company in the aggregate principal amount of up to $275,000,000.
		(24) Power of Attorney and Resolutions
		Southern Company
		(a)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2016, File No. 1-3526 as Exhibit 24(a).)
		Alabama Power
		(b)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2016, File No. 1-3164 as Exhibit 24(b).)
		Georgia Power
		(c)	-	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).)

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		(31) Section 302 Certifications
		Southern Company
	*	(a)1	-	Certificate of Southern Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(a)2	-	Certificate of Southern Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
		Alabama Power
	*	(b)1	-	Certificate of Alabama Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(b)2	-	Certificate of Alabama Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
		Georgia Power
	*	(c)1	-	Certificate of Georgia Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(c)2	-	Certificate of Georgia Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
		Gulf Power
	*	(d)1	-	Certificate of Gulf Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(d)2	-	Certificate of Gulf Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
		Mississippi Power
	*	(e)1	-	Certificate of Mississippi Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(e)2	-	Certificate of Mississippi Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
		Southern Power
	*	(f)1	-	Certificate of Southern Power Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(f)2	-	Certificate of Southern Power Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
		Southern Company Gas
	*	(g)1	-	Certificate of Southern Company Gas' Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(g)2	-	Certificate of Southern Company Gas' Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

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		(32) Section 906 Certifications
		Southern Company
	*	(a)	-	Certificate of Southern Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
		Alabama Power
	*	(b)	-	Certificate of Alabama Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
		Georgia Power
	*	(c)	-	Certificate of Georgia Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
		Gulf Power
	*	(d)	-	Certificate of Gulf Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
		Mississippi Power
	*	(e)	-	Certificate of Mississippi Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
		Southern Power
	*	(f)	-	Certificate of Southern Power Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
		Southern Company Gas
	*	(g)	-	Certificate of Southern Company Gas' Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
		(101) Interactive Data Files
	*	INS	-	XBRL Instance Document
	*	SCH	-	XBRL Taxonomy Extension Schema Document
	*	CAL	-	XBRL Taxonomy Calculation Linkbase Document
	*	DEF	-	XBRL Definition Linkbase Document
	*	LAB	-	XBRL Taxonomy Label Linkbase Document
	*	PRE	-	XBRL Taxonomy Presentation Linkbase Document

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THE SOUTHERN COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

 

		THE SOUTHERN COMPANY
By		Thomas A. Fanning
		Chairman, President, and Chief Executive Officer
		(Principal Executive Officer)
By		Art P. Beattie
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)
By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: May 2, 2017

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ALABAMA POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

 

		ALABAMA POWER COMPANY
By		Mark A. Crosswhite
		Chairman, President, and Chief Executive Officer
		(Principal Executive Officer)
By		Philip C. Raymond
		Executive Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)
By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: May 2, 2017

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GEORGIA POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

 

		GEORGIA POWER COMPANY
By		W. Paul Bowers
		Chairman, President, and Chief Executive Officer
		(Principal Executive Officer)
By		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: May 2, 2017

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GULF POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

 

		GULF POWER COMPANY
By		S. W. Connally, Jr.
		Chairman, President and Chief Executive Officer
		(Principal Executive Officer)
By		Xia Liu
		Vice President and Chief Financial Officer
		(Principal Financial Officer)
By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: May 2, 2017

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MISSISSIPPI POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

 

		MISSISSIPPI POWER COMPANY
By		Anthony L. Wilson
		Chairman, President, and Chief Executive Officer
		(Principal Executive Officer)
By		Moses H. Feagin
		Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)
By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: May 2, 2017

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SOUTHERN POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

 

		SOUTHERN POWER COMPANY
By		Joseph A. Miller
		Chairman, President, and Chief Executive Officer
		(Principal Executive Officer)
By		William C. Grantham
		Senior Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)
By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: May 2, 2017

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SOUTHERN COMPANY GAS

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

 

		SOUTHERN COMPANY GAS
By		Andrew W. Evans
		Chairman, President, and Chief Executive Officer
		(Principal Executive Officer)
By		Elizabeth W. Reese
		Executive Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)
By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: May 2, 2017

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