Alabama Power (ALP-PQ) 10-Q 2016 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2016

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

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, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Registrant	Large Accelerated Filer	Accelerated Filer	Non- accelerated Filer	Smaller Reporting 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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ (Response applicable to all registrants.)

Registrant	Description of Common Stock	Shares Outstanding at September 30, 2016
The Southern Company	Par Value $5 Per Share	979,999,480
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	5,642,717
Mississippi Power Company	Without Par Value	1,121,000
Southern Power Company	Par Value $0.01 Per Share	1,000

This combined Form 10-Q is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Southern Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

2

INDEX TO QUARTERLY REPORT ON FORM 10-Q

September 30, 2016

		Page Number
DEFINITIONS		5
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION		7
	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	10
	Condensed Consolidated Statements of Comprehensive Income	11
	Condensed Consolidated Statements of Cash Flows	12
	Condensed Consolidated Balance Sheets	13
	Management's Discussion and Analysis of Financial Condition and Results of Operations	15
	Alabama Power Company
	Condensed Statements of Income	48
	Condensed Statements of Comprehensive Income	48
	Condensed Statements of Cash Flows	49
	Condensed Balance Sheets	50
	Management's Discussion and Analysis of Financial Condition and Results of Operations	52
	Georgia Power Company
	Condensed Statements of Income	66
	Condensed Statements of Comprehensive Income	66
	Condensed Statements of Cash Flows	67
	Condensed Balance Sheets	68
	Management's Discussion and Analysis of Financial Condition and Results of Operations	70
	Gulf Power Company
	Condensed Statements of Income	89
	Condensed Statements of Comprehensive Income	89
	Condensed Statements of Cash Flows	90
	Condensed Balance Sheets	91
	Management's Discussion and Analysis of Financial Condition and Results of Operations	93
	Mississippi Power Company
	Condensed Statements of Income	108
	Condensed Statements of Comprehensive Income	108
	Condensed Statements of Cash Flows	109
	Condensed Balance Sheets	110
	Management's Discussion and Analysis of Financial Condition and Results of Operations	112
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	139
	Condensed Consolidated Statements of Comprehensive Income	139
	Condensed Consolidated Statements of Cash Flows	140
	Condensed Consolidated Balance Sheets	141
	Management's Discussion and Analysis of Financial Condition and Results of Operations	143
	Notes to the Condensed Financial Statements	157
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	45
Item 4.	Controls and Procedures	45

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q

September 30, 2016

		Page Number
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	218
Item 1A.	Risk Factors	218
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	Inapplicable
Item 3.	Defaults Upon Senior Securities	Inapplicable
Item 4.	Mine Safety Disclosures	Inapplicable
Item 5.	Other Information	Inapplicable
Item 6.	Exhibits	218
	Signatures	222

4

DEFINITIONS

Term	Meaning
2012 MPSC CPCN Order	A detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC
2013 ARP	Alternative Rate Plan approved by the Georgia PSC in 2013 for Georgia Power for the years 2014 through 2016 and subsequently extended through 2019
AFUDC	Allowance for funds used during construction
Alabama Power	Alabama Power Company
ASU	Accounting Standards Update
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
Bridge Agreement	Senior unsecured Bridge Credit Agreement, dated as of September 30, 2015, among Southern Company, the lenders identified therein, and Citibank, N.A.
CCR	Coal combustion residuals
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
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	Combined Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power for the year ended December 31, 2015
GAAP	U.S. generally accepted accounting principles
Georgia Power	Georgia Power Company
Gulf Power	Gulf Power Company
IGCC	Integrated coal gasification combined cycle
IIC	Intercompany interchange contract
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
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
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

5

DEFINITIONS

(continued)

Term	Meaning
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal units
Moody's	Moody's Investors Service, Inc.
MW	Megawatt
NCCR	Georgia Power's Nuclear Construction Cost Recovery
Nicor Gas	Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas
NRC	U.S. Nuclear Regulatory Commission
OCI	Other comprehensive income
PATH Act	The Protecting Americans from Tax Hikes Act
PEP	Mississippi Power's Performance Evaluation Plan
Plant Vogtle Units 3 and 4	Two new nuclear generating units under construction at Georgia Power's Plant Vogtle
power pool	The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power Company (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA	Power purchase agreements and contracts for differences that provide the owner of the renewable facility a certain fixed price for the electricity sold to the grid
PSC	Public Service Commission
PTC	Production tax credit
Rate CNP	Alabama Power's Rate Certificated New Plant
Rate CNP Compliance	Alabama Power's Rate Certificated New Plant Compliance
Rate CNP PPA	Alabama Power's Rate Certificated New Plant Power Purchase Agreement
Rate RSE	Alabama Power's Rate Stabilization and Equalization plan
registrants	Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power Company
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
Southern Company	The Southern Company
Southern Company Gas	Southern Company Gas (formerly known as AGL Resources Inc.) and its subsidiaries
Southern Company Gas Capital	Southern Company Gas Capital Corporation, a wholly-owned subsidiary of Southern Company Gas
Southern Company system	Southern Company, the traditional electric operating companies, Southern Power, Southern Electric Generating Company, Southern Nuclear, SCS, Southern Communications Services, Inc., other subsidiaries, and, as of July 1, 2016, Southern Company Gas
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company and its subsidiaries
traditional electric operating companies	Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
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
Westinghouse	Westinghouse Electric Company LLC

6

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, 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 acquisitions and 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 legislative and regulatory initiatives regarding deregulation and restructuring of the utility industry, 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, as well as changes in application of existing laws and regulations;

• current and future litigation, regulatory investigations, proceedings, or inquiries, including, without limitation, IRS and state tax audits;

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

• advances in technology;

• 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;

• actions related to cost recovery for the Kemper IGCC, including the ultimate impact of the 2015 decision of the Mississippi Supreme Court, the Mississippi PSC's December 2015 rate order, 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;

7

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)

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

• 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 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, 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.

8

THE SOUTHERN COMPANY

AND SUBSIDIARY COMPANIES

9

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2016			2015			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Retail electric revenues	$	4,808		$	4,701		$	11,932		$	11,958
Wholesale electric revenues	613			520			1,455			1,435
Other electric revenues	181			169			529			494
Natural gas revenues	518			—			518			—
Other revenues	144			11			281			34
Total operating revenues	6,264			5,401			14,715			13,921
Operating Expenses:
Fuel	1,400			1,520			3,334			3,932
Purchased power	227			193			581			507
Cost of natural gas	133			—			133			—
Cost of other sales	84			—			161			—
Other operations and maintenance	1,411			1,097			3,616			3,320
Depreciation and amortization	695			528			1,805			1,515
Taxes other than income taxes	309			264			821			761
Estimated loss on Kemper IGCC	88			150			222			182
Total operating expenses	4,347			3,752			10,673			10,217
Operating Income	1,917			1,649			4,042			3,704
Other Income and (Expense):
Allowance for equity funds used during construction	52			60			150			163
Interest expense, net of amounts capitalized	(374		)	(218		)	(913		)	(612		)
Other income (expense), net	21			(21		)	(38		)	(41		)
Total other income and (expense)	(301		)	(179		)	(801		)	(490		)
Earnings Before Income Taxes	1,616			1,470			3,241			3,214
Income taxes	448			500			942			1,076
Consolidated Net Income	1,168			970			2,299			2,138
Less:
Dividends on Preferred and Preference Stock of Subsidiaries	11			11			34			42
Net income attributable to noncontrolling interests	27			—			39			—
Consolidated Net Income Attributable to Southern Company	$	1,130		$	959		$	2,226		$	2,096
Common Stock Data:
Earnings per share (EPS) —
Basic EPS	$	1.17		$	1.05		$	2.37		$	2.30
Diluted EPS	$	1.16		$	1.05		$	2.36		$	2.30
Average number of shares of common stock outstanding (in millions)
Basic	968			910			940			910
Diluted	975			912			945			913
Cash dividends paid per share of common stock	$	0.5600		$	0.5425		$	1.6625		$	1.6100

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

10

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2016		2015			2016			2015
	(in millions)					(in millions)
Consolidated Net Income	$	1,168	$	970		$	2,299		$	2,138
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $12, $(11), $(74), and $(10), respectively	19		(18		)	(118		)	(16		)
Reclassification adjustment for amounts included in net income, net of tax of $2, $1, $13, and $3, respectively	2		1			20			4
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $2, and $3, respectively	1		2			3			5
Total other comprehensive income (loss)	22		(15		)	(95		)	(7		)
Less:
Dividends on preferred and preference stock of subsidiaries	11		11			34			42
Comprehensive income attributable to noncontrolling interests	27		—			39			—
Consolidated Comprehensive Income Attributable to    Southern Company	$	1,152	$	944		$	2,131		$	2,089

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

11

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2016			2015
	(in millions)
Operating Activities:
Consolidated net income	$	2,299		$	2,138
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	2,109			1,787
Deferred income taxes	(22		)	821
Investment tax credits	—			319
Allowance for equity funds used during construction	(150		)	(163		)
Pension, postretirement, and other employee benefits	(158		)	79
Settlement of asset retirement obligations	(117		)	(20		)
Stock based compensation expense	87			77
Hedge settlements	(236		)	(4		)
Estimated loss on Kemper IGCC	222			182
Income taxes receivable, non-current	—			(444		)
Other, net	(98		)	(48		)
Changes in certain current assets and liabilities —
-Receivables	(458		)	(118		)
-Fossil fuel for generation	204			239
-Natural gas for sale	(222		)	—
-Other current assets	(111		)	(40		)
-Accounts payable	(9		)	(266		)
-Accrued taxes	1,062			408
-Accrued compensation	(122		)	(129		)
-Mirror CWIP	—			99
-Other current liabilities	(18		)	171
Net cash provided from operating activities	4,262			5,088
Investing Activities:
Business acquisitions, net of cash acquired	(9,513		)	(1,128		)
Property additions	(5,252		)	(3,490		)
Investment in restricted cash	(750		)	—
Distribution of restricted cash	746			—
Nuclear decommissioning trust fund purchases	(838		)	(1,164		)
Nuclear decommissioning trust fund sales	832			1,159
Cost of removal, net of salvage	(155		)	(118		)
Change in construction payables, net	(259		)	20
Investment in unconsolidated subsidiaries	(1,421		)	—
Prepaid long-term service agreement	(125		)	(166		)
Other investing activities	95			7
Net cash used for investing activities	(16,640		)	(4,880		)
Financing Activities:
Increase in notes payable, net	655			662
Proceeds —
Long-term debt	14,091			3,992
Common stock	3,265			136
Short-term borrowings	—			280
Redemptions and repurchases —
Long-term debt	(2,405		)	(2,562		)
Interest-bearing refundable deposits	—			(275		)
Preferred and preference stock	—			(412		)
Common stock	—			(115		)
Short-term borrowings	(475		)	(255		)
Distributions to noncontrolling interests	(22		)	(6		)
Capital contributions from noncontrolling interests	367			274
Purchase of membership interests from noncontrolling interests	(129		)	—
Payment of common stock dividends	(1,553		)	(1,465		)
Other financing activities	(151		)	(63		)
Net cash provided from financing activities	13,643			191
Net Change in Cash and Cash Equivalents	1,265			399
Cash and Cash Equivalents at Beginning of Period	1,404			710
Cash and Cash Equivalents at End of Period	$	2,669		$	1,109
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $94 and $88 capitalized for 2016 and 2015, respectively)	$	766		$	590
Income taxes, net	(151		)	(13		)
Noncash transactions — Accrued property additions at end of period	578			483

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

12

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2016			At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	2,669		$	1,404
Receivables —
Customer accounts receivable	1,718			1,058
Energy marketing receivable	526			—
Unbilled revenues	639			397
Under recovered regulatory clause revenues	54			63
Income taxes receivable, current	—			144
Other accounts and notes receivable	317			398
Accumulated provision for uncollectible accounts	(43		)	(13		)
Materials and supplies	1,268			1,061
Fossil fuel for generation	664			868
Natural gas for sale	627			—
Vacation pay	178			178
Prepaid expenses	459			495
Other regulatory assets, current	414			402
Other current assets	168			71
Total current assets	9,658			6,526
Property, Plant, and Equipment:
In service	94,174			75,118
Less accumulated depreciation	29,590			24,253
Plant in service, net of depreciation	64,584			50,865
Other utility plant, net	—			233
Nuclear fuel, at amortized cost	901			934
Construction work in progress	10,069			9,082
Total property, plant, and equipment	75,554			61,114
Other Property and Investments:
Goodwill	6,223			2
Equity investments in unconsolidated subsidiaries	1,541			6
Other intangible assets, net of amortization of $39 and $12 at September 30, 2016 and December 31, 2015, respectively	942			317
Nuclear decommissioning trusts, at fair value	1,616			1,512
Leveraged leases	769			755
Miscellaneous property and investments	249			160
Total other property and investments	11,340			2,752
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,590			1,560
Unamortized loss on reacquired debt	228			227
Other regulatory assets, deferred	6,446			4,989
Income taxes receivable, non-current	413			413
Other deferred charges and assets	1,133			737
Total deferred charges and other assets	9,810			7,926
Total Assets	$	106,362		$	78,318

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

13

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At September 30, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	2,254		$	2,674
Notes payable	1,670			1,376
Energy marketing trade payables	533			—
Accounts payable	1,732			1,905
Customer deposits	577			404
Accrued taxes —
Accrued income taxes	375			19
Other accrued taxes	641			484
Accrued interest	410			249
Accrued vacation pay	231			228
Accrued compensation	505			549
Asset retirement obligations, current	390			217
Liabilities from risk management activities, net of collateral	125			156
Other regulatory liabilities, current	99			278
Mandatorily redeemable noncontrolling interest	174			—
Other current liabilities	851			590
Total current liabilities	10,567			9,129
Long-term Debt	41,550			24,688
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	14,218			12,322
Deferred credits related to income taxes	204			187
Accumulated deferred investment tax credits	1,721			1,219
Employee benefit obligations	3,022			2,582
Asset retirement obligations, deferred	4,124			3,542
Unrecognized tax benefits	381			370
Accrued environmental remediation	415			42
Other cost of removal obligations	2,771			1,162
Other regulatory liabilities, deferred	401			254
Other deferred credits and liabilities	641			678
Total deferred credits and other liabilities	27,898			22,358
Total Liabilities	80,015			56,175
Redeemable Preferred Stock of Subsidiaries	118			118
Redeemable Noncontrolling Interests	49			43
Stockholders' Equity:
Common Stockholders' Equity:
Common stock, par value $5 per share —
Authorized — 1.5 billion shares
Issued — September 30, 2016: 981 million shares
— December 31, 2015: 915 million shares
Treasury — September 30, 2016: 0.8 million shares
— December 31, 2015: 3.4 million shares
Par value	4,900			4,572
Paid-in capital	9,217			6,282
Treasury, at cost	(30		)	(142		)
Retained earnings	10,685			10,010
Accumulated other comprehensive loss	(225		)	(130		)
Total Common Stockholders' Equity	24,547			20,592
Preferred and Preference Stock of Subsidiaries	609			609
Noncontrolling Interests	1,024			781
Total Stockholders' Equity	26,180			21,982
Total Liabilities and Stockholders' Equity	$	106,362		$	78,318

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

14

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2016 vs. THIRD QUARTER 2015

AND

YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 2015

OVERVIEW

Southern Company is a holding company that owns all of the common stock of the traditional electric operating companies and the parent entities of Southern Power and Southern Company Gas and owns other direct and indirect subsidiaries. Discussion of the results of operations is focused on the Southern Company system's primary business of electricity sales by the traditional electric operating companies and Southern Power and, following the closing of the Merger on July 1, 2016, the distribution of natural gas by Southern Company Gas, formerly known as AGL Resources Inc. 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 is an energy services holding company whose primary business is the distribution of natural gas through seven natural gas distribution utilities 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 products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, as well as investments in telecommunications and leveraged lease projects. For additional information, see BUSINESS – "The Southern Company System – Traditional Operating Companies," " – Southern Power," and " – Other Businesses" in Item 1 of the Form 10-K.

Merger with Southern Company Gas

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.

Prior to the completion of the Merger, Southern Company and Southern Company Gas operated as separate companies. The discussion and analysis of results of operations and financial condition set forth herein include Southern Company Gas' results of operations since July 1, 2016 and financial condition as of September 30, 2016. See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information regarding the Merger.

During the three and nine months ended September 30, 2016, Southern Company recorded in its statements of income costs associated with the Merger of approximately $40.8 million and $104.1 million, respectively, of which $40.6 million and $73.5 million is included in operating expenses and $0.2 million and $30.6 million is included in other income and (expense), respectively. These costs include external transaction costs for financing, legal, and consulting services, as well as rate credits and additional compensation-related expenses.

See RISK FACTORS in Item 1A herein for additional information related to the various risks related to the Merger.

Construction Program

Construction continues on 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 RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC," FUTURE EARNINGS POTENTIAL – "Construction Program," and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information. 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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Key Performance Indicators

Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, execution of major construction projects, and earnings per share. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Southern Company in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$171	17.8	$130	6.2

Consolidated net income attributable to Southern Company was $1.1 billion ($1.17 per share) for the third quarter 2016 compared to $959 million ($1.05 per share) for the third quarter 2015. The increase was primarily the result of an increase in retail electric revenues resulting from warmer weather and base rate increases, a decrease in income taxes primarily from income tax benefits at Southern Power, and lower charges related to revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC, partially offset by increases in interest expense, depreciation and amortization, and non-fuel operations and maintenance expenses. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Consolidated net income attributable to Southern Company was $2.2 billion ($2.37 per share) for year-to-date 2016 compared to $2.1 billion ($2.30 per share) for the corresponding period in 2015. The increase was primarily the result of an increase in retail electric revenues resulting from base rate increases as well as the 2015 correction of a Georgia Power billing error and a decrease in income taxes primarily from income tax benefits at Southern Power, partially offset by increases in interest expense and depreciation and amortization.

Although several individual income statement line items reflect variances resulting from the Merger on July 1, 2016 and the acquisition of PowerSecure International, Inc. (PowerSecure) on May 9, 2016, consolidated net income for the third quarter and year-to-date 2016 was not significantly impacted by these transactions.

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

Retail Electric Revenues

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$107	2.3	$(26)	(0.2)

In the third quarter 2016, retail electric revenues were $4.8 billioncompared to $4.7 billion for the corresponding period in 2015. For year-to-date 2016, retail electric revenues decreased slightly compared to the corresponding period in 2015.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	Third Quarter 2016					Year-to-Date 2016
	(in millions)			(% change)		(in millions)			(% change)
Retail electric – prior year	$	4,701				$	11,958
Estimated change resulting from –
Rates and pricing	84			1.8		379			3.2
Sales growth (decline)	(18		)	(0.4	)	(14		)	(0.1	)
Weather	169			3.6		82			0.7
Fuel and other cost recovery	(128		)	(2.7	)	(473		)	(4.0	)
Retail electric – current year	$	4,808		2.3	%	$	11,932		(0.2	)%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2016 when compared to the corresponding periods in 2015 primarily due to increases in base tariffs at Georgia Power under the 2013 ARP and the NCCR tariff and increased revenues at Alabama Power under Rate CNP Compliance, all effective January 1, 2016. Also contributing to the increase in rates and pricing for year-to-date 2016 was the 2015 correction of a Georgia Power billing error to a small number of large commercial and industrial customers and the implementation of rates at Mississippi Power for certain Kemper IGCC in-service assets, effective September 2015.

See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power," "Retail Regulatory Matters – Georgia Power – Rate Plans" and " – Nuclear Construction," and "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.

Revenues attributable to changes in sales decreased in the third quarter 2016 when compared to the corresponding period in 2015. Industrial KWH sales decreased 3.3% in the third quarter 2016 primarily in the primary metals, paper, chemicals, pipelines, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector. Weather-adjusted commercial KWH sales decreased 0.7% in the third quarter 2016 primarily due to decreased customer usage resulting from an increase in energy saving initiatives, partially offset by customer growth. Weather-adjusted residential KWH sales decreased 0.4% in the third quarter 2016 primarily due to decreased customer usage primarily resulting from an increase in multi-family housing and efficiency improvements in residential appliances and lighting, partially offset by customer growth.

Revenues attributable to changes in sales decreased for year-to-date 2016 when compared to the corresponding period in 2015. Industrial KWH sales decreased 2.1% for year-to-date 2016 primarily in the primary metals, chemicals, pipelines, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector. Weather-adjusted commercial KWH sales decreased 0.6% for year-to-date 2016 primarily due to decreased customer usage resulting from an increase in energy saving initiatives, partially offset by customer growth. Weather-adjusted residential KWH sales increased 0.2% for year-to-date 2016 due to customer growth, partially offset by decreased customer usage primarily resulting from an increase in multi-family housing and efficiency improvements in residential appliances and lighting.

In the first quarter 2015, Mississippi Power updated the methodology to estimate the unbilled revenue allocation among customer classes. This change did not have a significant impact on net income. The KWH sales variances discussed above reflect an adjustment to the estimated allocation of Mississippi Power's unbilled first quarter 2015 KWH sales among customer classes that is consistent with the actual allocation in 2016. Without this adjustment, year-to-date 2016 weather-adjusted residential sales increased 0.3%, weather-adjusted commercial sales decreased 0.5%, and industrial KWH sales decreased 2.0% as compared to the corresponding period in 2015.

Fuel and other cost recovery revenues decreased $128 million and $473 million in the third quarter and year-to-date 2016, respectively, when compared to the corresponding periods in 2015 primarily due to a decrease in fuel prices. Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in

17

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.

Wholesale Electric Revenues

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$93	17.9	$20	1.4

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 reflect the recovery of fixed costs and 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. Solar and wind PPAs do not have a capacity charge and customers purchase the energy output of a dedicated renewable facility through an energy charge. 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 third quarter 2016, wholesale electric revenues were $613 million compared to $520 million for the corresponding period in 2015. This increase was primarily related to a $121 million increase in energy revenues, partially offset by a $28 million decrease in capacity revenues. For year-to-date 2016, wholesale electric revenues were $1.46 billion compared to $1.44 billion for the corresponding period in 2015. This increase was primarily related to a $112 million increase in energy revenues, partially offset by a $92 million decrease in capacity revenues. The increases in energy revenues were primarily due to an increase in short-term sales and renewable energy sales at Southern Power, partially offset by lower fuel prices. The decreases in capacity revenues were primarily due to the elimination in consolidation of a Southern Power PPA that was remarketed from a third party to Georgia Power in January 2016, the expiration of Plant Scherer Unit 3 power sales agreements at Gulf Power, and the expiration of wholesale contracts at Georgia Power, partially offset by an increase due to a new wholesale contract at Alabama Power. Additionally, the year-to-date 2016 decrease in capacity revenues was due to unit retirements at Georgia Power.

See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Gulf Power" herein for additional information regarding the expiration of long-term sales agreements at Gulf Power for Plant Scherer Unit 3, which will impact future wholesale earnings, and Gulf Power's request to rededicate its ownership interest in Scherer Unit 3 to the retail jurisdiction.

Other Electric Revenues

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$12	7.1	$35	7.1

For year-to-date 2016, other electric revenues were $529 million compared to $494 million for the corresponding period in 2015. The increase was primarily due to increases in customer temporary facilities services revenues, outdoor lighting revenues, and solar application fee revenues at Georgia Power.

18

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Natural Gas Revenues

Natural gas revenues represent sales from the seven natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. Following the Merger, $518 million of natural gas revenues are included in the consolidated statements of income for the third quarter and year-to-date 2016.

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

Other Revenues

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$133	N/M	$247	N/M

N/M - Not meaningful

In the third quarter 2016, other revenues were $144 million compared to $11 million for the corresponding period in 2015. For year-to-date 2016, other revenues were $281 million compared to $34 million for the corresponding period in 2015. These increases were primarily due to $91 million and $150 million for the third quarter and year-to-date 2016, respectively, of revenues from products and services at PowerSecure, which was acquired on May 9, 2016, and $25 million of revenues from gas marketing products and services at Southern Company Gas following the Merger. Additionally, for the third quarter and year-to-date 2016, revenues from certain non-regulated sales of products and services by the traditional electric operating companies of $17 million and $63 million, respectively, were reclassified as other revenues for consistency of presentation on a consolidated basis. In prior periods, these revenues were included in other income (expense), net.

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

Fuel and Purchased Power Expenses

	Third Quarter 2016 vs. Third Quarter 2015				Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(120	)	(7.9)	$	(598	)	(15.2)
Purchased power	34			17.6	74			14.6
Total fuel and purchased power expenses	$	(86	)		$	(524	)

In the third quarter 2016, total fuel and purchased power expenses were $1.6 billion compared to $1.7 billion for the corresponding period in 2015. The decrease was primarily the result of a $209 million decrease in the average cost of fuel and purchased power primarily due to lower coal prices, partially offset by a $123 million increase in the volume of KWHs generated and purchased.

For year-to-date 2016, total fuel and purchased power expenses were $3.9 billion compared to $4.4 billion for the corresponding period in 2015. The decrease was primarily the result of a $573 million decrease in the average cost of fuel and purchased power primarily due to lower coal and natural gas prices, partially offset by a $49 million net increase 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.

19

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	Third Quarter 2016	Third Quarter 2015	Year-to-Date 2016	Year-to-Date 2015
Total generation (in billions of KWHs)	56	53	145	146
Total purchased power (in billions of KWHs)	5	4	13	10
Sources of generation (percent) —
Coal	38	40	33	37
Nuclear	15	15	16	16
Gas	44	43	46	44
Hydro	1	1	3	2
Other Renewables	2	1	2	1
Cost of fuel, generated (in cents per net KWH)—
Coal	2.97	3.86	3.10	3.65
Nuclear	0.81	0.84	0.82	0.78
Gas	2.74	2.71	2.40	2.72
Average cost of fuel, generated (in cents per net KWH)	2.54	2.90	2.38	2.78
Average cost of purchased power (in cents per net KWH)(*)	5.57	5.95	5.31	6.13

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

Fuel

In the third quarter 2016, fuel expense was $1.4 billion compared to $1.5 billion for the corresponding period in 2015. The decrease was primarily due to a 23.1% decrease in the average cost of coal per KWH generated, partially offset by an 8.7% increase in the volume of KWHs generated by natural gas.

For year-to-date 2016, fuel expense was $3.3 billion compared to $3.9 billion for the corresponding period in 2015. The decrease was primarily due to a 15.1% decrease in the average cost of coal per KWH generated, an 11.9% decrease in the volume of KWHs generated by coal, and an 11.8% decrease in the average cost of natural gas per KWH generated, partially offset by a 6.1% increase in the volume of KWHs generated by natural gas.

Purchased Power

In the third quarter 2016, purchased power expense was $227 million compared to $193 million for the corresponding period in 2015. The increase was primarily due to a 24.1% increase in the volume of KWHs purchased, partially offset by a 6.4% decrease in the average cost per KWH purchased, primarily as a result of lower fuel prices.

For year-to-date 2016, purchased power expense was $581 million compared to $507 million for the corresponding period in 2015. The increase was primarily due to a 29.4% increase in the volume of KWHs purchased, partially offset by a 13.4% decrease in the average cost per KWH purchased, primarily as a result of lower fuel prices.

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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cost of Natural Gas

Cost of natural gas represents the cost of natural gas sold by the seven natural gas distribution utilities and certain non-regulated operations of Southern Company Gas. Following the Merger, $133 million of natural gas costs is included in the consolidated statements of income for the third quarter and year-to-date 2016.

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

Cost of Other Sales

In the third quarter and year-to-date 2016, cost of other sales were $84 million and $161 million, respectively. These costs were primarily related to sales of products and services by PowerSecure, which was acquired on May 9, 2016, of $69 million and $111 million for the third quarter and year-to-date 2016, respectively. Additionally, for the third quarter and year-to-date 2016, costs of $11 million and $43 million, respectively, related to certain non-regulated sales of products and services by the traditional electric operating companies were reclassified as cost of other sales for consistency of presentation on a consolidated basis. In prior periods, these costs were included in other income (expense), net.

See "Other Revenues" herein and Note (I) to the Condensed Financial Statements under "Southern Company – Acquisition of PowerSecure International, Inc." herein for additional information.

Other Operations and Maintenance Expenses

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$314	28.6	$296	8.9

In the third quarter 2016, other operations and maintenance expenses were $1.4 billion compared to $1.1 billion for the corresponding period in 2015. The increase was primarily related to $251 million in operations and maintenance expenses at Southern Company Gas following the Merger, a $26 million charge in connection with an employee attrition plan at Georgia Power, a $19 million increase in transmission and distribution expenses primarily related to overhead line maintenance at Georgia Power, $18 million in operations and maintenance expenses at PowerSecure, and a $9 million increase at Southern Power associated with new solar and wind facilities placed in service in 2015 and 2016, partially offset by an $11 million net decrease in employee compensation and benefits, including pension costs.

For year-to-date 2016, other operations and maintenance expenses were $3.6 billion compared to $3.3 billion for the corresponding period in 2015. The increase was primarily due to $251 million in operations and maintenance expenses at Southern Company Gas following the Merger, $28 million in operations and maintenance expenses at PowerSecure since the acquisition closed on May 9, 2016, a $28 million increase in transaction fees related to the Merger and the acquisition of PowerSecure, a $27 million increase in transmission and distribution expenses primarily related to overhead line maintenance and integrated transmission system billings at Georgia Power, a $26 million charge in connection with an employee attrition plan at Georgia Power, and a $22 million increase at Southern Power associated with new solar and wind facilities placed in service in 2015 and 2016. The increase was partially offset by a $53 million decrease in scheduled outage and maintenance costs at generation facilities and a $48 million net decrease in employee compensation and benefits, including pension costs.

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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Depreciation and Amortization

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$167	31.6	$290	19.1

In the third quarter 2016, depreciation and amortization was $695 million compared to $528 million for the corresponding period in 2015. For year-to-date 2016, depreciation and amortization was $1.8 billion compared to $1.5 billion for the corresponding period in 2015. Following the Merger, $116 million in depreciation and amortization for Southern Company Gas is included in the consolidated financial statements for the third quarter and year-to-date 2016. Additionally, the increases were due to additional plant in service at the traditional electric operating companies and Southern Power.

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

Taxes Other Than Income Taxes

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$45	17.0	$60	7.9

In the third quarter 2016, taxes other than income taxes were $309 million compared to $264 million for the corresponding period in 2015. For year-to-date 2016, taxes other than income taxes were $821 million compared to $761 million for the corresponding period in 2015. Following the Merger, $29 million in taxes other than income taxes associated with Southern Company Gas is included in the consolidated financial statements for the third quarter and year-to-date 2016. Additionally, property taxes at the traditional electric operating companies increased for the third quarter and year-to-date 2016 primarily due to an increase in the assessed value of property.

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

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(62)	(41.3)	$40	22.0

In the third quarter 2016 and 2015, estimated probable losses on the Kemper IGCC of $88 million and $150 million, respectively, were recorded at Southern Company. For year-to-date 2016 and 2015, estimated probable losses on the Kemper IGCC of $222 million and $182 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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Interest Expense, Net of Amounts Capitalized

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$156	71.6	$301	49.2

In the third quarter 2016, interest expense, net of amounts capitalized was $374 million compared to $218 million in the corresponding period in 2015. For year-to-date 2016, interest expense, net of amounts capitalized was $913 million compared to $612 million in the corresponding period in 2015. These increases were primarily due to an increase in average outstanding long-term debt primarily related to the financing of the Merger. In addition, following the Merger, $39 million in interest expense of Southern Company Gas is included in the consolidated financial statements for the third quarter and year-to-date 2016. Also contributing to the year-to-date 2016 increase was the May 2015 termination of an asset purchase agreement between Mississippi Power and SMEPA and the resulting reversal of accrued interest on related deposits.

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

Other Income (Expense), Net

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$42	N/M	$3	7.3

N/M - Not meaningful

In the third quarter 2016, other income (expense), net was $21 million compared to $(21) million for the corresponding period in 2015. For year-to-date 2016, other income (expense), net was $(38) million compared to $(41) million for the corresponding period in 2015. Following the Merger, $38 million in other income of Southern Company Gas is included in the consolidated financial statements for the third quarter and year-to-date 2016, primarily related to $27 million of earnings from the equity method investment in Southern Natural Gas Company, L.L.C. (SNG) in September 2016. Additionally, in the third quarter 2016, revenues and costs associated with certain non-regulated sales of products and services by the traditional electric operating companies were reclassified to other revenues and cost of other sales for consistency of presentation on a consolidated basis following the PowerSecure acquisition. For the third quarter and year-to-date 2016, net amounts reclassified were $6 million and $20 million, respectively. The year-to-date 2016 increase was partially offset by fees associated with the Bridge Agreement for the Merger.

See "Other Revenues" and "Cost of Other Sales" herein and Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information. Also see Note 12 to the financial statements of Southern Company under "Southern Company – Merger Financing" in Item 8 of the Form 10-K for additional information.

Income Taxes

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(52)	(10.4)	$(134)	(12.5)

In the third quarter 2016, income taxes were $448 million compared to $500 million for the corresponding period in 2015. The decrease was primarily due to increased federal income tax benefits from ITCs and PTCs at Southern Power, partially offset by a reduction in tax benefits related to the estimated probable losses on Mississippi Power's construction of the Kemper IGCC and an increase in pre-tax earnings.

For year-to-date 2016, income taxes were $942 million compared to $1.1 billion for the corresponding period in 2015. The decrease was primarily due to increased federal income tax benefits from ITCs and PTCs at Southern

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Power, partially offset by an increase in pre-tax earnings and an increase related to state income tax benefits realized in 2015.

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 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 business of selling electricity and, as a result of closing the Merger, the distribution of natural gas. These factors include the traditional electric operating companies' and Southern Company Gas' ability to maintain a constructive regulatory environment that allows for the timely recovery of prudently-incurred costs during a time of increasing costs and the completion and subsequent operation of the Kemper IGCC and Plant Vogtle Units 3 and 4 as well as other ongoing construction projects. Other major factors include the profitability of Southern Power's competitive wholesale business and successful additional investments in renewable and other energy projects. Future earnings for the electricity and natural gas businesses 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 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 generating capacity available and related costs, future acquisitions and construction of 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 gasdemand may be affected by changes in regional and global economic conditions, which may impact future earnings.

Volatility of natural gas prices has a significant impact on Southern Company Gas' customer rates, long-term competitive position against other energy sources, and the ability of 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, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company.

On July 10, 2016, Southern Company and Kinder Morgan, Inc. (Kinder Morgan) entered into a definitive agreement for Southern Company to acquire a 50% equity interest in SNG, which is the owner of a 7,000-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. In addition, the agreement committed Southern Company and Kinder Morgan to cooperatively pursue specific growth opportunities to develop natural gas infrastructure through SNG. On August 31, 2016, Southern Company assigned its rights and obligations under the definitive agreement to a wholly-owned, indirect subsidiary of Southern Company Gas. On September 1, 2016, Southern Company Gas completed the acquisition for a purchase price of approximately $1.4 billion. The investment in SNG is accounted for using the equity method.

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.

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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 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 Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's final MATS rule, regional haze regulations, fine particulate matter National Ambient Air Quality Standards (NAAQS), and the Cross State Air Pollution Rule (CSAPR).

On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion, the EPA published its supplemental finding regarding consideration of costs in support of the MATS rule. This finding does not impact MATS rule compliance requirements, costs, or deadlines, and all units within the Southern Company system that are subject to the MATS rule completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.

Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and cannot be determined at this time.

On September 6, 2016, the EPA designated all remaining areas within Georgia Power's and Gulf Power's service territories as attainment for the 2012 annual fine particulate matter NAAQS. Following the EPA's decision, all areas within the traditional electric operating companies' service territory have now been designated as attainment for the 2012 fine particulate matter NAAQS.

On October 26, 2016, the EPA published a final rule that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Alabama, Mississippi, and Texas and removing Florida and North Carolina from the program. The ultimate impact of this rule will depend on the outcome of any legal challenges and implementation at the state level and cannot be determined at this time.

Coal Combustion Residuals

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Residuals" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.

On June 13, 2016, Georgia Power announced that all of its 29 ash ponds will cease operations and stop receiving coal ash in the next three years, and all ponds will eventually be closed either by removal, consolidation, and/or recycling for the beneficial use of coal ash or through closure in place using advanced engineering methods. On October 26, 2016, the Georgia Department of Natural Resources approved amendments to its state solid waste regulations to incorporate the requirements of the EPA's Disposal of Coal Combustion Residuals from Electric Utilities Rule (CCR Rule) and establish additional requirements for all of Georgia Power's onsite storage units consisting of landfills and surface impoundments. The final State of Georgia regulations are not anticipated to have a material impact on the Southern Company system's compliance obligations under the CCR Rule. See Note (A) to

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the Condensed Financial Statements herein for information regarding Southern Company's asset retirement obligations (ARO) as of September 30, 2016.

Environmental Remediation

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

As a result of closing the Merger, Southern Company's Consolidated Balance Sheet at September 30, 2016 includes the environmental remediation liabilities of Southern Company Gas. See Note (B) to the Condensed Financial Statements under "Environmental Remediation" herein for additional information. See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information regarding the Merger.

Regulatory Matters

Fuel Cost Recovery

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

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.

On May 17, 2016, the Georgia PSC approved Georgia Power's request to decrease fuel rates by 15% effective June 1, 2016, which will reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017.

Renewables

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail 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.

In accordance with the Alabama PSC order approving up to 500 MWs of renewable projects, Alabama Power has entered into agreements to purchase power from or to build renewable generation sources, including a 72-MW solar PPA approved by the Alabama PSC in June 2016. Alabama Power is marketing the associated renewable energy credits (REC) generated by this solar PPA to customers interested in supporting renewable energy development. The terms of the renewable agreements permit Alabama Power to use the energy and retire the associated RECs in service of its customers or to sell RECs, separately or bundled with energy.

As part of the Georgia Power Advanced Solar Initiative (ASI), four PPAs totaling 149 MWs of Georgia Power's solar contracted capacity from Southern Power began in the first quarter 2016. During the second quarter 2016, Georgia Power executed PPAs to purchase an additional 41 MWs of solar capacity under the ASI. Ownership of any associated RECs is specified in each respective PPA. The party that owns the RECs retains the right to use them.

On October 4, 2016, two 30-MW solar generating facilities at Fort Gordon and Fort Stewart Army bases began commercial operation. These solar generating facilities were approved by the Georgia PSC in 2014.

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The Florida PSC issued a final approval order on Gulf Power's Community Solar Pilot Program on April 15, 2016. The program will offer all Gulf Power customers an opportunity to voluntarily contribute to the construction and operation of a solar photovoltaic facility with electric generating capacity of up to 1 MW through annual subscriptions. The energy generated from the solar facility is expected to provide power to all of Gulf Power's customers.

On October 11, 2016, the Florida PSC preliminarily approved Gulf Power's energy purchase agreement for up to 94 MWs of wind generation in central Oklahoma. Purchases under this agreement will be for energy only and will be recovered through Gulf Power's fuel cost recovery clause.

In November 2015, the Mississippi PSC issued orders approving three solar facilities for a combined total of approximately 105 MWs. Mississippi Power will purchase all of the energy produced by the solar facilities for the 25-year term under each of the three PPAs. The projects are expected to be in service by the second quarter 2017 and the resulting energy purchases are expected to be recovered through Mississippi Power's fuel cost recovery mechanism. Mississippi Power may retire the RECs 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 its Rate RSE, Rate CNP Compliance, rate energy cost recovery, and rate natural disaster reserve. 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 "Retail 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.

Environmental Accounting Order

In April 2016, as part of its environmental compliance strategy, Alabama Power ceased using coal at Plant Greene County Units 1 and 2 (300 MWs representing Alabama Power's ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively.

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 separate fuel cost recovery tariffs. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Retail 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 "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information regarding Georgia Power's fuel cost recovery.

Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC on April 14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company (collectively, Utilities) each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each utility will be shared on a 60/40 basis between their respective customers and the Utilities; thereafter, all merger savings will be retained by customers.

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See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power" in Item 8 of the Form 10-K for additional information regarding the 2013 ARP and Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information regarding the Merger.

Integrated Resource Plan

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail 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 (2016 IRP).

On July 28, 2016, the Georgia PSC voted to approve the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 combustion turbine (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. On August 31, 2016, Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc.

Additionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.

The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date will be deferred for consideration in Georgia Power's base rate case required to be filed by July 1, 2019.

The Georgia PSC also approved the Renewable Energy Development Initiative to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.

The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve the nuclear option at a future generation site in Stewart County, Georgia. The timing of cost recovery will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.

Storm Damage Recovery

As of September 30, 2016, the balance in Georgia Power's regulatory asset related to storm damage was $94 million. During October 2016, Hurricane Matthew caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of restoration costs related to this hurricane is estimated to be between $130 million and $155 million, which will be charged to capital accounts or to the storm damage reserve. Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, to the storm damage reserve to cover the operating and maintenance costs of damages from major storms to its transmission and distribution facilities, which is recoverable through base rates. The rate of recovery of storm damage costs after December 31, 2019 is expected to be adjusted in Georgia Power's base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's financial statements. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.

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Gulf Power

Through 2015, long-term non-affiliate capacity sales from Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs) provided the majority of Gulf Power's wholesale earnings. The revenues from wholesale contracts covering 100% of this capacity represented 82% of Gulf Power's wholesale capacity revenues in 2015. Following contract expirations at the end of 2015 and the end of May 2016, Gulf Power's remaining contracted sales from the unit cover approximately 24% of Gulf Power's ownership of the unit through 2019. The expiration of these contracts is not expected to have a material impact on Southern Company's earnings. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as its existing wholesale contracts expire. As a result, on September 13, 2016, the Florida PSC instructed Gulf Power to file its monthly earnings surveillance reports both including and excluding its share of investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts.

On October 12, 2016, Gulf Power filed a petition (2016 Rate Case) with the Florida PSC requesting an increase in retail rates and charges of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 and a retail ROE of 11% compared to the current retail ROE of 10.25%. The recoverability of the costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 will be decided in this matter. The Florida PSC is expected to make a decision on the 2016 Rate Case in the second quarter 2017. Gulf Power has requested that the increase in base rates, if approved by the Florida PSC, become effective in July 2017.

On November 2, 2016, the Florida PSC approved Gulf Power's annual rate clause request for its cost recovery clause factors for 2017. The fuel and environmental factors include certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters– Gulf Power– Cost Recovery Clauses" herein for additional information.

The ultimate outcome of these matters 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 revenues or net income, but will affect cash flow.

Regulatory Infrastructure Programs

Southern Company Gas' natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs update or expand the natural gas distribution systems of the utilities to improve safety and reliability and meet operational flexibility and growth. Southern Company Gas currently has approved infrastructure improvement programs in six different states with initial program lengths ranging from four to 10 years, with the longest set to expire in 2025. The average annual spend under these programs ranges from $10 million to $250 million.

Southern Company Gas currently has proposed infrastructure improvement programs pending approval by the applicable state regulatory agencies in Georgia and New Jersey requesting average annual spending of $44 million through 2020 and $110 million through 2027, respectively. The ultimate outcome of these matters 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

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its strategy of developing and constructing new electric generating facilities, as well as adding or changing fuel sources for certain existing units, adding environmental control equipment, 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 programs that update or expand its natural 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.

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 "Retail 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 "Retail 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 – Construction Projects" herein. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters– Southern Company Gas– Regulatory Infrastructure Programs" herein for additional information regarding infrastructure improvement programs at Southern Company Gas' 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's current cost estimate for the Kemper IGCC in total is approximately $6.82 billion, which includes approximately $5.52 billion of costs subject to the construction cost cap and is net of $137 million in additional DOE grants Mississippi Power received for the Kemper IGCC on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts for 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. In the aggregate, Southern Company has incurred charges of $2.63 billion ($1.63 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2016. Mississippi Power's current cost estimate includes costs through December 31, 2016.

The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." On October 11, 2016, the Kemper IGCC began testing using clean syngas from gasifier "A" and the related gas clean-up systems to produce electricity. On November 2, 2016, Mississippi Power determined a maintenance outage of gasifier "A" is needed to make improvements to the ash removal systems. The remaining schedule reflects the time expected to achieve production of electricity using gasifier "B," complete gasifier "A" outage activities, and resume electricity production using gasifier "A," as well as to complete the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.

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.

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

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Litigation

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

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

On October 20, 2016, Georgia Power and the Georgia PSC Staff entered into a settlement agreement (Vogtle Cost Settlement Agreement) resolving the following prudence and cost recovery matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth Vogtle Construction Monitoring report will be disallowed from rate base on the basis of imprudence; (ii) the definitive settlement agreement entered into on December 31, 2015 by Westinghouse and the Vogtle Owners (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 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 commercial operation. The ROE used to calculate the NCCR tariff will be 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

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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 commercially operational by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units reach commercial operation 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 upon reaching commercial operation, 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 Vogtle Cost Settlement Agreement is subject to approval by the Georgia PSC, which is scheduled to vote on this matter on December 20, 2016. Accordingly, the terms of the Vogtle Cost Settlement Agreement are subject to change and the terms of any final agreement approved by the Georgia PSC may differ materially from the terms of the Vogtle Cost Settlement Agreement. If approved, the Vogtle Cost Settlement Agreement is expected to reduce Georgia Power's revenues for the years 2016 through 2020 by a total of approximately $325 million ($115 million reduction in net income).

See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters– Georgia Power– Nuclear Construction" for additional information.

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

Income Tax Matters

Bonus Depreciation

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

The extension of 50% bonus depreciation included in the PATH Act is expected to result in approximately $1.7 billion of positive cash flows for the 2016 tax year, which may not all be realized in 2016 due to a projected consolidated net operating loss for Southern Company. Approximately $370 million of the benefit is dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2016. See Note (B) tothe Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and Note (G) tothe Condensed Financial Statements under "Current and Deferred Income Taxes – Net Operating Loss" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

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

TheultimateoutcomeofsuchpendingorpotentiallitigationagainstSouthernCompanyanditssubsidiariescannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementshereinorinNote3tothefinancialstatementsofSouthernCompanyinItem8ofthe Form 10-K,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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

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

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

During 2016, 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 the revisions to the cost estimate, Southern Company recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $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, and $540 million ($333 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $2.63 billion ($1.63 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2016.

Mississippi Power's revised cost estimate reflects an expected in-service date of December 31, 2016 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, 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, during the start-up and commissioning process, Mississippi Power is also identifying

33

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. The related potential costs have yet to be fully evaluated, have not been included in the current cost estimates, 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 December 31, 2016 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 with respect to the Kemper IGCC beyond December 31, 2016 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 $15 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.

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.

Goodwill and Other Intangible Assets

Southern Company accounts for acquisitions using the acquisition method of accounting, which requires the assets acquired and liabilities assumed to be recorded at the date of acquisition at their respective estimated fair values. Southern Company recognizes goodwill as of the acquisition date, as a residual over the fair values of the identifiable net assets acquired. Goodwill will be tested for impairment on an annual basis in the fourth quarter of the year as well as on an interim basis as events and changes in circumstances occur. Primarily as a result of the acquisitions of Southern Company Gas and PowerSecure in 2016, goodwill totaled approximately $6.2 billion at September 30, 2016.

Definite-lived intangible assets acquired are amortized over the estimated useful lives of the respective assets to reflect the pattern in which the economic benefits of the intangible assets are consumed. Whenever events or changes in circumstances indicate that the carrying amount of the intangible assets may not be recoverable, the intangible assets will be reviewed for impairment. Primarily as a result of the acquisitions of Southern Company Gas and PowerSecure in 2016, other intangible assets, net of amortization totaled approximately $0.9 billion at September 30, 2016.

The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can significantly impact Southern Company's results of operations. Fair values and useful lives are determined based on, among other factors, the expected future period of benefit of the asset, the various characteristics of the asset, and projected cash flows. As the determination of an asset's fair value and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, Southern Company considers these estimates to be critical accounting estimates.

See Note (A) to the Condensed Financial Statements under "Goodwill and Other Intangible Assets" herein for additional information regarding Southern Company's goodwill and other intangible assets as of September 30, 2016 and Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information related to Southern Company's recent acquisitions.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Derivatives and Hedging Activities

Derivative instruments are recorded on the balance sheets as either assets or liabilities measured at their fair value, unless the transactions qualify for the normal purchases or normal sales scope exception and are instead subject to traditional accrual accounting. For those transactions that do not qualify as a normal purchase or normal sale, changes in the derivatives' fair values are recognized concurrently in earnings unless specific hedge accounting criteria are met. If the derivatives meet those criteria, derivative gains and losses offset related results of the hedged item in the income statement in the case of a fair value hedge, or gains and losses are deferred in OCI until the hedged transaction occurs in the case of a cash flow hedge. Certain subsidiaries of Southern Company enter into energy-related derivatives that are designated as regulatory hedges where gains and losses are initially recorded as regulatory liabilities and assets and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through billings to customers.

Southern Company uses derivative instruments to reduce the impact to the results of operations due to the risk of changes in the price of natural gas, to manage fuel hedging programs per guidelines of state regulatory agencies, and to mitigate residual changes in the price of electricity, weather, interest rates, and foreign currency exchange rates. The fair value of commodity derivative instruments used to manage exposure to changing prices reflects the estimated amounts that Southern Company would receive or pay to terminate or close the contracts at the reporting date. To determine the fair value of the derivative instruments, Southern Company utilizes market data or assumptions that market participants would use in pricing the derivative asset or liability, including assumptions about risk and the risks inherent in the inputs of the valuation technique.

Southern Company classifies derivative assets and liabilities based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The determination of the fair value of the derivative instruments incorporates various factors required under the guidance. These factors include:

• the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit);

• events specific to a given counterparty; and

• the impact of Southern Company's nonperformance risk on its liabilities.

Given the assumptions used in pricing the derivative asset or liability, Southern Company considers the valuation of derivative assets and liabilities a critical accounting estimate. See "Quantitative and Qualitative Disclosures About Market Risk" in Item 3 herein for more information.

Recently Issued Accounting Standards

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Southern Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company's balance sheet.

On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Southern Company currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted and Southern Company intends to adopt the ASU in the fourth quarter 2016. The adoption is not expected to have a material impact on the results of operations, financial position, or cash flows of Southern Company.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at September 30, 2016. Through September 30, 2016, Southern Company has incurred non-recoverable cash expenditures of $2.42 billion and is expected to incur approximately $0.21 billion in additional non-recoverable cash expenditures through completion of the construction and start-up of the Kemper IGCC, which includes certain post-in-service costs expected to be subject to the cost cap. 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 $4.3 billion for the first nine months of 2016, a decrease of $0.8 billion from the corresponding period in 2015. The decrease in net cash provided from operating activities was primarily due to an increase in unutilized ITCs and PTCs. Net cash used for investing activities totaled $16.6 billion for the first nine months of 2016 primarily due to the closing of the Merger, the construction of electric generation, transmission, and distribution facilities and installation of equipment to comply with environmental standards, and Southern Power's acquisitions and construction of renewable facilities. Net cash provided from financing activities totaled $13.6 billion for the first nine months of 2016 primarily due to issuances of long-term debt and common stock associated with financing and completing the Merger and Southern Company Gas' investment in SNG, 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 nine months of 2016 include an increase of $14.4 billion in total property, plant, and equipment primarily related to the inclusion of Southern Company Gas as a result of the Merger, construction to comply with environmental standards, and construction of electric generation, transmission, and distribution facilities; an increase of $6.2 billion in goodwill related to the acquisitions of Southern Company Gas and PowerSecure; an increase of $1.5 billion in equity investments in unconsolidated subsidiaries primarily related to Southern Company Gas' investment in SNG; increases of $1.5 billion in other regulatory assets, deferred and $0.8 billion in AROs primarily related to changes in ash pond closure strategy principally for Georgia Power; increases of $16.9 billion in long-term debt and $4.0 billion in total common stockholder's equity primarily associated with financing and completing the Merger and Southern Company Gas' investment in SNG; and increases of $1.9 billion in accumulated deferred income taxes and $1.6 billion in other cost of removal obligations primarily related to the inclusion of Southern Company Gas as a result of the Merger. See Notes (A) and (I) to the Condensed Financial Statements herein under "Asset Retirement Obligations" and "Southern Company," respectively, for additional information.

At the end of the third quarter 2016, the market price of Southern Company's common stock was $51.30 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $25.05 per share, representing a market-to-book ratio of 205%, compared to $46.79, $22.59, and 207%, respectively, at the end of 2015. Southern Company's common stock dividend for the third quarter 2016 was $0.560 per share compared to $0.5425 per share in the third quarter 2015.

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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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, trust funding requirements, and unrecognized tax benefits. Subsequent to September 30, 2016, Mississippi Power repaid at maturity $300 million aggregate principal amount of its Series 2011A 2.35% Senior Notes due October 15, 2016 and Southern Company Gas repaid at maturity $120 million aggregate principal amount of Series A Floating Rate Senior Notes due October 27, 2016. An additional $1.8 billion will be required through September 30, 2017 to fund maturities of long-term debt. During the nine months ended September 30, 2016, and subsequent to that date, Southern Power entered into new long-term service agreements, which begin between 2017 and 2020 and result in additional future commitments totaling approximately $927 million. See "Sources of Capital" herein for additional information.

The Southern Company system's construction program is currently estimated to total $10.2 billion for 2016, $8.9 billion for 2017, $8.2 billion for 2018, $7.6 billion for 2019, $7.3 billion for 2020, and $6.6 billion for 2021. These amounts include expenditures of approximately $0.7 billion for 2016 and $0.1 billion for 2017 related to the construction and start-up of the Kemper IGCC; $0.6 billion for 2016, $0.6 billion for 2017, $0.7 billion for 2018, $0.4 billion for 2019, and $0.1 billion for 2020 to continue and complete construction of Plant Vogtle Units 3 and 4; and $4.4 billion for 2016 and $1.5 billion per year for 2017 through 2021 for Southern Power's acquisitions and/or construction of new generating facilities. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO₂ emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.

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 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; 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 "Retail 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 "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for information regarding additional factors that may impact construction expenditures.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

As a result of closing the Merger, the funding requirements of the Southern Company system include the contractual obligations of Southern Company Gas. The following table details the amounts related to Southern Company Gas as of September 30, 2016:

	2016		2017- 2018		2019- 2020		After 2020		Total
	(in millions)
Long-term debt(a) —
Principal	$	120	$	177	$	350	$	4,185	$	4,832
Interest	48		412		382		2,641		3,483
Pipeline charges, storage capacity, and gas supply(b)	308		1,350		806		2,913		5,377
Operating leases(c)	6		44		31		52		133
Asset management agreements(d)	2		15		2		—		19
Standby letters of credit, performance/surety bonds(e)	33		51		—		—		84
Financial derivative obligations(f)	195		211		21		2		429
Pension and other postretirement benefit plans(g)	5		44		—		—		49
Purchase commitments—
Capital(h)	401		3,540		3,058		1,221		8,220
Other(i)	11		53		—		—		64
Total	$	1,129	$	5,897	$	4,650	$	11,014	$	22,690

(a) Amounts are reflected based on final maturity dates. Variable rate interest obligations are estimated based on rates as of September 30, 2016.

(b) Includes charges recoverable through a natural gas cost recovery mechanism or alternatively billed to marketers and demand charges associated with wholesale gas services.

(c) Certain operating leases have provisions for step rent or escalation payments and certain lease concessions are accounted for by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms.

(d) Represents fixed-fee minimum payments for asset management agreements at wholesale gas services.

(e) Guarantees are provided to certain municipalities and other agencies and certain natural gas suppliers of SouthStar Energy Services, LLC (SouthStar) in support of payment obligations.

(f) Includes derivative liabilities related to energy-related derivatives.

(g) Estimated benefit payments for Southern Company Gas' retirement benefit plans are provided through 2018. No mandatory contributions to the plans are anticipated during this period.

(h) Estimated capital expenditures are provided through 2021.

(i) Primarily consists of contractual environmental remediation liabilities that are primarily recoverable through base rates or rate rider mechanisms.

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 2016, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements. 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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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

In addition, Georgia Power may make borrowings through a loan guarantee agreement (Loan Guarantee Agreement) between Georgia Power and the DOE, the proceeds of which 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 September 30, 2016 would allow for borrowings of up to $2.6 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.5 billion. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding the Loan Guarantee Agreement and Note (B) to the Condensed Financial Statements under "Retail 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. On April 8, 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. In addition, see Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.

As of September 30, 2016, Southern Company's current liabilities exceeded current assets by $0.9 billion, primarily due to long-term debt that is due within one year of $2.3 billion, including approximately $0.8 billion at the parent company, $0.2 billion at Alabama Power, $0.5 billion at Georgia Power, $0.2 billion at Gulf Power, $0.3 billion at Mississippi Power, $0.1 billion at Southern Power, and $0.1 billion at Southern Company Gas. To meet short-term cash needs and contingencies, Southern Company 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. In addition, Georgia Power expects to utilize borrowings through the FFB Credit Facility as an additional source of long-term borrowed funds.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At September 30, 2016, Southern Company and its subsidiaries had approximately $2.7 billion of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2016 were as follows:

	Expires												Executable Term Loans				Due Within One Year
Company	2016		2017		2018		2020		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)								(in millions)				(in millions)				(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	50		65		165		—		280		280		45		—		45		70
Mississippi Power	100		75		—		—		175		150		—		15		15		160
Southern Power Company(b)	—		—		—		600		600		532		—		—		—		—
Southern Company Gas(c)	—		75		1,925		—		2,000		1,947		—		—		—		—
Other	—		55		—		—		55		55		20		—		20		35
Southern Company Consolidated	$	150	$	305	$	3,590	$	4,400	$	8,445	$	8,281	$	65	$	15	$	80	$	300

(a) Represents the Southern Company parent entity.

(b) Excludes credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which are non-recourse to Southern Power Company, the proceeds of which are being used to finance project costs related to such solar facilities currently under construction. See Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information.

(c) Southern Company Gas 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 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.

On May 24, 2016, the $8.1 billion Bridge Agreement to provide Merger financing, to the extent necessary, was terminated.

Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Mississippi Power, and Southern Power, 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. Southern Company, the traditional electric operating companies, Southern Power Company, and Southern Company Gas are currently 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 traditional electric operating companies' pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2016 was approximately $1.9 billion. In addition, at September 30, 2016, the traditional electric operating companies had approximately $358 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas may also borrow through various other arrangements with banks. Short-term borrowings are included in notes payable in the balance sheets.

Details of short-term borrowings were as follows:

	Short-term Debt at September 30, 2016				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	$	717	0.7	%	$	756	0.7	%	$	1,499
Short-term bank debt	125		1.5	%	125		1.4	%	127
Total	$	842	0.8	%	$	881	0.8	%

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016.

In addition to the short-term borrowings in the table above, the Project Credit Facilities had total amounts outstanding as of September 30, 2016 of $828 million at a weighted average interest rate of 2.05%. For the three-month period ended September 30, 2016, these credit agreements had a maximum amount outstanding of $828 million and an average amount outstanding of $805 million at a weighted average interest rate of 2.02%.

Furthermore, in connection with the acquisition of a solar facility on July 1, 2016, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. For the three-month period ended September 30, 2016, this credit agreement had a maximum amount outstanding of $217 million and an average amount outstanding of $137 million at a weighted average interest rate of 2.21%.

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

Credit Rating Risk

At September 30, 2016, Southern Company and its subsidiaries did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

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

The maximum potential collateral requirements under these contracts at September 30, 2016 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	31
At BBB- and/or Baa3	$	665
Below BBB- and/or Baa3	$	2,570

41

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 May 12, 2016, Fitch downgraded the senior unsecured long-term debt rating of Southern Company to A- from A and revised the ratings outlook from negative to stable. Fitch also downgraded the senior unsecured long-term debt rating of Mississippi Power to BBB+ from A- and revised the ratings outlook from negative to stable.

On May 13, 2016, Moody's downgraded the senior unsecured long-term debt rating of Southern Company to Baa2 from Baa1 and revised the ratings outlook from negative to stable.

On July 11, 2016, S&P raised Southern Company Gas' and Nicor Gas' corporate and senior unsecured long-term debt ratings from BBB+ to A- and revised their ratings outlooks from positive to negative.

Financing Activities

On May 11, 2016, Southern Company issued 18.3 million shares of common stock in an underwritten offering for an aggregate purchase price of approximately $889 million. Of the 18.3 million shares, approximately 2.6 million were issued from treasury and the remainder were newly issued shares. The proceeds were used to fund a portion of the consideration for the Merger and for other general corporate purposes.

On August 19, 2016, Southern Company issued 32.5 million shares of common stock in an underwritten offering for an aggregate purchase price of approximately $1.6 billion. The proceeds were used to fund a portion of the purchase price for the SNG investment and related transaction costs and for other general corporate purposes.

In addition, during the first nine months of 2016, Southern Company issued approximately 17.5 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $782 million.

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2016:

Company	Senior Note Issuances		Senior Note Maturities and Redemptions		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions and Maturities(a)
	(in millions)
Southern Company(b)	$	8,500	$	500	$	—	$	800		$	—
Alabama Power	400		200		—		45			—
Georgia Power	650		700		4		300			5
Gulf Power	—		125		—		2			—
Mississippi Power	—		—		—		1,100			652
Southern Power	1,531		—		—		63			84
Southern Company Gas(c)	900		300		—		—			—
Other	—		—		—		—			60
Elimination(d)	—		—		—		(200		)	(225		)
Southern Company Consolidated	$	11,981	$	1,825	$	4	$	2,110		$	576

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

(b) Represents the Southern Company parent entity.

(c) Reflects only long-term debt financing activities occurring subsequent to completion of the Merger. The senior notes were issued by Southern Company Gas Capital and guaranteed by Southern Company Gas.

(d) Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements.

42

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In February 2016, Southern Company entered into $700 million notional amount of forward-starting interest rate swaps to hedge exposure to interest rate changes related to anticipated debt issuances. These interest rate swaps were settled in May 2016.

In May 2016, Southern Company issued the following series of senior notes for an aggregate principal amount of $8.5 billion:

• $0.5 billion of 1.55% Senior Notes due July 1, 2018;

• $1.0 billion of 1.85% Senior Notes due July 1, 2019;

• $1.5 billion of 2.35% Senior Notes due July 1, 2021;

• $1.25 billion of 2.95% Senior Notes due July 1, 2023;

• $1.75 billion of 3.25% Senior Notes due July 1, 2026;

• $0.5 billion of 4.25% Senior Notes due July 1, 2036; and

• $2.0 billion of 4.40% Senior Notes due July 1, 2046.

The net proceeds were used to fund a portion of the consideration for the Merger and related transaction costs and for other general corporate purposes.

In September 2016, Southern Company issued $800 million aggregate principal amount of Series 2016A 5.25% Junior Subordinated Notes due October 1, 2076. The proceeds were used to repay short-term indebtedness that was incurred to repay at maturity $500 million aggregate principal amount of Southern Company's Series 2011A 1.95% Senior Notes due September 1, 2016 and for other general corporate purposes.

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

On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR.

In May 2016, Gulf Power entered into an 11-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $100 million aggregate principal amount and the proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes.

Georgia Power's "Other Long-Term Debt Issuances" reflected in the table above include borrowings in June 2016 under the FFB Credit Facility in an aggregate principal amount of $300 million at a 2.571% interest rate through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.

During the nine months ended September 30, 2016, Southern Power's subsidiaries incurred an additional $691 million of short-term borrowings pursuant to the Project Credit Facilities at a weighted average interest rate of 2.05%. Furthermore, in connection with the acquisition of a solar facility, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. In addition, on October 14, 2016, Southern Power repaid at maturity $246 million of Project Credit Facility debt.

In June 2016, Southern Power issued €600 million aggregate principal amount of Series 2016A 1.00% Senior Notes due June 20, 2022 and €500 million aggregate principal amount of Series 2016B 1.85% Senior Notes due June 20, 2026. The proceeds are being allocated to renewable energy generation projects. Southern Power's obligations under its euro-denominated fixed-rate notes were effectively converted to fixed-rate U.S. dollars at issuance through cross-currency swaps, removing foreign currency exchange risk associated with the interest and principal payments. See

43

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

In September 2016, Southern Power repaid $80 million of an outstanding $400 million floating rate bank loan and extended the maturity date of the remaining $320 million from September 2016 to September 2018. In addition, Southern Power entered into a $60 million aggregate principal amount floating rate bank loan bearing interest based on one-month LIBOR due September 2017. The proceeds were used to repay existing indebtedness and for other general corporate purposes.

In September 2016, Southern Company Gas Capital issued $350 million aggregate principal amount of 2.45% Senior Notes due October 1, 2023 and $550 million aggregate principal amount of 3.95% Senior Notes due October 1, 2046, both of which are guaranteed by Southern Company Gas. The proceeds were used to repay a $360 million promissory note issued to Southern Company for the purpose of funding a portion of the purchase price for Southern Company Gas' 50% equity interest in SNG, to fund Southern Company Gas' purchase of Piedmont Natural Gas Company, Inc.'s (Piedmont) interest in SouthStar, to make a voluntary pension contribution, to repay at maturity $120 million aggregate principal amount of Series A Floating Rate Senior Notes due October 27, 2016, and for general corporate purposes. See Note (I) to the Condensed Financial Statements under "Southern Company– Investment in Southern Natural Gas" and " – Acquisition of Remaining Interest in SouthStar" herein for additional information regarding Southern Company Gas' investment in SNG and purchase of Piedmont's interest in SouthStar, respectively.

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.

44

PART I

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Other than the changes resulting from the Merger discussed below, during the nine months ended September 30, 2016, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, or Southern Power's disclosures about market risk. 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 and Mississippi Power, 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.

As a result of closing the Merger, the Southern Company system's exposure to market risks includes Southern Company Gas. 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 their 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. If there is a significant change in the underlying market prices or pricing assumptions Southern Company uses to price the derivative assets or liabilities, such changes may have a significant impact on Southern Company's financial position, results of operations, and cash flows.

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, and Southern Power 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.

Other than the changes resulting from the Merger discussed below, there have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, or Southern Power's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the third quarter 2016 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, or Southern Power's internal control over financial reporting.

Southern Company completed the Merger on July 1, 2016, with Southern Company Gas surviving the Merger as a wholly-owned, direct subsidiary of Southern Company. Southern Company is currently in the process of integrating Southern Company Gas' operations and conducting control reviews pursuant to Section 404 of the Sarbanes-Oxley

45

Act of 2002. See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information regarding the Merger.

46

ALABAMA POWER COMPANY

47

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2016			2015			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,629		$	1,558		$	4,139		$	4,151
Wholesale revenues, non-affiliates	82			65			211			188
Wholesale revenues, affiliates	18			20			49			55
Other revenues	56			52			162			157
Total operating revenues	1,785			1,695			4,561			4,551
Operating Expenses:
Fuel	410			408			973			1,061
Purchased power, non-affiliates	63			56			139			142
Purchased power, affiliates	41			51			129			153
Other operations and maintenance	348			371			1,097			1,140
Depreciation and amortization	177			163			524			481
Taxes other than income taxes	96			91			286			275
Total operating expenses	1,135			1,140			3,148			3,252
Operating Income	650			555			1,413			1,299
Other Income and (Expense):
Allowance for equity funds used during construction	7			14			23			43
Interest expense, net of amounts capitalized	(77		)	(71		)	(224		)	(205		)
Other income (expense), net	(5		)	(7		)	(16		)	(24		)
Total other income and (expense)	(75		)	(64		)	(217		)	(186		)
Earnings Before Income Taxes	575			491			1,196			1,113
Income taxes	221			192			466			427
Net Income	354			299			730			686
Dividends on Preferred and Preference Stock	4			4			13			21
Net Income After Dividends on Preferred and Preference Stock	$	350		$	295		$	717		$	665

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2016		2015			2016			2015
	(in millions)					(in millions)
Net Income	$	354	$	299		$	730		$	686
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $(4), $(1), and $(4), respectively	—		(6		)	(2		)	(6		)
Reclassification adjustment for amounts included in net income, net of tax of $1, $-, $2, and $1, respectively	1		—			3			1
Total other comprehensive income (loss)	1		(6		)	1			(5		)
Comprehensive Income	$	355	$	293		$	731		$	681

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

48

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	730		$	686
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	634			585
Deferred income taxes	267			85
Allowance for equity funds used during construction	(23		)	(43		)
Other, net	(23		)	23
Changes in certain current assets and liabilities —
-Receivables	(4		)	(160		)
-Fossil fuel stock	18			69
-Other current assets	(46		)	(10		)
-Accounts payable	(113		)	(106		)
-Accrued taxes	203			371
-Retail fuel cost over recovery	(104		)	81
-Other current liabilities	(4		)	(2		)
Net cash provided from operating activities	1,535			1,579
Investing Activities:
Property additions	(947		)	(938		)
Nuclear decommissioning trust fund purchases	(275		)	(349		)
Nuclear decommissioning trust fund sales	275			349
Cost of removal, net of salvage	(70		)	(41		)
Change in construction payables	(37		)	(48		)
Other investing activities	(28		)	(22		)
Net cash used for investing activities	(1,082		)	(1,049		)
Financing Activities:
Proceeds —
Senior notes	400			975
Capital contributions from parent company	253			13
Pollution control revenue bonds	—			80
Other long-term debt	45			—
Redemptions and repurchases —
Preferred and preference stock	—			(412		)
Pollution control revenue bonds	—			(134		)
Senior notes	(200		)	(250		)
Payment of common stock dividends	(574		)	(428		)
Other financing activities	(15		)	(38		)
Net cash used for financing activities	(91		)	(194		)
Net Change in Cash and Cash Equivalents	362			336
Cash and Cash Equivalents at Beginning of Period	194			273
Cash and Cash Equivalents at End of Period	$	556		$	609
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $8 and $15 capitalized for 2016 and 2015, respectively)	$	215		$	192
Income taxes, net	(70		)	47
Noncash transactions — Accrued property additions at end of period	84			88

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

49

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2016			At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	556		$	194
Receivables —
Customer accounts receivable	440			332
Unbilled revenues	155			119
Under recovered regulatory clause revenues	52			43
Income taxes receivable, current	—			142
Other accounts and notes receivable	43			20
Affiliated	30			50
Accumulated provision for uncollectible accounts	(9		)	(10		)
Fossil fuel stock	220			239
Materials and supplies	420			398
Vacation pay	66			66
Prepaid expenses	56			83
Other regulatory assets, current	73			115
Other current assets	9			10
Total current assets	2,111			1,801
Property, Plant, and Equipment:
In service	25,800			24,750
Less accumulated provision for depreciation	9,018			8,736
Plant in service, net of depreciation	16,782			16,014
Nuclear fuel, at amortized cost	345			363
Construction work in progress	473			801
Total property, plant, and equipment	17,600			17,178
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	67			71
Nuclear decommissioning trusts, at fair value	781			737
Miscellaneous property and investments	105			96
Total other property and investments	953			904
Deferred Charges and Other Assets:
Deferred charges related to income taxes	518			522
Deferred under recovered regulatory clause revenues	87			99
Other regulatory assets, deferred	1,070			1,114
Other deferred charges and assets	118			103
Total deferred charges and other assets	1,793			1,838
Total Assets	$	22,457		$	21,721

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

50

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	236		$	200
Accounts payable —
Affiliated	309			278
Other	233			410
Customer deposits	88			88
Accrued taxes —
Accrued income taxes	73			—
Other accrued taxes	125			38
Accrued interest	69			73
Accrued vacation pay	55			55
Accrued compensation	97			119
Liabilities from risk management activities	10			55
Other regulatory liabilities, current	1			240
Other current liabilities	65			39
Total current liabilities	1,361			1,595
Long-term Debt	6,859			6,654
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,505			4,241
Deferred credits related to income taxes	67			70
Accumulated deferred investment tax credits	112			118
Employee benefit obligations	366			388
Asset retirement obligations	1,501			1,448
Other cost of removal obligations	695			722
Other regulatory liabilities, deferred	95			136
Deferred over recovered regulatory clause revenues	157			—
Other deferred credits and liabilities	56			76
Total deferred credits and other liabilities	7,554			7,199
Total Liabilities	15,774			15,448
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	2,607			2,341
Retained earnings	2,604			2,461
Accumulated other comprehensive loss	(31		)	(32		)
Total common stockholder's equity	6,402			5,992
Total Liabilities and Stockholder's Equity	$	22,457		$	21,721

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

51

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2016 vs. THIRD QUARTER 2015

AND

YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 2015

OVERVIEW

Alabama Power operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service territory located within 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 selling electricity. 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, increasingly 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. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Alabama Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$55	18.6	$52	7.8

Alabama Power's net income after dividends on preferred and preference stock for the third quarter 2016 was $350 million compared to $295 million for the corresponding period in 2015. The increase in net income was related to an increase in revenue primarily due to warmer weather in the third quarter 2016 as compared to the corresponding period in 2015, an increase in retail revenues under Rate CNP Compliance, and a decrease in non-fuel operations and maintenance expenses. These increases to income were partially offset by a decrease in AFUDC and an increase in depreciation and amortization.

Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2016 was $717 million compared to $665 million for the corresponding period in 2015. The increase was primarily related to an increase in retail revenues under Rate CNP Compliance and decreases in non-fuel operations and maintenance expenses and dividends on preferred and preference stock for year-to-date 2016 compared to the corresponding period in 2015. These increases to income were partially offset by a decrease in AFUDC and increases in interest expense and depreciation and amortization.

52

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$71	4.6	$(12)	(0.3)

In the third quarter 2016, retail revenues were $1.63 billion compared to $1.56 billion for the corresponding period in 2015. For year-to-date 2016, retail revenues were $4.14 billion compared to $4.15 billion for the corresponding period in 2015.

Details of the changes in retail revenues were as follows:

	Third Quarter 2016					Year-to-Date 2016
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	1,558				$	4,151
Estimated change resulting from –
Rates and pricing	42			2.7		119			2.9
Sales growth (decline)	(14		)	(0.9	)	(15		)	(0.4	)
Weather	52			3.4		5			0.1
Fuel and other cost recovery	(9		)	(0.6	)	(121		)	(2.9	)
Retail – current year	$	1,629		4.6	%	$	4,139		(0.3	)%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2016 when compared to the corresponding periods in 2015 primarily due to increased revenues under Rate CNP Compliance associated with increases in the average net investments. 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 declined in the third quarter and year-to-date 2016 when compared to the corresponding periods in 2015. Industrial KWH sales decreased 6.3% and 5.1% for the third quarter and year-to-date 2016, respectively, when compared to the corresponding periods in 2015 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals, chemicals, pipelines, paper, and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector. Weather-adjusted residential KWH sales decreased 2.4% for the third quarter 2016 due to lower customer usage primarily resulting from an increase in efficiency improvements in residential appliances and lighting, partially offset by customer growth, and remained relatively flat year-to-date 2016. Weather-adjusted commercial KWH sales remained relatively flat for the third quarter and year-to-date 2016.

Revenues resulting from changes in weather increased in the third quarter 2016 due to warmer weather experienced in Alabama Power's service territory compared to the corresponding period in 2015. For the third quarter 2016, the resulting increases were 6.2% and 2.3% for residential and commercial sales revenue, respectively.

Fuel and other cost recovery revenues decreased in the third quarter 2016 when compared to the corresponding period in 2015 primarily due to a decrease in the average cost of fuel. Fuel and other cost recovery revenues decreased year-to-date 2016 when compared to the corresponding period in 2015 primarily due to a decrease in KWH generation and a decrease in the average cost of fuel. Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the natural disaster reserve. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Non-Affiliates

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$17	26.2	$23	12.2

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not affect net income.

In the third quarter 2016, wholesale revenues from sales to non-affiliates were $82 million compared to $65 million for the corresponding period in 2015. The increase was primarily due to a 45.3% increase in KWH sales as the result of a new wholesale contract effective December 2015, partially offset by a 13.4% decrease in the price of energy as a result of lower gas prices. For year-to-date 2016, wholesale revenues from sales to non-affiliates were $211 million compared to $188 million for the corresponding period in 2015. The increase was primarily due to a 29.7% increase in KWH sales as a result of a new wholesale contract effective December 2015, partially offset by a 13.1% decrease in the price of energy as a result of lower gas prices.

Fuel and Purchased Power Expenses

	Third Quarter 2016 vs. Third Quarter 2015				Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	2		0.5	$	(88	)	(8.3	)
Purchased power – non-affiliates	7			12.5	(3		)	(2.1	)
Purchased power – affiliates	(10		)	(19.6)	(24		)	(15.7	)
Total fuel and purchased power expenses	$	(1	)		$	(115	)

For year-to-date 2016, fuel and purchased power expenses were $1.24 billion compared to $1.36 billion for the corresponding period in 2015. The decrease was primarily due to a $56 million decrease related to the average cost of fuel, a $43 million decrease related to the average cost of purchased power, and a $35 million decrease related to the volume of KWHs generated. These decreases were partially offset by a $19 million increase 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. Alabama Power, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate ECR" in Item 8 of the Form 10-K for additional information.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	Third Quarter 2016	Third Quarter 2015	Year-to-Date 2016	Year-to-Date 2015
Total generation (in billions of KWHs)	18	17	46	46
Total purchased power (in billions of KWHs)	2	2	6	5
Sources of generation (percent) —
Coal	59	61	51	56
Nuclear	22	23	24	23
Gas	18	14	19	16
Hydro	1	2	6	5
Cost of fuel, generated (in cents per net KWH)—
Coal	2.73	2.79	2.80	2.85
Nuclear	0.77	0.81	0.78	0.81
Gas	2.85	3.11	2.62	3.08
Average cost of fuel, generated (in cents per net KWH)(a)	2.32	2.39	2.25	2.40
Average cost of purchased power (in cents per net KWH)(b)	5.70	6.90	4.81	5.56

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

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

Fuel

For year-to-date 2016, fuel expense was $0.97 billion compared to $1.06 billion for the corresponding period in 2015. The decrease was primarily due to a 14.9% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and a 10.4% decrease in the volume of KWHs generated by coal, partially offset by a 17.4% increase in the volume of KWHs generated by natural gas.

Purchased Power – Non-Affiliates

In the third quarter 2016, purchased power expense from non-affiliates was $63 million compared to $56 million for the corresponding period in 2015. The increase was primarily due to a 47.8% increase in the amount of energy purchased as a result of lower cost generation, partially offset by a 23.5% decrease in the average cost of purchased power per KHW due to a decrease in transmission capacity charges.

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

Purchased Power – Affiliates

In the third quarter 2016, purchased power expense from affiliates was $41 million compared to $51 million for the corresponding period in 2015. The decrease was primarily due to a 14.4% decrease in the average cost of purchased power per KWH as a result of lower capacity charges and a 4.4% decrease in the amount of energy purchased due to the availability of lower cost energy.

For year-to-date 2016, purchased power expense from affiliates was $129 million compared to $153 million for the corresponding period in 2015. The decrease was primarily related to a 17.3% decrease in the average cost of purchased power per KWH as a result of lower natural gas prices.

55

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Other Operations and Maintenance Expenses

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(23)	(6.2)	$(43)	(3.8)

In the third quarter 2016, other operations and maintenance expenses were $348 million compared to $371 million for the corresponding period in 2015. The decrease was primarily due to a net decrease of $8 million in employee compensation and benefits, including pension costs. In addition, scheduled other power generation outage costs and uncollectible customer account expenses decreased $8 million and $3 million, respectively.

For year-to-date 2016, other operations and maintenance expenses were $1.10 billion compared to $1.14 billion for the corresponding period in 2015. The decrease was primarily due to a net decrease of $22 million in employee compensation and benefits, including pension costs. In addition, scheduled steam and other power generation outage costs decreased $18 million.

See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

Depreciation and Amortization

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$14	8.6	$43	8.9

In the third quarter 2016, depreciation and amortization was $177 million compared to $163 million for the corresponding period in 2015. For year-to-date 2016, depreciation and amortization was $524 million compared to $481 million for the corresponding period in 2015. These increases were primarily the result of an increase in depreciation of compliance related steam equipment. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP" in Item 8 of the Form 10-K for additional information.

Taxes Other Than Income Taxes

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$5	5.5	$11	4.0

In the third quarter 2016, taxes other than income taxes were $96 million compared to $91 million for the corresponding period in 2015. For year-to-date 2016, taxes other than income taxes were $286 million compared to $275 million for the corresponding period in 2015. These increases were primarily due to increases in state and municipal utility license tax bases and increases in ad valorem taxes primarily due to an increase in assessed value of property.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Allowance for Equity Funds Used During Construction

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(7)	(50.0)	$(20)	(46.5)

In the third quarter 2016, AFUDC equity was $7 million compared to $14 million for the corresponding period in 2015. For year-to-date 2016, AFUDC equity was $23 million compared to $43 million for the corresponding period in 2015. These decreases were primarily associated with environmental compliance and steam generation capital projects being placed in service in 2016.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$6	8.5	$19	9.3

In the third quarter 2016, interest expense, net of amounts capitalized was $77 million compared to $71 million for the corresponding period in 2015. The increase was primarily due to an increase in debt outstanding and a reduction in amounts capitalized.

For year-to-date 2016, interest expense, net of amounts capitalized was $224 million compared to $205 million for the corresponding period in 2015. The increase was primarily due to an increase in debt outstanding and a reduction in amounts capitalized. See "Allowance for Equity Funds Used During Construction" herein, FUTURE EARNINGS POTENTIAL – "Financing Activities – Financial Condition and Liquidity" herein, and Note 6 to the financial statements of Alabama Power under "Senior Notes" in Item 8 of the Form 10-K for additional information.

Other Income (Expense), Net

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$2	28.6	$8	33.3

For year-to-date 2016, other income (expense), net was $(16) million compared to $(24) million for the corresponding period in 2015. The change was primarily due to a decrease in donations, partially offset by a decrease in sales of non-utility property in 2016.

Income Taxes

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$29	15.1	$39	9.1

In the third quarter 2016, income taxes were $221 million compared to $192 million for the corresponding period in 2015. The increase was primarily due to higher pre-tax earnings in 2016.

For year-to-date 2016, income taxes were $466 million compared to $427 million for the corresponding period in 2015. The increase was primarily due to higher pre-tax earnings and state tax credits taken in 2015.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Dividends on Preferred and Preference Stock

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$(8)	(38.1)

For year-to-date 2016, dividends on preferred and preference stock were $13 million compared to $21 million for the corresponding period in 2015. This decrease was primarily due to the redemption in May 2015 of certain series of preferred and preference stock. See Note 6 to the financial statements of Alabama Power under "Redeemable Preferred and Preference Stock" in Item 8 of the Form 10-K for additional information.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of 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 selling electricity. 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. Future earnings in the near term will depend, in part, upon maintaining and growing sales 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 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. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.

Environmental Matters

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

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's final MATS rule, regional haze regulations, and the Cross State Air Pollution Rule (CSAPR).

On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion, the EPA published its supplemental finding regarding consideration of costs in support of the MATS rule. This finding does not impact MATS rule

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

compliance requirements, costs, or deadlines, and all Alabama Power units that are subject to the MATS rule completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.

Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and cannot be determined at this time.

On October 26, 2016, the EPA published a final rule that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Alabama. The ultimate impact of this rule will depend on the outcome of any legal challenges and implementation at the state level and cannot be determined at this time.

FERC Matters

See BUSINESS – "Regulation – Federal Power Act" in Item 1 of the Form 10-K for a discussion of Alabama Power's hydroelectric developments on the Coosa River. On April 21, 2016, the FERC issued an order granting in part and denying in part Alabama Power's rehearing request of the new license for Alabama Power's seven hydroelectric developments on the Coosa River. The order also denied rehearing requests filed by Alabama Rivers Alliance, American Rivers, the Georgia Environmental Protection Division, and the Atlanta Regional Commission. On May 17, 2016, Alabama Rivers Alliance and American Rivers filed an additional rehearing request and also filed a petition for review by the U.S. Court of Appeals for the District of Columbia Circuit. On September 12, 2016, the FERC issued an order denying the second rehearing request, and Alabama Rivers Alliance and American Rivers filed an appeal of the April 21, 2016 order to the U.S. Court of Appeals for the District of Columbia Circuit. 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 its Rate RSE, Rate CNP Compliance, rate energy cost recovery, and rate natural disaster reserve. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Notes 1 and 3 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.

Environmental Accounting Order

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Environmental Accounting Order" of Alabama Power in Item 7 of the Form 10-K for information regarding the environmental accounting order.

In April 2016, as part of its environmental compliance strategy, Alabama Power ceased using coal at Plant Greene County Units 1 and 2 (300 MWs representing Alabama Power's ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively.

Renewables

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

In accordance with the Alabama PSC order approving up to 500 MWs of renewable projects, Alabama Power has entered into agreements to purchase power from or to build renewable generation sources, including a 72-MW solar PPA approved by the Alabama PSC in June 2016. Alabama Power is marketing the associated renewable energy credits (REC) generated by this solar PPA to customers interested in supporting renewable energy development. The

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

terms of the renewable agreements permit Alabama Power to use the energy and retire the associated RECs in service of its customers or to sell RECs, separately or bundled with energy.

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.

TheultimateoutcomeofsuchpendingorpotentiallitigationagainstAlabama Powercannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementshereinorinNote3tothefinancialstatementsofAlabama PowerinItem8ofthe Form 10-K,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 Electric Utility Regulation, Asset Retirement Obligations, Pension and Other Postretirement Benefits, and Contingent Obligations.

Recently Issued Accounting Standards

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Alabama Power is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Alabama Power's balance sheet.

On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Alabama Power currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

adoption is permitted and Alabama Power intends to adopt the ASU in the fourth quarter 2016. The adoption is not expected to have a material impact on the results of operations, financial position, or cash flows of Alabama Power.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at September 30, 2016. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $1.5 billion for the first nine months of 2016, a decrease of $44 million as compared to the first nine months of 2015. The decrease in net cash provided from operating activities was primarily due to lower fuel cost recovery revenues during 2016, partially offset by lower income tax payments and the receipt of income tax refunds as a result of bonus depreciation. Net cash used for investing activities totaled $1.1 billion for the first nine months of 2016 primarily due to gross property additions related to environmental, distribution, steam generation, and transmission. Net cash used for financing activities totaled $91 million for the first nine months of 2016 primarily due to common stock dividend payments and a redemption of long-term debt, partially offset by issuances of long-term debt and additional capital contributions from Southern Company. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first nine months of 2016 include increases of $422 million in property, plant, and equipment, primarily due to additions to environmental, distribution, nuclear generation, and transmission, $362 million in cash and cash equivalents, $266 million in additional paid-in capital due to capital contributions from Southern Company, $264 million in accumulated deferred income taxes related to bonus depreciation, and $205 million in long-term debt primarily due to the issuance of additional senior notes. Other significant changes include decreases of $239 million in other regulatory liabilities, current, primarily due to the timing of fuel cost recovery and $177 million in other accounts payable primarily due to the timing of vendor payments.

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 $236 million will be required through September 30, 2017 to fund maturities of long-term debt.

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

Alabama Power's approved construction program is currently estimated to total $1.9 billion for 2017, $1.6 billion for 2018, $1.2 billion for 2019, $1.3 billion for 2020, and $1.2 billion for 2021. The construction program includes capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements. Estimated capital expenditures to comply with environmental statutes and

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

regulations included in these amounts are $0.5 billion for 2017, $0.3 billion for 2018, $0.1 billion for 2019, $0.1 billion for 2020, and $0.2 billion for 2021. These estimated expenditures include anticipated costs for compliance with the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) and the EPA's final effluent guidelines rule. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved state plans that would limit CO₂ emissions from existing, new, modified, or reconstructed fossil-fuel-fired electric generating units.

Alabama Power also anticipates costs associated with closure in place and ground water monitoring of ash ponds in accordance with the CCR Rule, which are not reflected in the capital expenditures above as these costs are associated with Alabama Power's asset retirement obligation liabilities. These costs, which will change as Alabama Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance, are estimated to be $31 million for 2017, $26 million for 2018, $100 million for 2019, $105 million for 2020, and $107 million for 2021. See Note 1 to the financial statements of Alabama Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information. Costs associated with the CCR Rule are expected to be recovered through Rate CNP Compliance.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing 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 through 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, depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.

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

At September 30, 2016, Alabama Power had approximately $556 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2016 were as follows:

Expires										Due Within One Year
2017		2018		2020		Total		Unused		Term Out		No Term Out
(in millions)						(in millions)				(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.

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

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Alabama Power defaulted on indebtedness, the payment of which was then accelerated. Alabama Power is currently 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 borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2016 was approximately $890 million. In addition, at September 30, 2016, Alabama Power had $87 million of 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 company under these arrangements are several and there is no cross-affiliate credit support.

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	$	15	0.6	%	$	100

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016. No short-term debt was outstanding at September 30, 2016.

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

Credit Rating Risk

Alabama 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 primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, energy price risk management, and transmission. The maximum potential collateral requirements under these contracts at September 30, 2016 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	$	347

63

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. 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.

Financing Activities

In January 2016, Alabama Power issued $400 million aggregate principal amount of Series 2016A 4.30% Senior Notes due January 2, 2046. The proceeds were used to repay at maturity $200 million aggregate principal amount of Alabama Power's Series FF 5.20% Senior Notes due January 15, 2016 and for general corporate purposes, including Alabama Power's continuous construction program.

In March 2016, Alabama Power entered into three bank term loan agreements with maturity dates of March 2021, in an aggregate principal amount of $45 million, one of which bears interest at 2.38% per annum and two of which bear interest based on three-month LIBOR.

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.

64

GEORGIA POWER COMPANY

65

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2016			2015			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	2,540		$	2,537		$	6,164		$	6,223
Wholesale revenues, non-affiliates	49			55			131			173
Wholesale revenues, affiliates	9			5			24			18
Other revenues	100			94			302			271
Total operating revenues	2,698			2,691			6,621			6,685
Operating Expenses:
Fuel	575			706			1,390			1,735
Purchased power, non-affiliates	102			90			277			227
Purchased power, affiliates	142			148			392			411
Other operations and maintenance	496			462			1,393			1,405
Depreciation and amortization	215			214			639			633
Taxes other than income taxes	114			107			311			302
Total operating expenses	1,644			1,727			4,402			4,713
Operating Income	1,054			964			2,219			1,972
Other Income and (Expense):
Interest expense, net of amounts capitalized	(98		)	(90		)	(290		)	(272		)
Other income (expense), net	11			18			35			34
Total other income and (expense)	(87		)	(72		)	(255		)	(238		)
Earnings Before Income Taxes	967			892			1,964			1,734
Income taxes	365			337			737			657
Net Income	602			555			1,227			1,077
Dividends on Preferred and Preference Stock	4			4			13			13
Net Income After Dividends on Preferred and Preference Stock	$	598		$	551		$	1,214		$	1,064

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2016		2015			2016		2015
	(in millions)					(in millions)
Net Income	$	602	$	555		$	1,227	$	1,077
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $(7), $-, and $(7), respectively	—		(11		)	—		(10		)
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $1, and $1, respectively	1		1			2		2
Total other comprehensive income (loss)	1		(10		)	2		(8		)
Comprehensive Income	$	603	$	545		$	1,229	$	1,069

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

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GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	1,227		$	1,077
Adjustments to reconcile net income to net cash provided from operating activities --
Depreciation and amortization, total	794			766
Deferred income taxes	346			12
Allowance for equity funds used during construction	(36		)	(24		)
Deferred expenses	(40		)	(45		)
Pension, postretirement, and other employee benefits	(14		)	40
Settlement of asset retirement obligations	(93		)	(18		)
Other, net	4			48
Changes in certain current assets and liabilities —
-Receivables	(162		)	37
-Fossil fuel stock	128			141
-Prepaid income taxes	45			244
-Other current assets	17			(17		)
-Accounts payable	39			(118		)
-Accrued taxes	(22		)	54
-Accrued compensation	(26		)	(34		)
-Other current liabilities	53			(3		)
Net cash provided from operating activities	2,260			2,160
Investing Activities:
Property additions	(1,566		)	(1,321		)
Nuclear decommissioning trust fund purchases	(563		)	(815		)
Nuclear decommissioning trust fund sales	558			810
Cost of removal, net of salvage	(45		)	(57		)
Change in construction payables, net of joint owner portion	(139		)	44
Prepaid long-term service agreements	(27		)	(60		)
Other investing activities	24			11
Net cash used for investing activities	(1,758		)	(1,388		)
Financing Activities:
Decrease in notes payable, net	(63		)	(26		)
Proceeds —
Capital contributions from parent company	294			41
Pollution control revenue bonds	—			274
Senior notes	650			—
FFB loan	300			600
Short-term borrowings	—			250
Redemptions and repurchases —
Pollution control revenue bonds	(4		)	(268		)
Senior notes	(700		)	(525		)
Short-term borrowings	—			(250		)
Payment of common stock dividends	(979		)	(776		)
Other financing activities	(20		)	(31		)
Net cash used for financing activities	(522		)	(711		)
Net Change in Cash and Cash Equivalents	(20		)	61
Cash and Cash Equivalents at Beginning of Period	67			24
Cash and Cash Equivalents at End of Period	$	47		$	85
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $15 and $10 capitalized for 2016 and 2015, respectively)	$	277		$	251
Income taxes, net	188			311
Noncash transactions — Accrued property additions at end of period	226			192

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

67

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2016			At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	47		$	67
Receivables —
Customer accounts receivable	718			541
Unbilled revenues	298			188
Joint owner accounts receivable	46			227
Income taxes receivable, current	—			114
Other accounts and notes receivable	55			57
Affiliated	15			18
Accumulated provision for uncollectible accounts	(2		)	(2		)
Fossil fuel stock	274			402
Materials and supplies	470			449
Vacation pay	90			91
Prepaid income taxes	111			156
Other regulatory assets, current	115			123
Other current assets	89			92
Total current assets	2,326			2,523
Property, Plant, and Equipment:
In service	33,394			31,841
Less accumulated provision for depreciation	11,234			10,903
Plant in service, net of depreciation	22,160			20,938
Other utility plant, net	—			171
Nuclear fuel, at amortized cost	556			572
Construction work in progress	4,888			4,775
Total property, plant, and equipment	27,604			26,456
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	61			64
Nuclear decommissioning trusts, at fair value	835			775
Miscellaneous property and investments	42			43
Total other property and investments	938			882
Deferred Charges and Other Assets:
Deferred charges related to income taxes	675			679
Other regulatory assets, deferred	2,530			2,152
Other deferred charges and assets	175			173
Total deferred charges and other assets	3,380			3,004
Total Assets	$	34,248		$	32,865

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

68

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	458		$	712
Notes payable	95			158
Accounts payable —
Affiliated	451			411
Other	464			750
Customer deposits	265			264
Accrued taxes —
Accrued income taxes	14			12
Other accrued taxes	310			325
Accrued interest	110			99
Accrued vacation pay	62			62
Accrued compensation	118			142
Asset retirement obligations, current	313			179
Over recovered regulatory clause revenues, current	125			10
Other current liabilities	197			171
Total current liabilities	2,982			3,295
Long-term Debt	10,114			9,616
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,969			5,627
Deferred credits related to income taxes	103			105
Accumulated deferred investment tax credits	199			204
Employee benefit obligations	906			949
Asset retirement obligations, deferred	2,241			1,737
Other deferred credits and liabilities	203			347
Total deferred credits and other liabilities	9,621			8,969
Total Liabilities	22,717			21,880
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	6,585			6,275
Retained earnings	4,295			4,061
Accumulated other comprehensive loss	(13		)	(15		)
Total common stockholder's equity	11,265			10,719
Total Liabilities and Stockholder's Equity	$	34,248		$	32,865

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

69

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2016 vs. THIRD QUARTER 2015

AND

YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 2015

OVERVIEW

Georgia Power operates as a vertically integrated utility providing electricity 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 selling electricity. 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, increasingly stringent environmental standards, reliability, and fuel. In addition, construction continues on Plant Vogtle Units 3 and 4. Georgia Power will own a 45.7% interest in these two nuclear generating units to increase its generation diversity and meet future supply needs. Georgia Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms andappropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.

On October 20, 2016, Georgia Power and the Georgia PSC Staff entered into a settlement agreement resolving certain prudence and cost recovery matters related to Plant Vogtle Units 3 and 4. The settlement agreement is subject to approval by the Georgia PSC. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC on April 14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.

Georgia Power continues to focus on several key performance indicators. These indicators include, but are 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. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Georgia Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$47	8.5	$150	14.1

Georgia Power's net income after dividends on preferred and preference stock was $598 million for the third quarter 2016 compared to $551 million for the corresponding period in 2015. The increase was primarily due to an increase in retail base revenues effective January 1, 2016, as authorized by the Georgia PSC, and higher retail revenues due to warmer weather as compared to the corresponding period in 2015, partially offset by higher non-fuel operating expenses.

For year-to-date 2016, net income after dividends on preferred and preference stock was $1.21 billion compared to $1.06 billion for the corresponding period in 2015. The increase was primarily due to an increase in retail base revenues effective January 1, 2016, as authorized by the Georgia PSC, the 2015 correction of an error affecting billings to a small number of large commercial and industrial customers, higher retail revenues in the third quarter

70

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

2016 due to warmer weather as compared to the corresponding period in 2015, and lower non-fuel operating expenses. Partially offsetting the increase were lower retail revenues in the first quarter 2016 due to milder weather as compared to the corresponding period in 2015.

Retail Revenues

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$3	0.1	$(59)	(0.9)

Retail revenues increased slightly in the third quarter 2016 compared to the corresponding period in 2015. For year-to-date 2016, retail revenues were $6.16 billion compared to $6.22 billion for the corresponding period in 2015.

Details of the changes in retail revenues were as follows:

	Third Quarter 2016					Year-to-Date 2016
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	2,537				$	6,223
Estimated change resulting from –
Rates and pricing	22			0.9		167			2.7
Sales growth	1			—		3			—
Weather	105			4.1		75			1.2
Fuel cost recovery	(125		)	(4.9	)	(304		)	(4.9	)
Retail – current year	$	2,540		0.1	%	$	6,164		(1.0	)%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2016 when compared to the corresponding periods in 2015 primarily due to increases in base tariffs approved under the 2013 ARP and the NCCR tariff, all effective January 1, 2016. Also contributing to the increase for year-to-date 2016 was the 2015 correction of an error affecting billings since 2013 to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans" and " – Nuclear Construction" in Item 8 of the Form 10-K for additional information.

Revenues attributable to changes in sales were essentially flat in the third quarter and year-to-date 2016 when compared to the corresponding periods in 2015. Weather-adjusted residential KWH sales increased 1.7%, weather-adjusted commercial KWH sales decreased 0.7%, and weather-adjusted industrial KWH sales decreased 3.4% in the third quarter 2016 when compared to the corresponding period in 2015. For year-to-date 2016, weather-adjusted residential KWH sales increased 1.0%, weather-adjusted commercial KWH sales decreased 0.6%, and weather-adjusted industrial KWH sales decreased 0.5% when compared to the corresponding period in 2015. An increase of approximately 29,000 residential customers since September 30, 2015 contributed to the increase in weather-adjusted residential KWH sales, partially offset by a decline in average customer usage primarily resulting from an increase in multi-family housing and efficiency improvements in residential appliances and lighting. A decline in average customer usage resulting from an increase in energy saving initiatives contributed to the decrease in weather-adjusted commercial KWH sales, partially offset by an increase of approximately 3,000 commercial customers since September 30, 2015. Decreased demand in the pipeline, textiles, 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 non-manufacturing sector.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased $125 million and $304 million in the third quarter and year-to-date 2016, respectively, when compared to the corresponding periods in 2015 primarily due to lower fuel prices. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel

71

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.

Wholesale Revenues – Non-Affiliates

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(6)	(10.9)	$(42)	(24.3)

Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost to produce the energy.

In the third quarter 2016, wholesale revenues from sales to non-affiliates were $49 million compared to $55 million for the corresponding period in 2015 related to a $7 million decrease in capacity revenues, partially offset by a $1 million increase in energy revenues. For year-to-date 2016, wholesale revenues from sales to non-affiliates were $131 million compared to $173 million for the corresponding period in 2015 related to a $28 million decrease in capacity revenues and a $14 million decrease in energy revenues. The decreases in capacity revenues reflect the expiration of wholesale contracts in the second quarter 2016. In addition, the decrease in capacity revenues for year-to-date 2016 reflects the retirement of 14 coal-fired generating units since March 31, 2015 as a result of Georgia Power's environmental compliance strategy. The decrease in energy revenues for year-to-date 2016 was primarily due to lower fuel prices. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" and "Retail Regulatory Matters – Integrated Resource Plan" of Georgia Power in Item 7 of the Form 10-K for additional information related to Georgia Power's environmental compliance strategy.

Other Revenues

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$6	6.4	$31	11.4

For year-to-date 2016, other revenues were $302 million compared to $271 million for the corresponding period in 2015. The increase was primarily due to a $14 million increase related to customer temporary facilities services revenues, a $9 million increase in outdoor lighting revenues, and a $3 million increase in solar application fee revenues. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Renewables" herein for additional information on Georgia Power's solar renewable energy program.

72

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses

	Third Quarter 2016 vs. Third Quarter 2015					Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	(131	)	(18.6	)	$	(345	)	(19.9	)
Purchased power – non-affiliates	12			13.3		50			22.0
Purchased power – affiliates	(6		)	(4.1	)	(19		)	(4.6	)
Total fuel and purchased power expenses	$	(125	)			$	(314	)

In the third quarter 2016, total fuel and purchased power expenses were $819 million compared to $944 million in the corresponding period in 2015. The decrease in the third quarter 2016 was due to a net decrease of $189 million in the average cost of fuel and purchased power related to lower coal prices, partially offset by a $64 million increase related to the volume of KWHs generated and purchased as a result of warmer weather as compared to the corresponding period in 2015 resulting in higher customer demand.

For year-to-date 2016, total fuel and purchased power expenses were $2.06 billion compared to $2.37 billion in the corresponding period in 2015. The decrease in year-to-date 2016 was primarily due to a decrease of $326 million in the average cost of fuel and purchased power related to lower coal and natural gas prices and a $20 million decrease related to the volume of KWHs generated, partially offset by a $32 million increase related to the volume of KWHs purchased primarily as a result of warmer weather in the third quarter 2016 as compared to the corresponding period in 2015 resulting in higher 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 FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.

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

	Third Quarter 2016	Third Quarter 2015	Year-to-Date 2016	Year-to-Date 2015
Total generation (in billions of KWHs)	20	19	53	53
Total purchased power (in billions of KWHs)	7	7	19	18
Sources of generation (percent) —
Coal	44	41	37	38
Nuclear	22	22	23	23
Gas	34	36	38	37
Hydro	—	1	2	2
Cost of fuel, generated (in cents per net KWH)—
Coal	3.16	5.42	3.32	4.65
Nuclear	0.85	0.86	0.85	0.76
Gas	2.61	2.57	2.27	2.62
Average cost of fuel, generated (in cents per net KWH)	2.47	3.37	2.34	2.98
Average cost of purchased power (in cents per net KWH)(*)	4.57	4.54	4.46	4.50

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

73

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel

In the third quarter 2016, fuel expense was $575 million compared to $706 million in the corresponding period in 2015. The decrease was primarily due to a 26.7% decrease in the average cost of fuel per KWH generated primarily resulting from lower coal prices, partially offset by a 6.6% increase in the volume of KWHs generated due to warmer weather as compared to the corresponding period in 2015.

For year-to-date 2016, fuel expense was $1.39 billion compared to $1.74 billion in the corresponding period in 2015. The decrease was primarily due to a 21.5% decrease in the average cost of fuel per KWH generated primarily resulting from lower coal and natural gas prices and a 3.0% decrease in the volume of KWHs generated by coal.

Purchased Power – Non-Affiliates

In the third quarter 2016, purchased power expense from non-affiliates was $102 million compared to $90 million in the corresponding period in 2015. The increase was primarily due to an 18.3% increase in the volume of KWHs purchased due to warmer weather as compared to the corresponding period in 2015, partially offset by a 5.6% decrease in the average cost per KWH purchased primarily resulting from lower natural gas prices.

For year-to-date 2016, purchased power expense from non-affiliates was $277 million compared to $227 million in the corresponding period in 2015. The increase was primarily due to a 29.8% increase in the volume of KWHs purchased, partially offset by a 10.4% decrease in the average cost per KWH purchased primarily resulting from lower natural gas prices.

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

Purchased Power – Affiliates

In the third quarter 2016, purchased power expense from affiliates was $142 million compared to $148 million in the corresponding period in 2015. The decrease was the result of a 2.4% decrease in the volume of KWHs purchased as Georgia Power's units generally dispatched at a lower cost than other available Southern Company system resources, partially offset by a 1.8% increase in the average cost per KWH purchased.

For year-to-date 2016, purchased power expense from affiliates was $392 million compared to $411 million in the corresponding period in 2015. The decrease was primarily the result of a 2.7% decrease in the volume of KWHs purchased due to the lower market cost of available energy as compared to Southern Company system resources.

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

Other Operations and Maintenance Expenses

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$34	7.4	$(12)	(0.9)

In the third quarter 2016, other operations and maintenance expenses were $496 million compared to $462 million in the corresponding period in 2015. The increase was primarily due to a $26 million charge in connection with an employee attrition plan associated with cost containment activities, an $11 million increase in scheduled generation outage and maintenance costs, and an $11 million increase in transmission and distribution overhead line maintenance, partially offset by a $9 million decrease in pension costs.

For year-to-date 2016, other operations and maintenance expenses were $1.39 billion compared to $1.41 billion in the corresponding period in 2015. The decrease was primarily due to decreases of $31 million in scheduled generation outage and maintenance costs and $28 million in pension costs, partially offset by a $26 million charge

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in connection with an employee attrition plan associated with cost containment activities, an increase of $16 million in transmission and distribution overhead line maintenance, and an increase of $9 million for integrated transmission system billings.

See FUTURE EARNINGS POTENTIAL – "Other Matters" and Note (F) to the Condensed Financial Statements herein for additional information related to the employee attrition plan and pension costs, respectively.

Depreciation and Amortization

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$1	0.5	$6	0.9

For year-to-date 2016, depreciation and amortization was $639 million compared to $633 million in the corresponding period in 2015. The increase was primarily due to a $25 million increase related to additional plant in service and a $9 million increase in other cost of removal, partially offset by a decrease of $14 million related to amortization of nuclear construction financing costs that was completed in December 2015 and a decrease of $13 million related to unit retirements.

Taxes Other Than Income Taxes

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$7	6.5	$9	3.0

In the third quarter 2016, taxes other than income taxes were $114 million compared to $107 million in the corresponding period in 2015. For year-to-date 2016, taxes other than income taxes were $311 million compared to $302 million in the corresponding period in 2015. The increases were primarily due to increases in property taxes of $5 million and $8 million in the third quarter and year-to-date 2016, respectively, as a result of an increase in the assessed value of property.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$8	8.9	$18	6.6

In the third quarter 2016, interest expense, net of amounts capitalized was $98 million compared to $90 million in the corresponding period in 2015. The increase was primarily due to a $7 million increase in interest due to additional long-term borrowings from the FFB and higher interest rates on obligations for pollution control revenue bonds remarketed in 2015.

For year-to-date 2016, interest expense, net of amounts capitalized was $290 million compared to $272 million in the corresponding period in 2015. The increase was primarily due to a $27 million increase in interest due to additional long-term borrowings from the FFB and higher interest rates on obligations for pollution control revenue bonds remarketed in 2015, partially offset by an increase of $5 million in AFUDC debt and a decrease of $4 million in interest due to lower interest rates on obligations for senior notes.

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Income Taxes

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$28	8.3	$80	12.2

In the third quarter 2016, income taxes were $365 million compared to $337 million in the corresponding period in 2015. For year-to-date 2016, income taxes were $737 million compared to $657 million in the corresponding period in 2015. The increases were primarily due to higher pre-tax earnings.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Georgia Power's future earnings potential. The level of Georgia Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power's business of selling electricity. 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 the completion and subsequent operation of ongoing construction projects, primarily Plant Vogtle Units 3 and 4. Future earnings in the near term will depend, in part, upon maintaining and growing sales 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 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. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.

Environmental Matters

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

Environmental Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's final MATS rule, regional haze regulations, fine particulate matter National Ambient Air Quality Standards (NAAQS), and the Cross State Air Pollution Rule (CSAPR).

On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion, the EPA published its supplemental finding regarding consideration of costs in support of the MATS rule. This finding does not impact MATS rule

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compliance requirements, costs, or deadlines, and all Georgia Power units that are subject to the MATS rule completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.

Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and cannot be determined at this time.

On September 6, 2016, the EPA designated all remaining areas within Georgia Power's service territory as attainment for the 2012 annual fine particulate matter NAAQS.

On October 26, 2016, the EPA published a final rule that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Alabama and certain other states. The State of Georgia's emission budget was not affected by the revisions but interstate emissions trading is restricted unless the state decides to voluntarily adopt a reduced budget. The ultimate impact of this rule will depend on the outcome of any legal challenges and implementation at the state level and cannot be determined at this time.

Coal Combustion Residuals

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Residuals" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.

On June 13, 2016, Georgia Power announced that all of its 29 ash ponds will cease operations and stop receiving coal ash in the next three years, and all ponds will eventually be closed either by removal, consolidation, and/or recycling for the beneficial use of coal ash or through closure in place using advanced engineering methods. On October 26, 2016, the Georgia Department of Natural Resources approved amendments to its state solid waste regulations to incorporate the requirements of the EPA's Disposal of Coal Combustion Residuals from Electric Utilities Rule (CCR Rule) and establish additional requirements for all of Georgia Power's onsite storage units consisting of landfills and surface impoundments. The final State of Georgia regulations are not anticipated to have a material impact on Georgia Power's compliance obligations under the CCR Rule. See Note (A) to the Condensed Financial Statements herein for information regarding Georgia Power's asset retirement obligations (ARO) as of September 30, 2016.

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 separate fuel cost recovery tariffs. 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 "Fuel Cost Recovery" herein for additional information regarding fuel cost recovery.

Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC on April 14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company (collectively, Utilities) each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each utility will be shared on a 60/40 basis between their respective customers and the Utilities; thereafter, all merger savings will be retained by customers. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding the 2013 ARP.

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Renewables

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

As part of the Georgia Power Advanced Solar Initiative (ASI), four PPAs totaling 149 MWs of solar contracted capacity from Southern Power began in the first quarter 2016. During the second quarter 2016, Georgia Power executed PPAs to purchase an additional 41 MWs of solar capacity under the ASI. Ownership of any associated renewable energy credits (REC) is specified in each respective PPA. The party that owns the RECs retains the right to use them.

On October 4, 2016, two 30-MW solar generating facilities at Fort Gordon and Fort Stewart Army bases began commercial operation. These solar generating facilities were approved by the Georgia PSC in 2014.

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 (2016 IRP).

On July 28, 2016, the Georgia PSC voted to approve the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 combustion turbine (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. On August 31, 2016, Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc.

Additionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.

The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date will be deferred for consideration in Georgia Power's base rate case required to be filed by July 1, 2019.

The Georgia PSC also approved the Renewable Energy Development Initiative to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.

The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve the nuclear option at a future generation site in Stewart County, Georgia. The timing of cost recovery 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 MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for information regarding fuel cost recovery.

Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. On May 17, 2016, the Georgia PSC approved Georgia Power's request to decrease fuel rates by 15% effective June 1, 2016, which will

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reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017.

Storm Damage Recovery

As of September 30, 2016, the balance in Georgia Power's regulatory asset related to storm damage was $94 million. During October 2016, Hurricane Matthew caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of restoration costs related to this hurricane is estimated to be between $130 million and $155 million, which will be charged to capital accounts or to the storm damage reserve. Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, to the storm damage reserve to cover the operating and maintenance costs of damages from major storms to its transmission and distribution facilities, which is recoverable through base rates. The rate of recovery of storm damage costs after December 31, 2019 is expected to be adjusted in Georgia Power's base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Georgia Power's financial statements. See Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.

Nuclear Construction

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

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 performance guarantees, subject to a cap. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), 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%.

On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from Chicago Bridge & Iron Company, N.V. (CB&I) and changed the name of Stone & Webster, Inc. to WECTEC Global Project Services Inc. (WECTEC). Certain obligations of Westinghouse and WECTEC under the Vogtle 3 and 4 Agreement were originally guaranteed by Toshiba Corporation (Westinghouse's parent company) and The Shaw Group Inc. (which is now a subsidiary of CB&I), respectively. On March 9, 2016, in connection with Westinghouse's acquisition of WECTEC and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. was terminated. The guarantee of Toshiba Corporation remains in place. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. Additionally, as a result of credit rating downgrades of Toshiba Corporation, Westinghouse provided the Vogtle Owners with letters of credit in an aggregate amount of $920 million in accordance with, and subject to adjustment under, the terms of the Vogtle 3 and 4 Agreement.

The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4

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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 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected construction capital costs to be borne by Georgia Power increase by 5% above the certified cost or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. In February 2013, Georgia Power requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 (from April 2016) and the fourth quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the Georgia PSC Staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate until the completion of Plant Vogtle Unit 3 or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report, which included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion. Pursuant to the Georgia PSC's procedural order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent.

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). Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; and (v) provide that Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $256 million had been paid as of September 30, 2016. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs were reflected in Georgia Power's previously disclosed in-service cost estimate. Further, as part of the settlement and Westinghouse's acquisition of WECTEC: (i) Westinghouse engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.

The Georgia PSC has approved fourteen VCM reports covering the periods through December 31, 2015, including construction capital costs incurred, which through that date totaled $3.3 billion. On January 21, 2016, Georgia Power submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement

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to the Georgia PSC for its review. In accordance with the Georgia PSC's subsequent order, on April 5, 2016, Georgia Power filed supplemental information in support of the Contractor Settlement Agreement and Georgia Power's position that all construction costs to date have been prudently incurred and that the current estimated in-service capital cost and schedule are reasonable.

On October 20, 2016, Georgia Power and the Georgia PSC Staff entered into 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 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 commercial operation. The ROE used to calculate the NCCR tariff will be 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 commercially operational by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units reach commercial operation 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 upon reaching commercial operation, 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 Vogtle Cost Settlement Agreement is subject to approval by the Georgia PSC, which is scheduled to vote on this matter on December 20, 2016. Accordingly, the terms of the Vogtle Cost Settlement Agreement are subject to change and the terms of any final agreement approved by the Georgia PSC may differ materially from the terms of the Vogtle Cost Settlement Agreement. If approved, the Vogtle Cost Settlement Agreement is expected to reduce Georgia Power's revenues for the years 2016 through 2020 by a total of approximately $325 million ($115 million reduction in net income).

On August 31, 2016, Georgia Power filed the fifteenth VCM report with the Georgia PSC covering the period from January 1 through June 30, 2016 requesting approval of $141 million of construction capital costs incurred during that period. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.8 billion as of September 30, 2016. Estimated financing costs during the construction period total approximately $2.4 billion, of which $1.2 billion had been incurred through September 30, 2016.

On November 1, 2016, Georgia Power submitted its 2017 NCCR tariff filing requesting that the current NCCR tariff rate remain effective for 2017 if the Georgia PSC approves the Vogtle Cost Settlement Agreement. As required under the current order, Georgia Power concurrently submitted a 2017 NCCR tariff rate calculated using the current authorized 10.95% ROE, which would result in an increase of approximately $70 million.

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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 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 either to the Vogtle Owners or the Contractor or to both.

As construction continues, the risk remains that challenges with Contractor performance including 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. Contractor performance and progress in recent months, primarily associated with Unit 3, has resulted in additional current schedule pressure of approximately three to four months and has increased the likelihood of further schedule impacts to that unit. Georgia Power expects the Contractor to employ mitigation efforts to maintain the current project schedule and believes the Contractor is responsible for any related costs under the Vogtle 3 and 4 Agreement. Should Unit 3 be placed in service after June 2019, Georgia Power estimates its financing costs to be approximately $22 million per month. Additionally, Georgia Power estimates its owner's costs to be approximately $2 million per month, net of delay liquidated damages and certain incentive payments that would no longer be required to be paid per the Contractor Settlement Agreement. The Contractor's progress on Unit 4 indicates that the current estimated in-service date of June 2020 remains achievable. In addition, the IRS has allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.

Future claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units.

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.

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

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.

TheultimateoutcomeofsuchpendingorpotentiallitigationagainstGeorgia Powercannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementshereinorinNote3tothefinancialstatementsofGeorgia PowerinItem8ofthe Form 10-K,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

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of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

Georgia Power regularly evaluates its operations and costs. Primarily in response to changing customer expectations and payment patterns, including electronic payments and alternative payment locations, and on-going efforts to increase overall operating efficiencies, Georgia Power initiated cost containment activities throughout the enterprise in July 2016, including the announced closure of 104 local offices and an employee attrition plan affecting approximately 300 positions. Charges associated with the cost containment activities are not expected to have a material impact on Georgia Power's results of operations, financial position, or cash flows. The cost containment activities are expected to reduce operating costs in 2017.

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

Recently Issued Accounting Standards

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Georgia Power is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Georgia Power's balance sheet.

On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Georgia Power currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted and Georgia Power intends to adopt the ASU in the fourth quarter 2016. The adoption is not expected to have a material impact on the results of operations, financial position, or cash flows of Georgia Power.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power's financial condition remained stable at September 30, 2016. 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 $2.26 billion for the first nine months of 2016 compared to $2.16 billion for the corresponding period in 2015. The increase was primarily due to the timing of vendor payments. Net cash used for investing activities totaled $1.76 billion for the first nine months of 2016 compared to $1.39 billion for the corresponding period in 2015 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Net cash used for financing activities totaled $522 million for the first nine months of 2016 compared to $711 million in the corresponding period in 2015. The decrease in cash used for financing activities is primarily due to higher capital contributions received from Southern Company and senior note issuances, partially offset by higher common stock dividends and lower borrowings from the FFB for construction of Plant Vogtle Units 3 and 4. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first nine months of 2016 include an increase in property, plant, and equipment of $1.1 billion to comply with environmental standards and construction of generation, transmission, and distribution facilities and increases in current and deferred ARO liabilities of $638 million and other regulatory assets, deferred of $378 million primarily related to changes in ash pond closure strategy. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Residuals" herein for additional information regarding changes in ash pond closure strategy.

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 $458 million will be required through September 30, 2017 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

Georgia Power's construction program is currently estimated to total $2.6 billion for 2017, $2.7 billion for 2018, $2.3 billion for 2019, $2.2 billion for 2020, and $1.8 billion for 2021. These amounts include expenditures of approximately $0.6 billion for 2017, $0.7 billion for 2018, $0.4 billion for 2019, and $0.1 billion for 2020 to continue and complete construction of Plant Vogtle Units 3 and 4. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved 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; 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; 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 "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Sources of Capital

Except as described below with respect to the DOE loan guarantees, 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, 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 Georgia Power in Item 7 of the Form 10-K for additional information.

In addition, Georgia Power may make borrowings through a loan guarantee agreement (Loan Guarantee Agreement) between Georgia Power and the DOE, the proceeds of which 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 September 30, 2016 would allow for borrowings of up to $2.6 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.5 billion. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding the Loan Guarantee Agreement and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

As of September 30, 2016, Georgia Power's current liabilities exceeded current assets by $656 million primarily due to scheduled maturities of long-term debt. Georgia Power intends to utilize operating cash flows, as well as FFB borrowings, commercial paper, lines of credit, bank notes, and external securities issuances, as market conditions permit, and equity contributions from Southern Company to fund its short-term capital needs. Georgia Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.

At September 30, 2016, Georgia Power had approximately $47 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks at September 30, 2016 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. Georgia Power is currently in compliance with this covenant. This bank credit arrangement does not contain a material adverse change clause at the time of borrowing.

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

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

A portion of the unused credit with banks is allocated to provide liquidity support to Georgia Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2016 was approximately $868 million. In addition, at September 30, 2016, 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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.

Details of short-term borrowings were as follows:

	Short-term Debt at September 30, 2016				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	$	95	0.8	%	$	59	0.8	%	$	197

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016.

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

Credit Rating Risk

Georgia 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 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 September 30, 2016 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	93
Below BBB- and/or Baa3	$	1,222

Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. 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.

Financing Activities

In January 2016, $4.085 million aggregate principal amount of Savannah Economic Development Authority Pollution Control Revenue Bonds (Savannah Electric and Power Company Project), First Series 1993 matured.

In March 2016, Georgia Power issued $325 million aggregate principal amount of Series 2016A 3.25% Senior Notes due April 1, 2026 and $325 million aggregate principal amount of Series 2016B 2.40% Senior Notes due April 1, 2021. An amount equal to the proceeds from the Series 2016A 3.25% Senior Notes due April 1, 2026 will be allocated to eligible green expenditures, including financing of or investments in solar generating facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar or wind generating facilities. The proceeds from the Series 2016B 2.40% Senior Notes due April 1, 2021 were used to repay at maturity $250 million aggregate principal amount of Georgia Power's Series 2013B Floating Rate Senior Notes due March 15, 2016, to

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

repay a portion of Georgia Power's short-term indebtedness, and for general corporate purposes, including Georgia Power's continuous construction program.

In April 2016, Georgia Power's $250 million aggregate principal amount of Series 2011B 3.00% Senior Notes matured.

In June 2016, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $300 million at a 2.571% interest rate through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.

In August 2016, Georgia Power's $200 million aggregate principal amount of Series 2013C Floating Rate Senior Notes matured.

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

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GULF POWER COMPANY

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GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2016			2015			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	377		$	363		$	978		$	983
Wholesale revenues, non-affiliates	17			30			48			82
Wholesale revenues, affiliates	23			17			59			52
Other revenues	19			19			51			53
Total operating revenues	436			429			1,136			1,170
Operating Expenses:
Fuel	141			143			342			375
Purchased power, non-affiliates	33			26			95			76
Purchased power, affiliates	3			4			9			22
Other operations and maintenance	86			90			239			274
Depreciation and amortization	49			40			129			100
Taxes other than income taxes	34			35			93			91
Total operating expenses	346			338			907			938
Operating Income	90			91			229			232
Other Income and (Expense):
Interest expense, net of amounts capitalized	(11		)	(12		)	(36		)	(38		)
Other income (expense), net	(2		)	2			(4		)	8
Total other income and (expense)	(13		)	(10		)	(40		)	(30		)
Earnings Before Income Taxes	77			81			189			202
Income taxes	30			31			74			75
Net Income	47			50			115			127
Dividends on Preference Stock	2			2			7			7
Net Income After Dividends on Preference Stock	$	45		$	48		$	108		$	120

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2016		2015		2016			2015
	(in millions)				(in millions)
Net Income	$	47	$	50	$	115		$	127
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $-, $(3), and $-, respectively	—		—		(4		)	—
Total other comprehensive income (loss)	—		—		(4		)	—
Comprehensive Income	$	47	$	50	$	111		$	127

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

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GULF POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	115		$	127
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	134			105
Deferred income taxes	15			58
Other, net	(4		)	5
Changes in certain current assets and liabilities —
-Receivables	(9		)	18
-Fossil fuel stock	49			18
-Other current assets	3			32
-Accrued taxes	40			46
-Other current liabilities	30			2
Net cash provided from operating activities	373			411
Investing Activities:
Property additions	(106		)	(189		)
Cost of removal, net of salvage	(8		)	(9		)
Change in construction payables	(7		)	(29		)
Other investing activities	(6		)	(6		)
Net cash used for investing activities	(127		)	(233		)
Financing Activities:
Decrease in notes payable, net	(42		)	(34		)
Proceeds —
Common stock issued to parent	—			20
Pollution control revenue bonds	—			13
Redemptions and repurchases —
Pollution control revenue bonds	—			(13		)
Senior notes	(125		)	(60		)
Payment of common stock dividends	(90		)	(98		)
Other financing activities	6			(4		)
Net cash used for financing activities	(251		)	(176		)
Net Change in Cash and Cash Equivalents	(5		)	2
Cash and Cash Equivalents at Beginning of Period	74			39
Cash and Cash Equivalents at End of Period	$	69		$	41
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $- and $5 capitalized for 2016 and 2015, respectively)	$	29		$	27
Income taxes, net	14			(37		)
Noncash transactions — Accrued property additions at end of period	13			17

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

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GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2016			At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	69		$	74
Receivables —
Customer accounts receivable	94			76
Unbilled revenues	74			54
Under recovered regulatory clause revenues	2			20
Income taxes receivable, current	—			27
Other accounts and notes receivable	4			9
Affiliated	3			1
Accumulated provision for uncollectible accounts	(1		)	(1		)
Fossil fuel stock	59			108
Materials and supplies	56			56
Other regulatory assets, current	62			90
Other current assets	15			22
Total current assets	437			536
Property, Plant, and Equipment:
In service	5,073			5,045
Less accumulated provision for depreciation	1,387			1,296
Plant in service, net of depreciation	3,686			3,749
Other utility plant, net	—			62
Construction work in progress	64			48
Total property, plant, and equipment	3,750			3,859
Other Property and Investments	4			4
Deferred Charges and Other Assets:
Deferred charges related to income taxes	59			61
Other regulatory assets, deferred	507			427
Other deferred charges and assets	45			33
Total deferred charges and other assets	611			521
Total Assets	$	4,802		$	4,920

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

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GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	195		$	110
Notes payable	100			142
Accounts payable —
Affiliated	50			55
Other	41			44
Customer deposits	35			36
Accrued taxes —
Accrued income taxes	19			4
Other accrued taxes	34			9
Accrued interest	19			9
Accrued compensation	20			25
Deferred capacity expense, current	22			22
Other regulatory liabilities, current	28			22
Liabilities from risk management activities	30			49
Other current liabilities	41			40
Total current liabilities	634			567
Long-term Debt	989			1,193
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	904			893
Employee benefit obligations	125			129
Deferred capacity expense	125			141
Asset retirement obligations	119			113
Accrued environmental remediation	41			42
Other cost of removal obligations	248			233
Other regulatory liabilities, deferred	48			47
Other deferred credits and liabilities	41			60
Total deferred credits and other liabilities	1,651			1,658
Total Liabilities	3,274			3,418
Preference Stock	147			147
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — 5,642,717 shares	503			503
Paid-in capital	579			567
Retained earnings	303			285
Accumulated other comprehensive loss	(4		)	—
Total common stockholder's equity	1,381			1,355
Total Liabilities and Stockholder's Equity	$	4,802		$	4,920

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2016 vs. THIRD QUARTER 2015

AND

YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 2015

OVERVIEW

Gulf Power operates as a vertically integrated utility providing electricity 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 selling electricity. 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, increasingly stringent environmental standards, reliability, restoration following major storms, and fuel. 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.

Through 2015, long-term non-affiliate capacity sales from Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs) provided the majority of Gulf Power's wholesale earnings. The revenues from wholesale contracts covering 100% of this capacity represented 82% of wholesale capacity revenues in 2015. Following contract expirations at the end of 2015 and the end of May 2016, Gulf Power's remaining contracted sales from the unit cover approximately 24% of Gulf Power's ownership of the unit through 2019. The expiration of these contracts has had a material negative impact on Gulf Power's earnings in 2016. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as its existing wholesale contracts expire. As a result, on September 13, 2016, the Florida PSC instructed Gulf Power to file its monthly earnings surveillance reports both including and excluding its share of investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts.

On October 12, 2016, Gulf Power filed a petition (2016 Rate Case) with the Florida PSC requesting an increase in retail rates and charges of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 and a retail ROE of 11% compared to the current retail ROE of 10.25%. The recoverability of the costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 will be decided in this matter. The Florida PSC is expected to make a decision on the 2016 Rate Case in the second quarter 2017. Gulf Power has requested that the increase in base rates, if approved by the Florida PSC, become effective in July 2017.

On November 2, 2016, the Florida PSC approved Gulf Power's annual rate clause request for its cost recovery clause factors for 2017. The fuel and environmental factors include certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" herein for additional information.

The ultimate outcome of these matters cannot be determined at this time. However, if the recovery of Plant Scherer Unit 3 costs is not resolved through the 2016 Rate Case, it could continue to have a material negative impact on Gulf Power's earnings in future years until Gulf Power is able to find a suitable alternative related to this asset.

Gulf Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Gulf Power in Item 7 of the Form 10-K.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Net Income

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(3)	(6.3)	$(12)	(10.0)

Gulf Power's net income after dividends on preference stock for the third quarter 2016 was $45 million compared to $48 million for the corresponding period in 2015. The decrease was primarily due to lower non-affiliated wholesale capacity revenues and an increase in depreciation, partially offset by an increase in retail revenues primarily due to warmer weather and lower operations and maintenance expenses.

Gulf Power's net income after dividends on preference stock for year-to-date 2016 was $108 million compared to $120 million for the corresponding period in 2015. The decrease was primarily due to lower non-affiliated wholesale capacity revenues and an increase in depreciation, partially offset by lower operations and maintenance expenses.

Retail Revenues

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$14	3.9	$(5)	(0.5)

In the third quarter 2016, retail revenues were $377 million compared to $363 million for the corresponding period in 2015. For year-to-date 2016, retail revenues were $978 million compared to $983 million for the corresponding period in 2015.

Details of the changes in retail revenues were as follows:

	Third Quarter 2016					Year-to-Date 2016
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	363				$	983
Estimated change resulting from –
Rates and pricing	11			3.0		28			2.8
Sales growth (decline)	(1		)	(0.3	)	—			—
Weather	5			1.4		(3		)	(0.3	)
Fuel and other cost recovery	(1		)	(0.3	)	(30		)	(3.1	)
Retail – current year	$	377		3.8	%	$	978		(0.6	)%

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

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2016 when compared to the corresponding periods in 2015 primarily due to an increase in the environmental cost recovery clause rate, partially offset by a decrease in the energy conservation cost recovery clause rate, both effective in January 2016. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Cost Recovery Clauses" herein for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Revenues attributable to changes in sales decreased slightly in the third quarter 2016 when compared to the corresponding period in 2015. For the third quarter 2016, weather-adjusted KWH sales to residential and commercial customers decreased 1.9% and 0.5%, 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 increased 1.3% for the third quarter 2016 primarily due to decreased customer co-generation and changes in customers' operations.

Revenues attributable to changes in sales remained essentially flat year-to-date 2016 when compared to the corresponding period in 2015. Weather-adjusted KWH sales to residential and commercial customers decreased 0.4% and 1.0%, 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 increased 2.9% primarily due to decreased customer co-generation, partially offset by changes in customers' operations.

Fuel and other cost recovery revenues decreased in the third quarter 2016 when compared to the corresponding period in 2015, primarily due to lower recoverable costs under Gulf Power's environmental cost recovery clause, partially offset by higher recoverable costs under Gulf Power's energy conservation cost recovery clause. Fuel and other cost recovery revenues decreased year-to-date 2016 when compared to the corresponding period in 2015, primarily due to a decrease in fuel costs as a result of decreased generation and lower purchased power energy costs. Lower recoverable costs under Gulf Power's environmental cost recovery clause, partially offset by higher recoverable costs under Gulf Power's energy conservation cost recovery clause, also contributed to this decrease. 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.

Wholesale Revenues – Non-Affiliates

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(13)	(43.3)	$(34)	(41.5)

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

In the third quarter 2016, wholesale revenues from sales to non-affiliates were $17 million compared to $30 million for the corresponding period in 2015. For year-to-date 2016, wholesale revenues from sales to non-affiliates were $48 million compared to $82 million for the corresponding period in 2015. These decreases were primarily due to a 62.1% and 52.3% decrease in capacity revenues for the third quarter and year-to-date 2016, respectively, resulting from the expiration of Plant Scherer Unit 3 long-term sales agreements.

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Wholesale Revenues – Affiliates

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$6	35.3	$7	13.5

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

In the third quarter 2016, wholesale revenues from sales to affiliates were $23 million compared to $17 million for the corresponding period in 2015. The increase was primarily due to a 42.8% increase in KWH sales as a result of higher sales to the power pool due to greater Southern Company system load. For year-to-date 2016, wholesale revenues from sales to affiliates were $59 million compared to $52 million for the corresponding period in 2015. The increase was primarily due to a 33.7% increase in KWH sales resulting from lower planned unit outages for Gulf Power's generation resources.

Fuel and Purchased Power Expenses

	Third Quarter 2016 vs. Third Quarter 2015					Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	(2	)	(1.4	)	$	(33	)	(8.8	)
Purchased power – non-affiliates	7			26.9		19			25.0
Purchased power – affiliates	(1		)	(25.0	)	(13		)	(59.1	)
Total fuel and purchased power expenses	$	4				$	(27	)

In the third quarter 2016, total fuel and purchased power expenses were $177 million compared to $173 million for the corresponding period in 2015. The increase was primarily due to a $7 million net increase related to the volume of KWHs generated and purchased as a result of higher customer loads on Gulf Power's system, partially offset by a $3 million decrease in the average cost of fuel and purchased power.

For year-to-date 2016, total fuel and purchased power expenses were $446 million compared to $473 million for the corresponding period in 2015. The decrease was primarily the result of a $40 million decrease due to the lower average cost of fuel and purchased power, partially offset by a $13 million net increase related to the volume of KWHs purchased from 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:

	Third Quarter 2016	Third Quarter 2015	Year-to-Date 2016	Year-to-Date 2015
Total generation (in millions of KWHs)	2,775	2,839	6,654	7,435
Total purchased power(in millions of KWHs)	1,906	1,637	5,295	4,231
Sources of generation (percent) –
Coal	68	64	57	61
Gas	32	36	43	39
Cost of fuel, generated (in cents per net KWH) –
Coal	3.55	3.67	3.80	3.88
Gas	4.38	4.32	4.06	4.22
Average cost of fuel, generated(in cents per net KWH)	3.81	3.90	3.91	4.01
Average cost of purchased power (in cents per net KWH)(*)	3.79	3.83	3.51	4.12

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

Fuel

In the third quarter 2016, fuel expense was $141 million compared to $143 million for the corresponding period in 2015. The decrease was primarily due to a 12.9% decrease in the volume of KWHs generated by Gulf Power's gas-fired generation resources due to higher planned maintenance and a 2.3% decrease in the average cost of fuel. The decreases were partially offset by a 3.6% increase in the volume of KWHs generated by Gulf Power's coal-fired generation resources.

For year-to-date 2016, fuel expense was $342 million compared to $375 million for the corresponding period in 2015. The decrease was primarily due to a 17.4% decrease in the volume of KWHs generated by Gulf Power's coal-fired generation resources due to the lower cost of gas-fired resources and a 2.5% decrease in the average cost of fuel. The decreases were partially offset by a 0.5% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.

Purchased Power – Non-Affiliates

In the third quarter 2016, purchased power expense from non-affiliates was $33 million compared to $26 million for the corresponding period in 2015. The increase was primarily due to a 26.5% increase in the volume of KWHs purchased due to the availability of lower cost energy, partially offset by a 6.6% decrease in the average cost per KWH purchased due to lower energy costs from gas-fired resources.

For year-to-date 2016, purchased power expense from non-affiliates was $95 million compared to $76 million for the corresponding period in 2015. The increase was primarily due to a 46.6% increase in the volume of KWHs purchased due to the availability of lower cost energy, partially offset by a 21.0% decrease in the average cost per KWH purchased due to lower energy costs from gas-fired resources.

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

Purchased Power – Affiliates

In the third quarter 2016, purchased power expense from affiliates was $3 million compared to $4 million for the corresponding period in 2015. The decrease was primarily due to a 54.9% decrease in the volume of KWHs purchased due to an increase in coal-fired Gulf Power generation committed to serve territorial loads, partially offset by a 67.4% increase in the average cost per KWH purchased due to higher power pool interchange rates.

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For year-to-date 2016, purchased power expense from affiliates was $9 million compared to $22 million for the corresponding period in 2015. The decrease was primarily due to a 54.6% decrease in the volume of KWHs purchased due to lower territorial loads and a 10.8% decrease in the average cost per KWH purchased due to lower power pool interchange rates as a result of lower fuel prices and lower off-peak energy prices of renewable market resources.

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

Other Operations and Maintenance Expenses

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(4)	(4.4)	$(35)	(12.8)

In the third quarter 2016, other operations and maintenance expenses were $86 million compared to $90 million for the corresponding period in 2015. For year-to-date 2016, other operations and maintenance expenses were $239 million compared to $274 million for the corresponding period in 2015. These decreases were primarily due to decreases in routine and planned maintenance expenses at generating facilities and lower expenses related to marketing programs.

Expenses from marketing programs do not have a significant impact on earnings since they are generally offset by energy conservation revenues through Gulf Power's energy conservation cost recovery clause.

Depreciation and Amortization

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$9	22.5	$29	29.0

In the third quarter 2016, depreciation and amortization was $49 million compared to $40 million for the corresponding period in 2015. For year-to-date 2016, depreciation and amortization was $129 million compared to $100 million for the corresponding period in 2015. The increases were primarily due to $7 million and $20 million less of a reduction in depreciation, as authorized in a settlement agreement approved by the Florida PSC in 2013 (2013 Rate Case Settlement Agreement), in the third quarter and year-to-date 2016, respectively, compared to the corresponding periods in 2015. In the third quarter 2016, and in accordance with the 2013 Rate Case Settlement Agreement, Gulf Power reversed reductions previously recorded to depreciation. As a result, for the first nine months of 2016, the net reduction in depreciation was zero. Also contributing to the increases were property additions at generation, transmission, and distribution facilities placed in service in 2015.

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 "Retail Regulatory Matters – Gulf Power – Retail Base Rate Cases" herein for additional information.

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Other Income (Expense), Net

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(4)	N/M	$(12)	N/M

N/M - Not meaningful

In the third quarter 2016, other income (expense), net was $(2) million compared to $2 million for the corresponding period in 2015. For year-to-date 2016, other income (expense), net was $(4) million compared to $8 million for the corresponding period in 2015. These changes were primarily due to lower AFUDC related to environmental control projects at generating facilities and transmission projects placed in service in 2015.

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 selling electricity. 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. Future earnings in the near term will depend, in part, upon maintaining and growing sales which are subject to a number of 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, the rate of economic growth or decline in Gulf Power's service territory, the successful remarketing of wholesale capacity as current contracts expire, and the outcome of the 2016 Rate Case related to Gulf Power's ownership of Plant Scherer Unit 3. 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. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in retail rates or through long-term wholesale agreements on a timely basis or through market-based contracts. The State of Florida has statutory provisions that allow a utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Gulf Power's current long-term wholesale agreements contain provisions that permit charging the customer with costs incurred as a result of changes in environmental laws and regulations. The full impact of any such regulatory or legislative 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.

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Environmental Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA's final MATS rule, regional haze regulations, fine particulate matter National Ambient Air Quality Standards (NAAQS), and the Cross State Air Pollution Rule (CSAPR).

On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion, the EPA published its supplemental finding regarding consideration of costs in support of the MATS rule. This finding does not impact MATS rule compliance requirements, costs, or deadlines, and all Gulf Power units that are subject to the MATS rule completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.

Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and cannot be determined at this time.

On September 6, 2016, the EPA designated all remaining areas within Gulf Power's service territory as attainment for the 2012 annual fine particulate matter NAAQS.

On October 26, 2016, the EPA published a final rule that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Mississippi and removing Florida from the CSAPR program. The ultimate impact of this rule will depend on the outcome of any legal challenges and implementation at the state level and 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.

Gulf Power's wholesale business consists of two types of agreements. The first type, referred to as requirements service, provides that Gulf Power serves the customer's capacity and energy requirements from Gulf Power resources. The second type, referred to as a unit sale, is a wholesale customer purchase from a dedicated generating plant unit where a portion of that unit is reserved for the customer. These agreements are associated with Gulf Power's ownership of Plant Scherer Unit 3 and consist of both capacity and energy sales. Through 2015, long-term non-affiliate capacity sales from Gulf Power's ownership of the unit provided the majority of Gulf Power's wholesale earnings. The revenues from wholesale contracts covering 100% of this capacity represented 82% of wholesale capacity revenues in 2015. Following contract expirations at the end of 2015 and the end of May 2016, Gulf Power's remaining contracted sales from the unit cover approximately 24% of Gulf Power's ownership of the unit through 2019. The expiration of these contracts has had a material negative impact on Gulf Power's earnings in 2016. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as its existing wholesale contracts expire. As a result, on September 13, 2016, the Florida PSC instructed Gulf Power to file its monthly earnings surveillance reports both including and excluding its share of investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts. See "Retail Base Rate Cases" and "Cost Recovery Clauses" herein for additional information.

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The ultimate outcome of this matter cannot be determined at this time. However, if the recovery of Plant Scherer Unit 3 costs is not resolved through the 2016 Rate Case, it could continue to have a material negative impact on Gulf Power's earnings in future years until Gulf Power is able to find a suitable alternative related to this asset.

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. In the third quarter 2016 and in accordance with the 2013 Rate Case Settlement Agreement, Gulf Power reversed reductions previously recorded to depreciation. As a result, for the first nine months of 2016, the net reduction in depreciation was zero.

On October 12, 2016, Gulf Power filed the 2016 Rate Case with the Florida PSC requesting an increase in retail rates and charges of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 and a retail ROE of 11% compared to the current retail ROE of 10.25%. The recoverability of the costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 will be decided in this matter. The Florida PSC is expected to make a decision on the 2016 Rate Case in the second quarter 2017. Gulf Power has requested that the increase in base rates, if approved by the Florida PSC, become effective in July 2017. The ultimate outcome of this matter cannot be determined at this time.

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.

On November 2, 2016, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2017. The net effect of the approved changes is a $41 million decrease in annual revenues for 2017. In general, the decreased revenues will not have a significant impact on net income since most of the revenues will be offset by lower expenses. However, certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 were included in the environmental clause rate, which will have an impact of approximately $11 million and $14 million of additional revenue in 2016 and 2017, respectively. The final disposition of these costs, and the related impact on rates, is subject to the Florida PSC's ultimate ruling on whether costs associated with Plant Scherer Unit 3 are recoverable from retail customers, which is expected to be decided by the Florida PSC in the 2016 Rate Case as discussed previously. The ultimate outcome of this matter cannot be determined at this time.

Renewables

The Florida PSC issued a final approval order on Gulf Power's Community Solar Pilot Program on April 15, 2016. The program will offer all Gulf Power customers an opportunity to voluntarily contribute to the construction and operation of a solar photovoltaic facility with electric generating capacity of up to 1 MW through annual subscriptions. The energy generated from the solar facility is expected to provide power to all of Gulf Power's customers.

On October 11, 2016, the Florida PSC preliminarily approved an energy purchase agreement for up to 94 MWs of wind generation in central Oklahoma. Purchases under this agreement will be for energy only and will be recovered through Gulf Power's fuel cost recovery clause.

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Other Matters

As a result of the cost to comply with environmental regulations imposed by the EPA, Gulf Power retired its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) on March 31, 2016. Gulf Power filed a petition with the Florida PSC requesting permission to recover the remaining net book value of Plant Smith Units 1 and 2 and the remaining materials and supplies associated with these units as of the retirement date. In connection with this request, Gulf Power reclassified approximately $63 million to a regulatory asset, including the remaining net book value of the units and the associated materials and supplies. On August 29, 2016, the Florida PSC approved Gulf Power's request to create a regulatory asset and defer the recovery over a period to be decided in the 2016 Rate Case.

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.

TheultimateoutcomeofsuchpendingorpotentiallitigationagainstGulf Powercannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementshereinorinNote3tothefinancialstatementsofGulf PowerinItem8ofthe Form 10-K,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Gulf Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Recently Issued Accounting Standards

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Gulf Power is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Gulf Power's balance sheet.

On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most

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significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Gulf Power currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted and Gulf Power intends to adopt the ASU in the fourth quarter 2016. The adoption is not expected to have a material impact on the results of operations, financial position, or cash flows of Gulf Power.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Gulf Power in Item 7 of the Form 10-K for additional information. Gulf Power's financial condition remained stable at September 30, 2016. 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 $373 million for the first nine months of 2016 compared to $411 million for the corresponding period in 2015. The $38 million decrease in net cash was primarily due to a decrease in wholesale capacity revenue, partially offset by a federal income tax refund. Net cash used for investing activities totaled $127 million in the first nine months of 2016 primarily due to property additions to utility plant. Net cash used for financing activities totaled $251 million for the first nine months of 2016 primarily due to the redemption of long-term debt, payment of common stock dividends, and a decrease in notes payable. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first nine months of 2016 include decreases of $125 million in long-term debt due to a redemption and $109 million in net property, plant, and equipment primarily due to the retirement of Plant Smith Units 1 and 2 and an increase in accumulated provision for depreciation primarily due to environmental control projects at generating facilities and transmission projects placed in service in 2015.

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 $195 million will be required through September 30, 2017 to fund maturities of long-term debt. See "Financing Activities" herein for additional information.

Gulf Power's construction program is currently estimated to total $0.2 billion for 2017, $0.2 billion for 2018, $0.2 billion for 2019, $0.3 billion for 2020, and $0.3 billion for 2021. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved 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 the expected environmental compliance programs; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the

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cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

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

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

At September 30, 2016, Gulf Power had approximately $69 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2016 were as follows:

Expires										Executable Term Loans				Due Within One Year
2016		2017		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)						(in millions)				(in millions)				(in millions)
$	50	$	65	$	165	$	280	$	280	$	45	$	—	$	45	$	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) that are restricted only to the indebtedness 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. Gulf Power is currently 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 September 30, 2016 was approximately $82 million. In addition, at September 30, 2016, Gulf Power had approximately $21 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 company under these arrangements are several and there is no cross-affiliate credit support.

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Details of short-term borrowings were as follows:

	Short-term Debt at September 30, 2016				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	$	—	—	%	$	35	0.8	%	$	88
Short-term bank debt	100		1.3	%	100		1.2	%	100
Total	$	100	1.3	%	$	135	1.1	%

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016.

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

Gulf 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 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 September 30, 2016 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	192
Below BBB- and/or Baa3	$	630

Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. 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.

Market Price Risk

Gulf Power's market risk exposure relative to interest rate changes for the third quarter and year-to-date 2016 has not changed materially compared to the December 31, 2015 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.

For an in-depth 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. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as its existing wholesale contracts expire. As a result, on September 13, 2016, the Florida PSC instructed Gulf Power to file its monthly earnings surveillance

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reports both including and excluding its share of investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts. The recoverability of the costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 is expected to be decided in the 2016 Rate Case. The ultimate outcome of this matter cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.

Financing Activities

In May 2016, Gulf Power redeemed $125 million aggregate principal amount of its Series 2011A 5.75% Senior Notes due June 1, 2051.

Also in May 2016, Gulf Power entered into an 11-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $100 million aggregate principal amount and the proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes.

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

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MISSISSIPPI POWER COMPANY

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CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2016			2015			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	263		$	244		$	652		$	601
Wholesale revenues, non-affiliates	78			76			198			216
Wholesale revenues, affiliates	7			18			23			63
Other revenues	4			3			12			13
Total operating revenues	352			341			885			893
Operating Expenses:
Fuel	112			130			268			359
Purchased power, non-affiliates	3			1			4			5
Purchased power, affiliates	5			1			14			6
Other operations and maintenance	74			63			211			206
Depreciation and amortization	30			38			114			95
Taxes other than income taxes	31			24			81			71
Estimated loss on Kemper IGCC	88			150			222			182
Total operating expenses	343			407			914			924
Operating Income (Loss)	9			(66		)	(29		)	(31		)
Other Income and (Expense):
Allowance for equity funds used during construction	31			29			90			82
Interest expense, net of amounts capitalized	(15		)	(13		)	(46		)	6
Other income (expense), net	(1		)	(2		)	(4		)	(5		)
Total other income and (expense)	15			14			40			83
Earnings (Loss) Before Income Taxes	24			(52		)	11			52
Income taxes (benefit)	(2		)	(31		)	(29		)	(11		)
Net Income (Loss)	26			(21		)	40			63
Dividends on Preferred Stock	—			—			1			1
Net Income (Loss) After Dividends on Preferred Stock	$	26		$	(21	)	$	39		$	62

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2016		2015			2016			2015
	(in millions)					(in millions)
Net Income (Loss)	$	26	$	(21	)	$	40		$	63
Other comprehensive income (loss)
Qualifying hedges:
Changes in fair value, net of tax of $-, $-, $-, and $-, respectively	—		—			(1		)	—
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $-, and $-, respectively	—		—			1			1
Total other comprehensive income (loss)	—		—			—			1
Comprehensive Income (Loss)	$	26	$	(21	)	$	40		$	64

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

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CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	40		$	63
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	115			94
Deferred income taxes	34			518
Investment tax credits	—			25
Allowance for equity funds used during construction	(90		)	(82		)
Regulatory assets associated with Kemper IGCC	(13		)	(56		)
Estimated loss on Kemper IGCC	222			182
Income taxes receivable, non-current	—			(544		)
Other, net	12			7
Changes in certain current assets and liabilities —
-Prepaid income taxes	38			(1		)
-Other current assets	7			4
-Accounts payable	5			(32		)
-Accrued taxes	95			24
-Over recovered regulatory clause revenues	(20		)	59
-Mirror CWIP	—			99
-Customer liability associated with Kemper refunds	(73		)	—
-Other current liabilities	—			(11		)
Net cash provided from operating activities	372			349
Investing Activities:
Property additions	(592		)	(626		)
Construction payables	(25		)	(31		)
Capital grant proceeds	137			—
Other investing activities	(29		)	(29		)
Net cash used for investing activities	(509		)	(686		)
Financing Activities:
Increase in notes payable, net	—			475
Proceeds —
Capital contributions from parent company	227			153
Long-term debt to parent company	200			—
Other long-term debt	900			—
Short-term borrowings	—			30
Redemptions —
Short-term borrowings	(475		)	(5		)
Long-term debt to parent company	(225		)	—
Other long-term debt	(425		)	(350		)
Other financing activities	(4		)	(3		)
Net cash provided from financing activities	198			300
Net Change in Cash and Cash Equivalents	61			(37		)
Cash and Cash Equivalents at Beginning of Period	98			133
Cash and Cash Equivalents at End of Period	$	159		$	96
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $72 and $58, net of $36 and $52 capitalized for 2016 and 2015, respectively)	$	36		$	6
Income taxes, net	(231		)	(55		)
Noncash transactions —
Accrued property additions at end of period	80			83
Issuance of promissory note to parent related to repayment of     interest-bearing refundable deposits and accrued interest	—			301

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

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CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2016		At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	159	$	98
Receivables —
Customer accounts receivable	39		26
Unbilled revenues	47		36
Income taxes receivable, current	—		20
Other accounts and notes receivable	6		10
Affiliated	17		20
Fossil fuel stock	96		104
Materials and supplies	75		75
Other regulatory assets, current	118		95
Prepaid income taxes	—		39
Other current assets	10		8
Total current assets	567		531
Property, Plant, and Equipment:
In service	4,835		4,886
Less accumulated provision for depreciation	1,259		1,262
Plant in service, net of depreciation	3,576		3,624
Construction work in progress	2,525		2,254
Total property, plant, and equipment	6,101		5,878
Other Property and Investments	12		11
Deferred Charges and Other Assets:
Deferred charges related to income taxes	330		290
Other regulatory assets, deferred	510		525
Income taxes receivable, non-current	544		544
Other deferred charges and assets	101		61
Total deferred charges and other assets	1,485		1,420
Total Assets	$	8,165	$	7,840

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

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CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	343		$	728
Notes payable	25			500
Accounts payable —
Affiliated	92			85
Other	126			135
Customer deposits	16			16
Accrued taxes —
Accrued income taxes	110			—
Other accrued taxes	75			85
Accrued interest	20			18
Accrued compensation	21			26
Asset retirement obligations, current	36			22
Over recovered regulatory clause liabilities	76			96
Customer liability associated with Kemper refunds	1			73
Other current liabilities	37			52
Total current liabilities	978			1,836
Long-term Debt:
Long-term debt, affiliated	551			576
Long-term debt, non-affiliated	2,161			1,310
Total Long-term Debt	2,712			1,886
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	823			762
Deferred credits related to income taxes	7			8
Employee benefit obligations	146			153
Asset retirement obligations, deferred	154			154
Unrecognized tax benefits	382			368
Other cost of removal obligations	172			165
Other regulatory liabilities, deferred	76			71
Other deferred credits and liabilities	54			45
Total deferred credits and other liabilities	1,814			1,726
Total Liabilities	5,504			5,448
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	3,124			2,893
Accumulated deficit	(528		)	(566		)
Accumulated other comprehensive loss	(6		)	(6		)
Total common stockholder's equity	2,628			2,359
Total Liabilities and Stockholder's Equity	$	8,165		$	7,840

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

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THIRD QUARTER 2016 vs. THIRD QUARTER 2015

AND

YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 2015

OVERVIEW

Mississippi Power operates as a vertically integrated utility providing electricity 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 selling electricity. 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 major construction projects, primarily the Kemper IGCC and the Plant Daniel scrubber project, projected long-term demand growth, reliability, fuel, and increasingly stringent environmental standards, as well as ongoing capital expenditures required for maintenance. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.

In 2010, the Mississippi PSC issued a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC established by the Mississippi PSC was $2.4 billion with 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). 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.

Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014 and continues to progress towards completing the remainder of the Kemper IGCC, including the gasifiers and the gas clean-up facilities. The in-service date for the remainder of the Kemper IGCC is currently expected to occur by December 31, 2016. The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." On October 11, 2016, the Kemper IGCC began testing using clean syngas from gasifier "A" and the related gas clean-up systems to produce electricity. On November 2, 2016, Mississippi Power determined a maintenance outage of gasifier "A" is needed to make improvements to the ash removal systems. The remaining schedule reflects the time expected to achieve production of electricity using gasifier "B," complete gasifier "A" outage activities, and resume electricity production using gasifier "A," as well as to complete the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.

Mississippi Power's current cost estimate for the Kemper IGCC in total is approximately $6.82 billion, which includes approximately $5.52 billion of costs subject to the construction cost cap and is net of the Additional DOE Grants. 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 totaling $88 million ($54 million after tax) in the third quarter 2016 and a total of $222 million ($137 million after tax) for the nine months ended September 30, 2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.63 billion ($1.63 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2016.

In addition, during the start-up and commissioning process, Mississippi Power is identifying potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If

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completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. The related potential costs 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 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.

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 Kemper IGCC assets previously placed in service. On July 27, 2016, the Mississippi Supreme Court (Court) dismissed Greenleaf CO₂ Solutions, LLC’s (Greenleaf) motion for reconsideration of its previous decision to dismiss Greenleaf's appeal of the In-Service Asset Rate Order.

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 proceeding 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 following the start of commercial operations. Certain costs, including operations and maintenance, are materially higher than the amounts presented in the CPCN proceedings. 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. Mississippi Power expects the Mississippi PSC to address these issues in connection with its next rate request.

Mississippi Power anticipates that it will incur additional expenses in excess of current rates associated with operating the Kemper IGCC after it is placed in service until the Kemper IGCC cost recovery approach is finalized, which are expected to be material. Mississippi Power expects to request authority from the Mississippi PSC and 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. Mississippi Power is required to file its next rate request with the Mississippi PSC related to cost recovery for the Kemper IGCC by June 3, 2017. The ultimate outcome of these matters cannot be determined at this time.

Southern Company and Mississippi Power are defendants in two lawsuits that allege improper disclosure of important facts about the Kemper IGCC. While Mississippi Power believes that these lawsuits are without merit, an adverse outcome could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. In addition, 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.

For additional information on the Kemper IGCC, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and 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.

As of September 30, 2016, Mississippi Power's current liabilities exceeded current assets by approximately $411 million primarily due to the $300 million in senior notes which matured on October 15, 2016, as well as $65 million in short-term debt. In addition, if the Kemper IGCC does not go into service by December 31, 2016, Mississippi Power would have to repay approximately $250 million of tax benefits received as a result of quarterly income tax estimates through September 30, 2016.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Mississippi Power continues to focus on several key performance indicators, including the construction, start-up, and rate recovery of the Kemper IGCC. 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 return. In addition to the PEP performance indicators, Mississippi Power focuses on other performance measures, including broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Mississippi Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$47	N/M	$(23)	(37.1)

N/M - Not meaningful

Mississippi Power's net income after dividends on preferred stock for the third quarter 2016 was $26 million compared to a net loss of $21 million for the corresponding period in 2015. The increase was primarily related to lower pre-tax charges of $88 million ($54 million after tax) in the third quarter 2016 compared to pre-tax charges of $150 million ($93 million after tax) in the third quarter 2015 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 increase in net income was also due to an increase in retail revenues and a decrease in depreciation and amortization, partially offset by an increase in other operations and maintenance expenses.

For year-to-date 2016, net income after dividends on preferred stock was $39 million compared to $62 million for the corresponding period in 2015. The decrease was primarily related to a decrease in interest on deposits in 2015 resulting from the termination of an asset purchase agreement between Mississippi Power and SMEPA in May 2015, higher depreciation and amortization, and higher pre-tax charges of $222 million ($137 million after tax) in 2016 compared to pre-tax charges of $182 million ($112 million after tax) in 2015 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 retail revenues.

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

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$19	7.8	$51	8.5

In the third quarter 2016, retail revenues were $263 million compared to $244 million for the corresponding period in 2015. For year-to-date 2016, retail revenues were $652 million compared to $601 million for the corresponding period in 2015.

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Details of the changes in retail revenues were as follows:

	Third Quarter 2016					Year-to-Date 2016
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	244				$	601
Estimated change resulting from –
Rates and pricing	8			3.3		66			11.0
Sales growth (decline)	(3		)	(1.3	)	(2		)	(0.3	)
Weather	7			2.9		5			0.8
Fuel and other cost recovery	7			2.9		(18		)	(3.0	)
Retail – current year	$	263		7.8	%	$	652		8.5	%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2016 when compared to the corresponding periods in 2015, primarily due to the implementation of rates for certain Kemper IGCC in-service assets. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" 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.

Revenues attributable to changes in sales decreased in the third quarter 2016 when compared to the corresponding period in 2015. Weather-adjusted KWH sales to residential and commercial customers decreased 6.7% and 0.9%, respectively, in the third quarter 2016 due to decreased customer usage primarily resulting from efficiency improvements in residential appliances and lighting, partially offset by customer growth. KWH sales to industrial customers decreased 1.7% in the third quarter 2016 primarily due to an unplanned outage by a large customer.

Revenues attributable to changes in sales decreased for year-to-date 2016 when compared to the corresponding period in 2015. Weather-adjusted KWH sales to residential and commercial customers decreased 2.6% and 1.5%, respectively, due to decreased customer usage primarily resulting from efficiency improvements in residential appliances and lighting, partially offset by customer growth. KWH sales to industrial customers decreased 0.7% primarily due to an unplanned outage by a large customer.

In the first quarter 2015, Mississippi Power updated the methodology to estimate the unbilled revenue allocation among customer classes. This change did not have a significant impact on net income. The KWH sales variances discussed above reflect an adjustment to the estimated allocation of Mississippi Power's unbilled first quarter 2015 KWH sales among customer classes that is consistent with the actual allocation in 2016. Without this adjustment, year-to-date 2016 weather-adjusted residential KWH sales decreased 0.8%, weather-adjusted KWH sales to commercial customers increased 0.6%, and KWH sales to industrial customers were relatively flat as compared to the corresponding period in 2015.

Fuel and other cost recovery revenues increased in the third quarter 2016 when compared to the corresponding period in 2015, primarily as a result of revised ECO Plan rates which became effective with the first billing cycle for September 2016, partially offset by lower recoverable fuel costs. Fuel and other cost recovery revenues decreased for year-to-date 2016 when compared to the corresponding period in 2015, primarily as a result of lower recoverable fuel costs, partially offset by revised ECO Plan rates which became effective with the first billing cycle for September 2016. 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.

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Wholesale Revenues – Non-Affiliates

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$2	2.6	$(18)	(8.3)

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

For year-to-date 2016, wholesale revenues from sales to non-affiliates were $198 million compared to $216 million for the corresponding period in 2015. The decrease was primarily due to a $16 million decrease in energy revenues primarily resulting from lower natural gas prices and decreased usage primarily resulting from milder weather.

Wholesale Revenues – Affiliates

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(11)	(61.1)	$(40)	(63.5)

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

In the third quarter 2016, wholesale revenues from sales to affiliates were $7 million compared to $18 million for the corresponding period in 2015. The decrease was due to a decrease in KWH sales primarily due to availability of lower cost alternatives.

For year-to-date 2016, wholesale revenues from sales to affiliates were $23 million compared to $63 million for the corresponding period in 2015. The decrease was due to a $35 million decrease in KWH sales primarily due to availability of lower cost alternatives and a $5 million decrease associated with lower natural gas prices.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses

	Third Quarter 2016 vs. Third Quarter 2015				Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(18	)	(13.8)	$	(91	)	(25.3)
Purchased power – non-affiliates	2			N/M	(1		)	(20.0)
Purchased power – affiliates	4			N/M	8			N/M
Total fuel and purchased power expenses	$	(12	)		$	(84	)

N/M - Not meaningful

In the third quarter 2016, total fuel and purchased power expenses were $120 million compared to $132 million for the corresponding period in 2015. The decrease was primarily due to a net decrease in the volume of KWHs generated and purchased primarily due to a decrease in non-territorial sales.

For year-to-date 2016, total fuel and purchased power expenses were $286 million compared to $370 million for the corresponding period in 2015. The decrease was due to a $49 million net decrease in the volume of KWHs generated and purchased primarily due to a decrease in non-territorial sales and milder weather and a $35 million decrease due to lower natural gas prices.

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:

	Third Quarter 2016	Third Quarter 2015	Year-to-Date 2016	Year-to-Date 2015
Total generation (in millions of KWHs)	4,255	4,681	11,570	13,136
Total purchased power (in millions of KWHs)	288	121	877	427
Sources of generation (percent) –
Coal	10	19	9	20
Gas	90	81	91	80
Cost of fuel, generated (in cents per net KWH)–
Coal	4.02	3.81	4.09	3.70
Gas	2.64	2.72	2.34	2.70
Average cost of fuel, generated (in cents per net KWH)	2.79	2.93	2.50	2.91
Average cost of purchased power (in cents per net KWH)	2.59	2.21	2.04	2.42

Fuel

In the third quarter 2016, fuel expense was $112 million compared to $130 million for the corresponding period in 2015. The decrease was due to a 10.2% decrease in the volume of KWHs generated primarily as a result of lower wholesale sales and a 4.8% decrease in the average cost of fuel per KWH generated primarily due to a 2.7% lower cost of natural gas.

For year-to-date 2016, total fuel expense was $268 million compared to $359 million for the corresponding period in 2015. The decrease was due to a 12.9% decrease in the volume of KWHs generated primarily as a result of lower wholesale sales and a 14.2% decrease in the average cost of fuel per KWH generated primarily due to a 13.6% lower cost of natural gas.

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Purchased Power - Non-Affiliates

For year-to-date 2016, purchased power expense from non-affiliates was $4 million compared to $5 million for the corresponding period in 2015. The decrease was primarily due to a 43.1% decrease in the average cost per KWH purchased due to lower energy costs from available gas-fired resources, partially offset by a 49.0% increase in the volume of KWHs purchased due to the availability of lower cost energy.

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

Purchased Power - Affiliates

In the third quarter 2016, purchased power expense from affiliates was $5 million compared to $1 million for the corresponding period in 2015. The increase was primarily due to a 234.7% increase in the volume of KWHs purchased due to the availability of lower cost energy as compared to self-generation fuel cost and a 9.9% increase in the average cost per KWH purchased due to higher power pool interchange rates associated with higher natural gas prices.

For year-to-date 2016, purchased power expense from affiliates was $14 million compared to $6 million for the corresponding period in 2015. The increase was primarily due to a 163.8% 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 5.9% decrease in the average cost per KWH purchased due to lower power pool interchange rates 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.

Other Operations and Maintenance Expenses

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$11	17.5	$5	2.4

In the third quarter 2016, other operations and maintenance expenses were $74 million compared to $63 million for the corresponding period in 2015. The increase was primarily due to a $7 million increase in maintenance expenses related to the combined cycle and the associated common facilities portion of the Kemper IGCC that Mississippi Power began recognizing in connection with interim rates associated with the Kemper IGCC in-service assets implemented in September 2015 and a $4 million increase in transmission and distribution overhead line maintenance and vegetation management expenses.

For year-to-date 2016, other operations and maintenance expenses were $211 million compared to $206 million for the corresponding period in 2015. The increase was primarily due to a $23 million increase in maintenance expenses related to the combined cycle and the associated common facilities portion of the Kemper IGCC that Mississippi Power began recognizing in connection with interim rates associated with the Kemper IGCC in-service assets implemented in September 2015, partially offset by a $15 million decrease in generation outage costs and a $4 million decrease primarily related to pension costs.

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. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

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Depreciation and Amortization

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(8)	(21.1)	$19	20.0

In the third quarter 2016, depreciation and amortization was $30 million compared to $38 million for the corresponding period in 2015. The decrease was primarily due to a $17 million deferral associated with the implementation of revised ECO Plan rates with the first billing cycle for September 2016, partially offset by an increase in depreciation and amortization of $9 million primarily related to the In-Service Asset Rate Order, ECO Plan, MATS rule compliance, and additional plant in service assets.

For year-to-date 2016, depreciation and amortization was $114 million compared to $95 million for the corresponding period in 2015. The increase was primarily due to additional regulatory asset amortization of $16 million related to the In-Service Asset Rate Order, ECO Plan, and MATS rule compliance, $12 million primarily due to Kemper IGCC deferrals, and $8 million of depreciation for additional plant in service assets, primarily the Plant Daniel scrubbers. These increases were partially offset by a $17 million deferral associated with the implementation of revised ECO Plan rates with the first billing cycle for September 2016.

See Note 1 to the financial statements of Mississippi Power under "Depreciation, Depletion, and Amortization" in Item 8 of the Form 10-K for additional information. Also, 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 "Retail Regulatory Matters – Mississippi Power – Environmental Compliance Overview Plan" and "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" and " – Regulatory Assets and Liabilities" herein for additional information.

Taxes Other Than Income Taxes

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$7	29.2	$10	14.1

In the third quarter 2016, taxes other than income taxes were $31 million compared to $24 million for the corresponding period in 2015. For year-to-date 2016, taxes other than income taxes were $81 million compared to $71 million for the corresponding period in 2015. The increases were primarily due to increases in ad valorem taxes of $4 million and $6 million for the third quarter and year-to-date 2016, respectively, due to an increase in the assessed value of property as well as increases in franchise taxes of $3 million and $4 million for the third quarter and year-to-date 2016, respectively.

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

Estimated Loss on Kemper IGCC

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(62)	(41.3)	$40	22.0

In the third quarters of 2016 and 2015, estimated probable losses on the Kemper IGCC of $88 million and $150 million, respectively, were recorded at Mississippi Power. For year-to-date 2016 and year-to-date 2015, estimated probable losses on the Kemper IGCC of $222 million and $182 million, respectively, were recorded at Mississippi Power. These losses reflect revisions of estimated costs expected to be incurred on the construction of the Kemper

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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

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$2	6.9	$8	9.8

In the third quarter of 2016, AFUDC equity was $31 million compared to $29 million for the corresponding period in 2015. For year-to-date 2016, AFUDC equity was $90 million compared to $82 million for the corresponding period in 2015. The increases were driven by a higher AFUDC rate and an increase in Kemper IGCC CWIP subject to AFUDC, partially offset by placing the Plant Daniel scrubbers in service in November 2015. 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.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$2	15.4	$52	N/M

N/M - Not meaningful

In the third quarter 2016, interest expense, net of amounts capitalized was $15 million compared to $13 million for the corresponding period in 2015. The increase was related to additional long-term debt and a decrease in amounts capitalized, partially offset by a decrease in interest accrued on the Mirror CWIP liability prior to refund.

For year-to-date 2016, interest expense, net of amounts capitalized was $46 million compared to $(6) million for the corresponding period in 2015. The increase was primarily due to a $31 million decrease in interest on deposits in 2015 resulting from the termination of an asset purchase agreement between Mississippi Power and SMEPA in May 2015. In addition, the increase was related to additional long-term debt and a decrease in amounts capitalized, partially offset by a decrease in interest accrued on the Mirror CWIP liability prior to refund.

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 on the Mirror CWIP refund.

Income Taxes (Benefit)

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$29	93.5	$(18)	N/M

N/M - Not meaningful

In the third quarter 2016, income tax benefit was $(2) million compared to $(31) million for the corresponding period in 2015. The change was primarily due to the reduction in the estimated probable losses on construction of the Kemper IGCC.

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For year-to-date 2016, income tax benefit was $(29) million compared to $(11) million for the corresponding period in 2015. 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 selling electricity. These factors include Mississippi Power's ability to recover its prudently-incurred costs 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, as well as other ongoing construction projects. Future earnings in the near term will depend, in part, upon maintaining and growing sales which are subject to a number of 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. 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 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 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

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's final MATS rule, regional haze regulations, and the Cross State Air Pollution Rule (CSAPR).

On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion, the EPA published its supplemental finding regarding consideration of costs in support of the MATS rule. This finding does not impact MATS rule compliance requirements, costs, or deadlines, and all Mississippi Power units that are subject to the MATS rule completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.

Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and cannot be determined at this time.

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On October 26, 2016, the EPA published a final rule that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Alabama and Mississippi. The ultimate impact of this rule will depend on the outcome of any legal challenges and implementation at the state level and cannot be determined at this time.

FERC Matters

Municipal and Rural Associations Tariff

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

On March 31, 2016, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC for an increase in wholesale base revenues under the Municipal and Rural Associations (MRA) cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service in November 2015. The settlement agreement, accepted by the FERC, effective for services rendered beginning May 1, 2016, provides that base rates under the MRA cost-based electric tariff will produce additional annual base revenues of $7 million. 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 36 months, (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 $11 million through the Kemper IGCC's projected in-service date of December 31, 2016.

Fuel Cost Recovery

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. Effective with the first billing cycle for September 2016, fuel rates decreased $11 million annually for wholesale MRA customers and $1 million annually for wholesale MB customers.

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.

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 "Retail Regulatory Matters – Mississippi Power" and "Integrated Coal Gasification Combined Cycle" herein for additional information.

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Renewables

In November 2015, the Mississippi PSC issued orders approving three solar facilities for a combined total of approximately 105 MWs. Mississippi Power will purchase all of the energy produced by the solar facilities for the 25-year term under each of the three PPAs. The projects are expected to be in service by the second quarter 2017 and the resulting energy purchases are expected to be recovered through Mississippi Power's fuel cost recovery mechanism. 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.

Energy Efficiency

On May 3, 2016, the Mississippi PSC issued an order approving the annual Energy Efficiency Cost Rider Compliance filing, which included an anticipated reduction of $2 million in retail revenues for the year ending December 31, 2016.

Performance Evaluation Plan

On April 1, 2016, Mississippi Power submitted its annual PEP lookback filing for 2015, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC.

On July 12, 2016, Mississippi Power submitted its annual projected PEP filing for 2016 which indicated no change in rates. The filing has been suspended for review by the Mississippi PSC.

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

Environmental Compliance Overview Plan

On August 17, 2016, the Mississippi PSC approved Mississippi Power's revised ECO Plan filing for 2016, which requested the maximum 2% annual increase in revenues, approximately $18 million, primarily related to Plant Daniel Units 1 and 2 scrubbers being placed in service in November 2015. The revised rates became effective with the first billing cycle for September 2016. Approximately $22 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2017 filing.

Fuel Cost Recovery

At September 30, 2016, the amount of over-recovered retail fuel costs included on the balance sheet was $58 million compared to $71 million at December 31, 2015.

The Mississippi PSC conditionally approved a decrease of $120 million annually in fuel cost recovery rates on January 5, 2016, effective with the first billing cycle for February 2016. On August 17, 2016, the Mississippi PSC approved an additional decrease of $51 million annually in fuel cost recovery rates effective with the first billing cycle for September 2016.

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

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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 and continues to progress towards completing the remainder of the Kemper IGCC, including the gasifiers and the gas clean-up facilities. The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." On October 11, 2016, the Kemper IGCC began testing using clean syngas from gasifier "A" and the related gas clean-up systems to produce electricity. Late on October 31, 2016, gasifier "A" experienced challenges associated with the ash removal systems, and on November 2, 2016, Mississippi Power determined a maintenance outage on gasifier "A" is needed to make improvements to the ash removal systems. Therefore, Mississippi Power has re-sequenced activities, and gasifier "B" is now expected to progress through testing and begin producing electricity during the gasifier "A" outage. In light of these changes, Mississippi Power has determined that integrated operation of both gasifiers will not occur by mid-November and has revised the expected in-service date for the remainder of the Kemper IGCC to December 31, 2016. The remaining schedule reflects the time expected to achieve production of electricity using gasifier "B," complete gasifier "A" outage activities, and resume electricity production using gasifier "A," as well as to complete the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.

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MISSISSIPPI POWER COMPANY

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Recovery of the costs subject to the cost cap and the Cost Cap Exceptions remains subject to review and approval by the Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Court's decision discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of September 30, 2016 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	$	5.52		$	5.30
Lignite Mine and Equipment	0.21		0.23			0.23
CO2 Pipeline Facilities	0.14		0.11			0.11
AFUDC(d)	0.17		0.75			0.71
Combined Cycle and Related Assets Placed in Service – Incremental(e)	—		0.04			0.03
General Exceptions	0.05		0.10			0.09
Deferred Costs(e)	—		0.21			0.20
Additional DOE Grants	—		(0.14		)	(0.14		)
Total Kemper IGCC	$	2.97	$	6.82		$	6.53

(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. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (e) 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 September 30, 2016. 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 September 30, 2016. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of September 30, 2016, $3.70 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 $2.63 billion), $6 million in other property and investments, $81 million in fossil fuel stock, $46 million in materials and supplies, $33 million in other regulatory assets, current, $177 million in other regulatory assets, deferred, $4 million in other current assets, and $9 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 $88 million ($54 million after tax) in the third quarter 2016 and a total of $222 million ($137 million after tax) for the nine months ended September 30, 2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.63 billion ($1.63 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2016. The increase to the cost estimate in the third quarter of 2016 primarily reflects $53 million for the extension of the Kemper IGCC's projected in-service date from October 31, 2016 to December 31, 2016 and

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increased efforts related to operational readiness and challenges in start-up and commissioning activities, including the cost of repairs and modifications to gasifier "B" and mechanical improvements to coal feed and ash management systems, as well as certain post-in-service costs expected to be subject to the cost cap. The year-to-date increase to the cost estimate also includes $78 million for the extension of the Kemper IGCC's projected in-service date from August 31, 2016 to October 31, 2016. In addition, during the start-up and commissioning process, Mississippi Power is identifying potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. The related potential costs 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 December 31, 2016 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 with respect to the Kemper IGCC beyond December 31, 2016 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 $15 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 "2015 Rate Case" herein.

Mississippi Power's analysis of the time needed to complete the start-up and commissioning activities for the Kemper IGCC will continue until the remaining Kemper IGCC assets are placed in service. The next steps for the facility include the testing and production of electricity using clean syngas from gasifier "B," as well as the generation of electricity using clean syngas from gasifier "A," which are scheduled to occur by the end of November. If integrated operation of both gasifiers does not occur by mid-December, the expected in-service date and related cost estimate for the Kemper IGCC likely would require further revision. 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, 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

See "FERC Matters" herein for additional information regarding Mississippi Power's MRA cost based tariff relating to recovery of a portion of the Kemper IGCC costs from Mississippi Power's wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See Note (G) to the Condensed Financial Statements under "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" herein for additional tax information related to the Kemper IGCC.

The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity.

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

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based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with 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.

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).

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 September 30, 2016, AFUDC recorded since the original May 2014 estimated in-service date for the Kemper IGCC has totaled $352 million. 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.

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 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 below.

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 with the first billing cycle for 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. Mississippi Power continues to evaluate its alternatives with respect to its investment and related costs associated with the 15% undivided interest.

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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.

On July 27, 2016, the Court dismissed Greenleaf's motion for reconsideration of its previous decision to dismiss Greenleaf's appeal of the In-Service Asset Rate Order.

In addition to current estimated costs at September 30, 2016 of $6.82 billion, Mississippi Power anticipates that it will incur additional expenses in excess of current rates associated with operating the Kemper IGCC after it is placed in service until the Kemper IGCC cost recovery approach is finalized, which are expected to be material. These costs include, but are not limited to, regulatory costs, operational costs in excess of current rates, taxes, and additional carrying costs. Mississippi Power expects to request authority from the Mississippi PSC and 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. Mississippi Power is required to file its next rate request with the Mississippi PSC related to cost recovery for the Kemper IGCC by June 3, 2017. See "Regulatory Assets and Liabilities" below for additional information. As part of that filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation for the in-service assets.

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 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.

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 proceeding 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 following the start of commercial operations. Certain costs, including operations and maintenance, are materially higher than the amounts presented in the CPCN proceedings. 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. Mississippi Power expects the Mississippi PSC to address these issues in connection with its next rate request.

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

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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 September 30, 2016, the balance associated with these regulatory assets was $105 million, of which $33 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $105 million as of September 30, 2016. The amortization period for these assets is expected to be determined by the Mississippi PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews. See "FERC Matters" herein for 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 September 30, 2016, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $7 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 will own 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 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.

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Litigation

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

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.

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.

Bonus Depreciation

The extension of 50% bonus depreciation included in the PATH Act is expected to result in approximately $400 million of positive cash flows for the 2016 tax year, which may not all be realized in 2016 due to a projected consolidated net operating loss for Southern Company. Approximately $370 million of the benefit is dependent upon placing the remainder of the Kemper IGCC in service by December 31, 2016, of which $250 million has been received as of September 30, 2016 through quarterly income tax refunds. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and Note (G) to the Condensed Financial Statements under "Current and Deferred Income Taxes – Net Operating Loss" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

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

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nuisance, and citizen enforcement of environmental requirements, such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

The ultimate outcome of such pending or potential litigation against Mississippi Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K, 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 Electric Utility Regulation, Asset Retirement Obligations, Contingent Obligations, Unbilled Revenues, Pension and Other Postretirement Benefits, and AFUDC.

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

During 2016, 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 the revisions to the cost estimate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $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 2012. In the aggregate, Mississippi Power has

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incurred charges of $2.63 billion ($1.63 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2016.

Mississippi Power's revised cost estimate reflects an expected in-service date of December 31, 2016 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, 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, during the start-up and commissioning process, Mississippi Power is also identifying potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. The related potential costs have yet to be fully evaluated, have not been included in the current cost estimates, 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 December 31, 2016 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 with respect to the Kemper IGCC beyond December 31, 2016 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 $15 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.

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

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Mississippi Power is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Mississippi Power's balance sheet.

On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Mississippi Power currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15,

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2016. Early adoption is permitted and Mississippi Power intends to adopt the ASU in the fourth quarter 2016. The adoption is not expected to have a material impact on the results of operations, financial position, or cash flows of Mississippi Power.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Earnings for the nine months ended September 30, 2016 were negatively affected by revisions to the cost estimate for the Kemper IGCC.

Through September 30, 2016, Mississippi Power has incurred non-recoverable cash expenditures of $2.42 billion and is expected to incur approximately $0.21 billion in additional non-recoverable cash expenditures through completion of the construction and start-up of the Kemper IGCC, which includes certain post-in-service costs expected to be subject to the cost cap.

Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows through 2021. 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, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities.

On January 28, 2016, Mississippi Power issued a promissory note for up to $275 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During the first nine months of 2016, Mississippi Power borrowed $100 million under this promissory note and an additional $100 million under a separate promissory note issued to Southern Company in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. On June 27, 2016, Mississippi Power received a capital contribution from Southern Company for $225 million, the proceeds of which were used to repay to Southern Company a portion of the existing promissory note issued in November 2015. As of September 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.

As of September 30, 2016, Mississippi Power's current liabilities exceeded current assets by approximately $411 million primarily due to the $300 million in senior notes which matured on October 15, 2016, as well as $65 million in short-term debt.

Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company to fund the remainder of its short-term capital needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $372 million for the first nine months of 2016, an increase of $23 million as compared to the corresponding period in 2015. The increase in cash provided from operating activities is primarily due to income taxes receivable associated with research and experimental (R&E) deductions and accrued taxes, partially offset by lower R&E tax deductions, the cessation of Mirror CWIP collections and subsequent refund payments, and higher recovery of regulatory fuel clause revenues. 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 $509 million for the first nine months of 2016 primarily due to gross property additions related to the Kemper IGCC, partially offset by receipt of $137 million in Additional DOE Grants. Net cash provided from financing activities totaled $198 million for the first nine months

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of 2016 primarily due to long-term debt issuances and capital contributions from Southern Company, partially offset by redemptions of long-term debt and a decrease in short-term borrowings. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first nine months of 2016 include an increase in long-term debt of $826 million. A portion of this debt was used to repay securities and notes payable resulting in a $385 million decrease in securities due within one year and a $475 million decrease in notes payable. Additionally, CWIP increased $271 million primarily due to the Kemper IGCC and the customer liability associated with Kemper IGCC refunds decreased $72 million. Other significant changes include a $110 million increase in accrued income taxes due to bonus depreciation, a $61 million increase in accumulated deferred income taxes (ADIT) due to transmission and distribution property-related ADITs and additional Section 174 R&E deduction, partially offset by ADITs associated with the estimated losses on the Kemper IGCC construction, and a $39 million increase in prepaid income taxes. Total common stockholder's equity increased $269 million primarily due to the receipt of capital contributions from Southern Company and net income for the period.

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 $300 million will be required through September 30, 2017 to fund maturities of long-term debt, and $25 million will be required to fund maturities of short-term debt. See "Sources of Capital" herein for additional information. Subsequent to September 30, 2016, Mississippi Power repaid at maturity $300 million aggregate principal amount of its Series 2011A 2.35% Senior Notes due October 15, 2016. If the Kemper IGCC does not go into service by December 31, 2016, Mississippi Power also would have to repay approximately $250 million of tax benefits received as a result of quarterly income tax estimates through September 30, 2016. See "Income Tax Matters" herein for additional information.

The construction program of Mississippi Power is currently estimated to be $0.8 billion for 2016, net of the Additional DOE Grants, $0.3 billion for 2017, $0.2 billion for 2018, $0.2 billion for 2019, $0.3 billion for 2020, and $0.3 billion for 2021, which includes revised estimates for the Kemper IGCC, including post-in-service costs. The expenditures related to the construction and start-up of the Kemper IGCC are currently estimated to be $0.7 billion for 2016, net of the Additional DOE Grants, and $0.1 billion for 2017. These estimated expenditures do not include potential compliance costs that may arise from the EPA's final rules and guidelines or subsequently approved 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. 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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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Sources of Capital

In December 2015, the Mississippi PSC approved the In-Service Asset Rate Order, which among other things, provided for retail rate recovery of an annual revenue requirement of approximately $126 million effective December 17, 2015. 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 – 2013 MPSC Rate Order" and " – 2015 Rate Case" of Mississippi Power in Item 7 of the Form 10-K for additional information. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" of Mississippi Power in Item 7 of the Form 10-K for additional information.

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. On April 8, 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. In addition, 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 legislation related to the securitization of certain costs of the Kemper IGCC.

On January 28, 2016, Mississippi Power issued a promissory note for up to $275 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During the first nine months of 2016, Mississippi Power borrowed $100 million pursuant to the $275 million promissory note and an additional $100 million under a separate promissory note issued to Southern Company in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR. On June 27, 2016, Mississippi Power received a capital contribution from Southern Company for $225 million, the proceeds of which were used to repay to Southern Company a portion of the existing promissory note issued in November 2015. As of September 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.

Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company to fund Mississippi Power's short-term capital needs.

At September 30, 2016, Mississippi Power had approximately $159 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2016 were as follows:

Expires								Executable Term Loans				Due Within One Year
2016		2017		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)				(in millions)				(in millions)				(in millions)
$	100	$	75	$	175	$	150	$	—	$	15	$	15	$	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 arrangements, contain covenants that limit debt levels and typically contain cross acceleration or cross default provisions to other indebtedness

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(including guarantee obligations) of Mississippi Power. Such cross default provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness or guarantee obligations over a specific threshold. 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. Mississippi Power is 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 $150 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of September 30, 2016 was approximately $40 million.

Details of short-term borrowings were as follows:

	Short-term Debt at September 30, 2016			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	$	25	2.2%	$	25	2.1%	$	25

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016.

Credit Rating Risk

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 September 30, 2016, 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 $259 million.

Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. 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 May 12, 2016, Fitch downgraded the senior unsecured long-term debt rating of Mississippi Power to BBB+ from A- and revised the ratings outlook from negative to stable.

Financing Activities

On January 28, 2016, Mississippi Power issued a promissory note for up to $275 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During the first nine months of 2016, Mississippi Power borrowed $100 million under this promissory note and an additional $100 million under a separate promissory note issued to Southern Company in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

$1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR. On June 27, 2016, Mississippi Power received a capital contribution from Southern Company of $225 million, the proceeds of which were used to repay to Southern Company a portion of the promissory note issued in November 2015. As of September 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.

In June 2016, Mississippi Power renewed a $10 million short-term note, which matures on June 30, 2017, bearing interest based on three-month LIBOR.

In September 2016, Mississippi Power entered into interest rate swaps to fix the variable interest rate on $900 million of the term loan entered into in March 2016.

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AND SUBSIDIARY COMPANIES

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2016			2015			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	387		$	295		$	866		$	776
Wholesale revenues, affiliates	110			104			313			303
Other revenues	3			2			10			7
Total operating revenues	500			401			1,189			1,086
Operating Expenses:
Fuel	154			118			341			361
Purchased power, non-affiliates	25			17			60			52
Purchased power, affiliates	8			5			16			18
Other operations and maintenance	81			62			246			184
Depreciation and amortization	93			64			247			183
Taxes other than income taxes	5			6			17			17
Total operating expenses	366			272			927			815
Operating Income	134			129			262			271
Other Income and (Expense):
Interest expense, net of amounts capitalized	(35		)	(18		)	(78		)	(62		)
Other income (expense), net	2			1			3			1
Total other income and (expense)	(33		)	(17		)	(75		)	(61		)
Earnings Before Income Taxes	101			112			187			210
Income taxes (benefit)	(102		)	1			(167		)	14
Net Income	203			111			354			196
Less: Net income attributable to noncontrolling interests	27			9			39			15
Net Income Attributable to Southern Power	$	176		$	102		$	315		$	181

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2016			2015		2016			2015
	(in millions)					(in millions)
Net Income	$	203		$	111	$	354		$	196
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $14, $-, $(1), and $-, respectively	23			—		(1		)	—
Reclassification adjustment for amounts included in net income, net of tax of $(1), $-, $7, and $-, respectively	(1		)	—		13			—
Total other comprehensive income (loss)	22			—		12			—
Less: Comprehensive income attributable to noncontrolling interests	27			9		39			15
Comprehensive Income Attributable to Southern Power	$	198		$	102	$	327		$	181

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	354		$	196
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	262			187
Deferred income taxes	(668		)	222
Investment tax credits	—			294
Amortization of investment tax credits	(25		)	(14		)
Deferred revenues	9			15
Collateral deposits	(80		)	—
Accrued income taxes, non-current	—			100
Other, net	10			10
Changes in certain current assets and liabilities —
-Receivables	(82		)	(28		)
-Prepaid income taxes	(16		)	(116		)
-Other current assets	1			1
-Accounts payable	7			1
-Accrued taxes	483			(247		)
-Other current liabilities	14			(12		)
Net cash provided from operating activities	269			609
Investing Activities:
Business acquisitions	(1,134		)	(1,128		)
Property additions	(1,702		)	(348		)
Change in construction payables	(69		)	88
Payments pursuant to long-term service agreements	(58		)	(65		)
Investment in restricted cash	(750		)	—
Distribution of restricted cash	746			—
Other investing activities	(41		)	(1		)
Net cash used for investing activities	(3,008		)	(1,454		)
Financing Activities:
Increase in notes payable, net	692			18
Proceeds —
Senior notes	1,531			650
Capital contributions	800			226
Other long-term debt	63			400
Redemptions —
Senior notes	—			(525		)
Other long-term debt	(84		)	(3		)
Distributions to noncontrolling interests	(22		)	(6		)
Capital contributions from noncontrolling interests	367			274
Purchase of membership interests from noncontrolling interests	(129		)	—
Payment of common stock dividends	(204		)	(98		)
Other financing activities	(14		)	(5		)
Net cash provided from financing activities	3,000			931
Net Change in Cash and Cash Equivalents	261			86
Cash and Cash Equivalents at Beginning of Period	830			75
Cash and Cash Equivalents at End of Period	$	1,091		$	161
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $32 and $4 capitalized for 2016 and 2015, respectively)	$	49		$	69
Income taxes, net	71			(215		)
Noncash transactions — Accrued property additions at end of period	210			120

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2016		At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,091	$	830
Receivables —
Customer accounts receivable	121		75
Other accounts receivable	25		19
Affiliated	67		30
Fossil fuel stock	14		16
Materials and supplies	163		63
Prepaid income taxes	61		45
Other current assets	32		30
Total current assets	1,574		1,108
Property, Plant, and Equipment:
In service	9,491		7,275
Less accumulated provision for depreciation	1,465		1,248
Plant in service, net of depreciation	8,026		6,027
Construction work in progress	1,652		1,137
Total property, plant, and equipment	9,678		7,164
Other Property and Investments:
Goodwill	2		2
Other intangible assets, net of amortization of $16 and $12 at September 30, 2016 and December 31, 2015, respectively	389		317
Total other property and investments	391		319
Deferred Charges and Other Assets:
Prepaid long-term service agreements	151		166
Accumulated deferred income taxes	199		—
Other deferred charges and assets — affiliated	3		9
Other deferred charges and assets — non-affiliated	355		139
Total deferred charges and other assets	708		314
Total Assets	$	12,351	$	8,905

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At September 30, 2016		At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	60	$	403
Notes payable	828		137
Accounts payable —
Affiliated	91		66
Other	218		327
Accrued taxes —
Accrued income taxes	147		198
Other accrued taxes	16		5
Accrued interest	30		23
Contingent consideration	30		36
Other current liabilities	97		44
Total current liabilities	1,517		1,239
Long-term Debt	4,548		2,719
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	140		601
Accumulated deferred investment tax credits	1,385		889
Accrued income taxes, non-current	109		109
Asset retirement obligations	40		21
Deferred capacity revenues — affiliated	19		17
Other deferred credits and liabilities	115		3
Total deferred credits and other liabilities	1,808		1,640
Total Liabilities	7,873		5,598
Redeemable Noncontrolling Interests	49		43
Common Stockholder's Equity:
Common stock, par value $.01 per share —
Authorized — 1,000,000 shares
Outstanding — 1,000 shares	—		—
Paid-in capital	2,620		1,822
Retained earnings	769		657
Accumulated other comprehensive income (loss)	16		4
Total common stockholder's equity	3,405		2,483
Noncontrolling interests	1,024		781
Total stockholders' equity	4,429		3,264
Total Liabilities and Stockholders' Equity	$	12,351	$	8,905

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2016 vs. THIRD QUARTER 2015

AND

YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 2015

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 of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, electric cooperatives, 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 nine months ended September 30, 2016, Southern Power acquired or commenced construction of approximately 758 MWs of additional solar and wind facilities and, subsequent to September 30, 2016, acquired or commenced construction of approximately 977 MWs of wind and natural gas facilities. In addition, Southern Power has committed to acquire approximately 674 MWs of solar and wind facilities over the next several months. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.

At September 30, 2016, Southern Power had an average investment coverage ratio of 92% through 2020 and 91% through 2025, with an average remaining contract duration of approximately 17 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. These indicators include peak season equivalent forced outage rate, contract availability, and net income. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Southern Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$74	72.5	$134	74.0

Net income attributable to Southern Power for the third quarter 2016 was $176 million compared to $102 million for the corresponding period in 2015. Net income attributable to Southern Power for year-to-date 2016 was $315 million compared to $181 million for the corresponding period in 2015. The increases were primarily due to increased federal income tax benefits from solar ITCs and wind PTCs and increased renewable energy sales, partially offset by increases in depreciation, operations and maintenance expenses, and interest expense from debt issuances, all related to new solar and wind facilities.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Operating Revenues

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$99	24.7	$103	9.5

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 unused capacity, it may sell power into the wholesale market or into the power pool.

Capacity revenues are an integral component of Southern Power's natural gas and biomass PPAs. Energy under these PPAs is generally sold at variable cost or is indexed to published gas indices. Energy revenues also include fees for support services, fuel storage, and unit start charges.

Southern Power's electricity sales from solar and wind generating facilities are also through long-term PPAs; however, these solar and wind PPAs do not have a capacity charge and customers purchase the energy output of a dedicated renewable facility through an energy charge. 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.

	Third Quarter 2016 vs. Third Quarter 2015				Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)	(change in millions)			(% change)
PPA capacity revenues	$	(19	)	(11.8)	$	(25	)	(5.8)
PPA energy revenues	62			33.3	79			17.5
Total PPA revenues	43			11.8	54			6.1
Revenues not covered by PPAs	55			121.9	46			23.4
Other revenues	1			50.0	3			42.9
Total operating revenues	$	99		24.7%	$	103		9.5%

In the third quarter 2016, operating revenues were $500 million compared to $401 million for the corresponding period in 2015. The $99 million increase in operating revenues was primarily due to the following:

• PPA capacity revenues decreased $19 million primarily due to the remarketing of generation capacity into the short-term markets as a result of PPA expirations.

• PPA energy revenuesincreased $62 million primarily due to an increase in renewable energy sales from new solar and wind facilities.

• Revenues not covered by PPAs increased $55 million primarily due to an increase in short-term sales to non-affiliates as a result of the remarketing of generation capacity from expired PPAs.

For year-to-date 2016, operating revenues were $1.2 billion compared to $1.1 billion for the corresponding period in 2015. The $103 million increase in operating revenues was primarily due to the following:

• PPA capacity revenues decreased $25 million as a result of a $44 million decrease in non-affiliate capacity revenues primarily due to the remarketing of generation capacity into the short-term markets as a result of PPA expirations, partially offset by a $19 million increase in affiliate capacity revenues due to new PPAs.

• PPA energy revenuesincreased $79 million primarily due to a $122 million increase in renewable energy sales arising from new solar and wind facilities, partially offset by a decrease of $43 million in fuel revenues related to natural gas facility PPAs.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

• Revenues not covered by PPAs increased $46 million due to a $70 million increase in short-term sales to non-affiliates as a result of the remarketing of generation capacity from expired PPAs, partially offset by a $24 million decrease in power pool revenue primarily associated with a reduction in available uncovered capacity.

Wholesale 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. Increases and decreases in revenues under PPAs 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.

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 and the power pool. Details of Southern Power's generation and purchased power were as follows:

	Third Quarter 2016	Third Quarter 2015	Year-to-Date 2016	Year-to-Date 2015
	(in billions of KWHs)
Generation	11.1	9.4	27.9	24.8
Purchased power	0.9	0.5	2.5	1.5
Total generation and purchased power	12.0	9.9	30.4	26.3
Total generation and purchased power excluding solar, wind, and tolling agreements	6.7	5.2	17.7	15.9

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 (excluding its subsidiaries).

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.

	Third Quarter 2016 vs. Third Quarter 2015			Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)		(% change)	(change in millions)			(% change)
Fuel	$	36	30.5	$	(20	)	(5.5)
Purchased power	11		50.0	6			8.6
Total fuel and purchased power expenses	$	47		$	(14	)

In the third quarter 2016, total fuel and purchased power expenses were $187 million compared to $140 million for the corresponding period in 2015. The increase was primarily due to the following:

• Fuel expense increased $36 million primarily due to a $27 million increase associated with the volume of KWHs generated and a $9 million increase associated with average cost of natural gas per KWH generated.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

• Purchased power expense increased $11 million due to a $19 million increase associated with the volume of KWHs purchased, partially offset by a $4 million decrease in the average cost of purchased power and a $4 million decrease associated with a PPA expiration.

For year-to-date 2016, total fuel and purchased power expenses were $417 million compared to $431 million for the corresponding period in 2015. The decrease was primarily due to the following:

• Fuel expense decreased $20 million primarily due to a $42 million decrease associated with the average cost of natural gas per KWH generated, partially offset by a $22 million increase associated with the volume of KWHs generated.

• Purchased power expense increased $6 million due to a $48 million increase associated with the volume of KWHs purchased, largely offset by a $30 million decrease in the average cost of purchased power and a $12 million decrease associated with a PPA expiration.

Other Operations and Maintenance Expenses

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$19	30.6	$62	33.7

In the third quarter 2016, other operations and maintenance expenses were $81 million compared to $62 million for the corresponding period in 2015. The increase was primarily due to a $9 million increase in expenses associated with new solar and wind facilities placed in service in 2015 and 2016, a $5 million increase associated with scheduled outage and maintenance expenses, and a $3 million increase in general business expenses associated with Southern Power's overall growth strategy.

For year-to-date 2016, other operations and maintenance expenses were $246 million compared to $184 million for the corresponding period in 2015. The increase was primarily due to a $24 million increase associated with scheduled outage and maintenance expenses, a $22 million increase in expenses associated with new solar and wind facilities placed in service in 2015 and 2016, and a $14 million increase in general business expenses associated with Southern Power's overall growth strategy.

Depreciation and Amortization

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$29	45.3	$64	35.0

In the third quarter 2016, depreciation and amortization was $93 million compared to $64 million for the corresponding period in 2015. For year-to-date 2016, depreciation and amortization was $247 million compared to $183 million for the corresponding period in 2015. The increases were primarily due to additional depreciation related to new solar and wind facilities placed in service in 2015 and 2016.

Interest Expense, net of Amounts Capitalized

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$17	94.4	$16	25.8

In the third quarter 2016, interest expense, net of amounts capitalized was $35 million compared to $18 million for the corresponding period in 2015. The increase was primarily due to an increase of $25 million in interest expense related to additional debt issued since the third quarter of 2015 primarily to fund Southern Power's growth strategy and continuous construction program, partially offset by an $8 million increase in capitalized interest associated

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with the construction of solar facilities.

For year-to-date 2016, interest expense, net of amounts capitalized was $78 million compared to $62 million for the corresponding period in 2015. The increase was primarily due to an increase of $43 million in interest expense related to additional debt issued since the third quarter of 2015 primarily to fund Southern Power's growth strategy and continuous construction program, largely offset by a $27 million increase in capitalized interest associated with the construction of solar facilities.

Income Taxes (Benefit)

Third Quarter 2016 vs. Third Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(103)	N/M	$(181)	N/M

N/M - Not meaningful

In the third quarter 2016, income tax benefit was $(102) million compared to an expense of $1 million for the corresponding period in 2015. The change was primarily due to a $96 million increase in federal income tax benefits from solar ITCs and wind PTCs in 2016 and a $10 million decrease in tax expense related to lower pre-tax earnings in 2016, partially offset by a $3 million increase in tax expense related to beneficial state apportionment rate changes in 2015.

For year-to-date 2016, income tax benefit was $(167) million compared to an expense of $14 million for the corresponding period in 2015. The change was primarily due to a $171 million increase in federal income tax benefits from solar ITCs and wind PTCs in 2016 and a $17 million decrease in tax expense related to lower pre-tax earnings in 2016, partially offset by a $7 million increase in tax expense related to beneficial state apportionment rate changes in 2015.

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 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 construct generating facilities; and the impact of federal ITCs and PTCs. 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.

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 December 31, 2015, Southern Power's generation contract coverage ratio, which compares contracted capacity (MW) to available demonstrated capacity (MW), was an average of 75% through 2020 and 70% through 2025, with an average remaining contract duration of approximately 10 years.

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Southern Power believes an investment coverage ratio best identifies the value of assets covered since it represents 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 or being acquired) as the investment amount. At September 30, 2016, the average investment coverage ratio was 92% through 2020 and 91% through 2025, with an average remaining contract duration of approximately 17 years. At December 31, 2015, the average investment coverage ratio would have been 91% through 2020 and 90% through 2025, with an average remaining contract duration of approximately 18 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

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's Cross State Air Pollution Rule (CSAPR).

On October 26, 2016, the EPA published a final rule that updates the CSAPR ozone season nitrogen oxide program, including revising ozone-season emissions budgets in Alabama and Texas and removing Florida and North Carolina from the CSAPR program. The ultimate impact of this rule will depend on the outcome of any legal challenges and implementation at the state level and cannot be determined at this time.

Acquisitions

During 2016, in accordance with its overall growth strategy, Southern Power or one of its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC and Southern Renewable Energy, Inc., acquired or contracted to acquire the projects discussed below. Acquisition-related costs were expensed as incurred and were not material. See Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information.

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Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Percentage Ownership			Actual/Expected COD	PPA Contract Period
Acquisitions During the Nine Months Ended September 30, 2016
Calipatria	Solar	20	Imperial County, CA	90	%		February 2016	20 years
East Pecos	Solar	120	Pecos County, TX	100	%		December 2016	15 years
Grant Plains	Wind	147	Grant County, OK	100	%		December 2016	Up to 20 years
Grant Wind	Wind	151	Grant County, OK	100	%		April 2016	20 years
Henrietta	Solar	102	Kings County, CA	51	%	(a)	July 2016	20 years
Lamesa	Solar	102	Dawson County, TX	100	%		First quarter 2017	15 years
Passadumkeag	Wind	42	Penobscot County, ME	100	%		July 2016	15 years
Rutherford	Solar	74	Rutherford County, NC	90	%		December 2016	15 years
Acquisitions Subsequent to September 30, 2016
Mankato	Natural Gas	375	Mankato, MN	100	%		N/A(b)	10 years
Wake Wind	Wind	257	Floyd and Crosby Counties, TX	90.1	%		October 2016	12 years

(a) Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction.

(b) The Mankato facility is a fully operational 375-MW natural gas-fired combined-cycle facility with an additional 345-MW expansion under development.

Acquisitions During the Nine Months Ended September 30, 2016

Southern Power's aggregate purchase price for the project facilities acquired during the nine months ended September 30, 2016 was approximately $830 million. Total aggregate construction costs, excluding the acquisition costs, are expected to be $708 million to $775 million for East Pecos, Grant Plains, Lamesa, and Rutherford, which are currently under construction. The ultimate outcome of these matters cannot be determined at this time.

Acquisitions Subsequent to September 30, 2016

Southern Power's aggregate purchase price for acquisitions subsequent to September 30, 2016 was approximately $873 million. As part of Southern Power's acquisition of Mankato, which has a fully operational 375-MW natural gas-fired combined-cycle facility, Southern Power has commenced construction of an additional 345-MW expansion which is covered with a 20-year PPA. Total aggregate construction costs, excluding the acquisition costs allocated to CWIP, are expected to be $170 million to $190 million. The ultimate outcome of this matter cannot be determined at this time.

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Acquisition Agreements Executed but Not Yet Closed

During the nine months ended September 30, 2016 and subsequent to that date, Southern Power entered into agreements to acquire the following projects for an aggregate purchase price of approximately $1.2 billion:

• 51% ownership interest (through 100% ownership of the class A membership interests entitling Southern Power to 51% of all cash distributions and most of the federal tax benefits) in a 100-MW solar facility in Nevada covered with a 20-year PPA, which is expected to close in November 2016;

• 100% ownership interests in two wind facilities in Texas totaling 299 MWs, the majority of which is contracted under PPAs for the first 12 to 14 years of operation and are expected to close before the end of 2016; and

• 100% ownership interest in a 275-MW wind facility in Texas, the majority of which is contracted under a 12-year PPA and is expected to close in January 2017.

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

The aggregate amount of revenue recognized by Southern Power related to the project facilities acquired during the nine months ended September 30, 2016 included in the condensed consolidated statements of income for year-to-date 2016 is $14 million. The aggregate amount of net income, excluding impacts of ITCs and PTCs, attributable to Southern Power related to the project facilities acquired during the nine months ended September 30, 2016 included in the condensed consolidated statements of income is immaterial. These businesses did not have operating revenues or activities prior to completion of construction and their assets being placed in service; therefore, supplemental pro forma information as though the acquisitions occurred as of the beginning of 2016, and for the comparable 2015 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.

During the nine months ended September 30, 2016, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through September 30, 2016, total costs of construction incurred for the following projects were $3.0 billion, of which $1.2 billion remains in CWIP. Including the total construction costs incurred through September 30, 2016 and the acquisition prices allocated to CWIP, total aggregate construction costs for the following projects are estimated to be $3.1 billion to $3.2 billion. The ultimate outcome of these matters cannot be determined at this time.

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Solar Facility	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Projects Completed During the Nine Months Ended September 30, 2016
Butler Solar Farm	22	Taylor County, GA	February 2016	20 years
Desert Stateline(a)	299(b)	San Bernardino County, CA	Through July 2016	20 years
Garland A	20	Kern County, CA	August 2016	20 years
Pawpaw	30	Taylor County, GA	March 2016	30 years
Tranquillity	205	Fresno County, CA	July 2016	18 years
Projects Under Construction as of September 30, 2016
Butler	103	Taylor County, GA	December 2016	30 years
Garland	185	Kern County, CA	October 2016	15 years
Roserock	160	Pecos County, TX	November 2016	20 years
Sandhills	146	Taylor County, GA	October 2016	25 years

(a) On March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline. As a result, Southern Power and the class B member are entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction.

(b) The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 189 MWs were placed in service during the nine months ended September 30, 2016.

Income Tax Matters

Bonus Depreciation

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

The extension of 50% bonus depreciation included in the PATH Act is expected to result in approximately $650 million of positive cash flows for the 2016 tax year, which may not all be realized in 2016 due to a projected consolidated net operating loss (NOL) for Southern Company. As a result, the NOL will increase deferred tax assets for federal ITC and PTC carryforwards. See Note (G) to the Condensed Financial Statements under "Current and Deferred Income Taxes – Net Operating Loss" and " – Tax Credit Carryforwards" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

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

TheultimateoutcomeofsuchpendingorpotentiallitigationagainstSouthern Powercannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementshereinorinNote3tothefinancialstatementsofSouthern PowerinItem8ofthe Form 10-K,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Power's financial statements.

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ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Recently Issued Accounting Standards

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Southern Power is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Southern Power's balance sheet.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power's financial condition remained stable at September 30, 2016. 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 $269 million for the first nine months of 2016 compared to $609 million for the first nine months of 2015. The decrease in net cash provided from operating activities was primarily due to an increase in unutilized ITCs and PTCs. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" herein for additional information. Net cash used for investing activities totaled $3.0 billion for the first nine months of 2016 primarily due to 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 $3.0 billion for the first nine months of 2016 primarily due to an increase in senior notes, notes payable, and capital contributions from Southern Company. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first nine months of 2016 include a $515 million increase in CWIP due to the acquisition and continued construction of new solar and wind facilities and a $2.2 billion increase in plant in service, primarily due to solar and wind facilities being placed in service. Other significant changes include a $261 million increase in cash and cash equivalents and a $2.5 billion increase in notes payable and long-term debt primarily due to additional borrowings to fund acquisitions and construction projects. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a

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description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, unrecognized tax benefits, and other purchase commitments. Approximately $60 million will be required to repay maturities of long-term debt through September 30, 2017. In addition, during the nine months ended September 30, 2016, and subsequent to that date, Southern Power entered into new long-term service agreements (LTSA), which begin between 2017 and 2020 and result in additional future commitments totaling approximately $927 million.

Southern Power's construction program includes estimates for potential plant acquisitions, new construction, 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. Capital expenditures for Southern Power are currently estimated to total approximately $4.5 billion for 2016, primarily for acquisitions and/or construction of new generating facilities. Capital expenditures for Southern Power are currently estimated to total approximately $1.6 billion annually for 2017 through 2021. 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, and other purposes from sources similar to those used in the past, which were primarily 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. Southern Power expects to utilize the capital markets, bank term loans, and commercial paper markets as the source of funds for the majority of its debt maturities.

As of September 30, 2016, Southern Power had cash and cash equivalents of approximately $1.1 billion.

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	$	10	0.9	%	$	62

(*) Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016. No short-term debt was outstanding at September 30, 2016.

Company Credit Facility

At September 30, 2016, Southern Power had a committed credit facility (Facility) of $600 million expiring in 2020, of which $68 million has been used for letters of credit and $532 million remains unused. Southern Power's subsidiaries are not borrowers under the Facility.

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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.

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.

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.

Subsidiary Credit Facilities

In connection with the construction of solar facilities byRE Garland Holdings LLC, RE Roserock LLC, and RE Tranquillity LLC, indirect subsidiaries of Southern Power, each subsidiary entered into separate credit agreements (Project Credit Facilities), which are non-recourse to Southern Power (other than the subsidiary party to the agreement). Each Project Credit Facility provides (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 is secured by the membership interests of the respective project company, with proceeds directed to finance project costs related to the respective solar facilities. Each Project Credit Facility is secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The table below summarizes each Project Credit Facility as of September 30, 2016.

Project	Maturity Date	Construction Loan Facility		Bridge Loan Facility		Total Loan Facility		Loan Facility Undrawn		Letter of Credit Facility		Letter of Credit Facility Undrawn
		(in millions)
Garland	Earlier of PPA COD or November 30, 2016	$	86	$	308	$	394	$	21	$	49	$	23
Roserock	Earlier of PPA COD or November 30, 2016(*)	63		180		243		34		23		16
Tranquillity	October 14, 2016	86		172		258		12		77		26
Total		$	235	$	660	$	895	$	67	$	149	$	65

(*) Subsequent to September 30, 2016, Roserock extended the maturity date of its Project Credit Facility to December 31, 2016.

The Project Credit Facilities above had total amounts outstanding as of September 30, 2016 of $828 million at a weighted average interest rate of 2.05%. For the three-month period ended September 30, 2016, these credit agreements had a maximum amount outstanding of $828 million and an average amount outstanding of $805 million at a weighted average interest rate of 2.02%.

Furthermore, in connection with the acquisition of the Henrietta solar facility on July 1, 2016, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. For the three-month period ended September 30, 2016, this credit agreement had a maximum amount outstanding of $217 million and an average amount outstanding of $137 million at a weighted average interest rate of 2.21%.

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

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Credit Rating Risk

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

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

The maximum potential collateral requirements under these contracts at September 30, 2016 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	30
At BBB- and/or Baa3	$	385
Below BBB- and/or Baa3	$	1,104

Included in these amounts are certain agreements that could require collateral in the event that one or more power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. 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.

Financing Activities

In June 2016, Southern Power issued €600 million aggregate principal amount of Series 2016A 1.00% Senior Notes due June 20, 2022 and €500 million aggregate principal amount of Series 2016B 1.85% Senior Notes due June 20, 2026. The proceeds are being allocated to renewable energy generation projects. Southern Power's obligations under its euro-denominated fixed-rate notes were effectively converted to fixed-rate U.S. dollars at issuance through cross-currency swaps, removing foreign currency exchange risk associated with the interest and principal payments. See Note (H) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for additional information.

In September 2016, Southern Power issued $290 million aggregate principal amount of Series 2016C 2.75% Senior Notes due September 20, 2023. The proceeds were used for general corporate purposes, including Southern Power's growth strategy and continuous construction program, as well as repayment of amounts outstanding under the Project Credit Facilities.

Also in September 2016, Southern Power repaid $80 million of an outstanding $400 million floating rate bank loan and extended the maturity date of the remaining $320 million from September 2016 to September 2018. In addition, Southern Power entered into a $60 million aggregate principal amount floating rate bank loan bearing interest based on one-month LIBOR due September 2017. The proceeds were used to repay existing indebtedness and for other general corporate purposes.

In addition, Southern Power issued $34 million in letters of credit during the nine months ended September 30, 2016.

During the nine months ended September 30, 2016, Southern Power's subsidiaries incurred an additional $691 million of short-term borrowings pursuant to the Project Credit Facilities at a weighted average interest rate of 2.05%. Furthermore, in connection with the acquisition of the Henrietta solar facility, a subsidiary of Southern

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. In addition, Southern Power's subsidiaries issued $16 million in letters of credit.

Subsequent to September 30, 2016, Southern Power's subsidiaries borrowed $5 million pursuant to the Project Credit Facilities at a weighted average interest rate of 2.03%. In addition, on October 14, 2016, Southern Power repaid at maturity $246 million of Project Credit Facility debt.

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.

156

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

(UNAUDITED)

INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS

Note		Page Number
A	Introduction	158
B	Contingencies and Regulatory Matters	162
C	Fair Value Measurements	180
D	Stockholders' Equity	184
E	Financing	186
F	Retirement Benefits	190
G	Income Taxes	193
H	Derivatives	195
I	Acquisitions	208
J	Segment and Related Information	215

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
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

157

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY 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, 2015 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2016 and 2015. 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 since July 1, 2016 and financial condition as of September 30, 2016 are reflected within Southern Company's consolidated amounts in these accompanying notes herein. Southern Company Gas continues to maintain reporting requirements as an SEC registrant and has filed its Quarterly Report on Form 10-Q with the SEC separately from this combined Form 10-Q. The equity method is used for entities in which Southern Company has significant influence but does not control, including Southern Company Gas' investment in Southern Natural Gas Company, L.L.C. (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" and " – Investment in Southern Natural Gas" for additional information regarding the Merger and Southern Company Gas' investment in SNG, respectively.

Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.

Recently Issued Accounting Standards

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption

158

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

permitted. The registrants are currently evaluating the new standard and have not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the registrants' balance sheets.

On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Southern Company and the traditional electric operating companies currently recognize any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation as additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted and Southern Company and the traditional electric operating companies intend to adopt the ASU in the fourth quarter 2016. The adoption is not expected to have a material impact on the results of operations, financial position, or cash flows of Southern Company and the traditional electric operating companies.

Affiliate Transactions

In 2014, prior to Southern Company's acquisition of PowerSecure International, Inc. (PowerSecure) on May 9, 2016, Georgia Power entered into two agreements with PowerSecure to build solar power generation facilities at two U.S. Army bases, as approved by the Georgia PSC. Payments of approximately $108 million made by Georgia Power to PowerSecure under the two agreements since inception in 2014 are included in CWIP at September 30, 2016. PowerSecure construction service costs of approximately $0.2 million are included in accounts payable, affiliated in Georgia Power's balance sheet at September 30, 2016. On October 4, 2016, the two facilities began commercial operation.

Prior to Southern Company Gas' completion of its acquisition of a 50% equity interest in SNG, Southern Company and Southern Company Gas had entered into long-term interstate natural gas transportation agreements with SNG. The interstate transportation service provided to the traditional electric operating companies, 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 period subsequent to Southern Company Gas' investment in SNG, transportation costs paid to SNG by Southern Company were approximately $16 million, including $8 million for Georgia Power, $2 million for Southern Power, and $1 million for Alabama Power.

See Note (I) under "Southern Company– Acquisition of PowerSecure International, Inc." and " – Investment in Southern Natural Gas" for additional information regarding Southern Company's acquisition of PowerSecure and Southern Company Gas' investment in SNG, respectively.

Asset Retirement Obligations

See Note 1 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information regarding Southern Company's and the traditional electric operating companies' asset retirement obligations (ARO) and the EPA's regulation of CCR. See Note 1 to the financial statements of Southern Power under "Asset Retirement Obligations" in Item 8 of the Form 10-K for additional information regarding Southern Power's AROs.

The cost estimates below are based on information as of September 30, 2016. The cost estimates for AROs related to the disposal of CCR are based on various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the Disposal of Coal Combustion Residuals from Electric Utilities final rule requirements for closure in place or by other methods. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the traditional electric operating companies expect to continue to periodically update these estimates.

159

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

As of September 30, 2016, details of the AROs included in the registrants' Condensed Balance Sheets were as follows:

	Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power			Southern Power
	(in millions)
Balance at beginning of year	$	3,759		$	1,448		$	1,916		$	130	$	177		$	21
Liabilities incurred	41			5			—			—		15			18
Liabilities settled	(117		)	(12		)	(93		)	—		(12		)	—
Accretion	119			55			56			2		3			1
Cash flow revisions	712			31			675			2		7			—
Balance at end of period	$	4,514		$	1,527		$	2,554		$	134	$	190		$	40

The traditional electric operating companies' increases in cash flow revisions for the nine months ended September 30, 2016 primarily relate to changes in ash pond closure strategy. The increase for Georgia Power reflects its decision in June 2016 to cease operating and stop receiving coal ash at all of its ash ponds within the next three years and to eventually close all of its ash ponds either by removal, consolidation, and/or recycling for the beneficial use of coal ash or through closure in place using advanced engineering methods.

Goodwill and Other Intangible Assets

As of September 30, 2016, goodwill was as follows:

	As of September 30, 2016
	(in millions)
Southern Company	$	6,223
Southern Power	$	2

160

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

As of September 30, 2016, other intangible assets were as follows:

		As of September 30, 2016
	Estimated Useful Life	Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net
		(in millions)
Southern Company
Other intangible assets subject to amortization:
Customer relationships	11-26 years	$	268	$	(16	)	$	252
Trade names	5-28 years	158		(3		)	155
Patents	3-10 years	4		—			4
Backlog	5 years	5		—			5
Storage and transportation contracts	1-5 years	64		(4		)	60
Software and other	1-12 years	2		—			2
PPA fair value adjustments	19-20 years	405		(16		)	389
Total other intangible assets subject to amortization		$	906	$	(39	)	$	867
Other intangible assets not subject to amortization:
Federal Communications Commission licenses		$	75	$	—		$	75
Total other intangible assets		$	981	$	(39	)	$	942
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	19-20 years	$	405	$	(16	)	$	389

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Nine Months Ended
	September 30, 2016
	(in millions)
Southern Company	$	25	$	27
Southern Power	$	2	$	4

At December 31, 2015, other intangible assets consisted primarily of Southern Power's PPA fair value adjustments with a net carrying amount of $317 million. The increases in goodwill and other intangible assets primarily relate to Southern Company's acquisitions of PowerSecure on May 9, 2016 and Southern Company Gas on July 1, 2016.

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. Also see Note (I) under "Southern Company– Acquisition of PowerSecure International, Inc." and " –Merger with Southern Company Gas" for additional information.

Natural Gas for Sale

Southern Company Gas' natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a weighted average cost of gas (WACOG) basis.

161

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Nicor Gas' natural gas inventory is carried at cost on a last-in, first-out (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 layers liquidated. 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 net income.

Southern Company Gas' other natural gas inventories 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.

(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

Nicor Gas and Nicor Energy Services Company, wholly-owned subsidiaries of Southern Company Gas, and Nicor Inc. are defendants in a putative class action initially filed in September 2011 in state court in Cook County, Illinois. The plaintiffs purport to represent a class of the customers who purchased the Gas Line Comfort Guard product from Nicor Energy Services Company and variously allege 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 seek, on behalf of the classes they purport to represent, actual and punitive damages, interest, costs, attorney fees, and injunctive relief. On October 26, 2016, the court held a hearing on the plaintiffs' motion for class certification and the defendants' motion for summary judgment on all of the plaintiffs' claims. The ultimate outcome of this matter cannot be determined at this time.

Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, 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 or in Note 3 to the financial statements of each registrant in Item 8 of the Form 10-K, 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.

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 Southern Company Gas' 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.

162

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Georgia Power's environmental remediation liability as of September 30, 2016 was $23 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The PRPs at the Brunswick site have completed a removal action as ordered by the EPA. On July 29, 2016, Honeywell International, Inc. and Georgia Power entered into a consent decree with the EPA to perform additional remediation at the site. Additional response actions at the site are anticipated. In September 2015, Georgia Power entered into an allocation agreement with another PRP, under which that PRP will be responsible (as between Georgia Power and that PRP) for paying and performing certain investigation, assessment, remediation, and other incidental activities at the Brunswick site, including costs associated with implementation of the consent decree. Assessment and potential cleanup of other sites are anticipated.

The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of Georgia Power's regulatory treatment for environmental remediation expenses, these matters are not expected to have a material impact on Southern Company's or Georgia Power's financial statements.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $46 million as of September 30, 2016. 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 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.

The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management of Southern Company and Gulf Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.

Southern Company Gas' environmental remediation liability as of September 30, 2016 was $433 million based on the estimated cost of environmental investigation and remediation associated with known current and former operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of Southern Company Gas' natural gas distribution utilities, with the exception of one site representing $5 million of the total accrued remediation costs. The ultimate outcome of these matters cannot be determined at this time; however, these matters are not expected to have a material impact on Southern Company's financial statements.

In September 2015, the EPA filed an administrative complaint and notice of opportunity for hearing against Nicor Gas. The complaint alleges violation of the regulatory requirements applicable to polychlorinated biphenyls in the Nicor Gas natural gas distribution system and the EPA seeks a total civil penalty of approximately $0.3 million. The ultimate resolution of this matter cannot be determined at this time; however, the final disposition of this matter is not expected to have a material impact on Southern Company's financial statements.

FERC Matters

Municipal and Rural Associations Tariff

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

On March 31, 2016, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC for an increase in wholesale base revenues under the Municipal and Rural Associations (MRA) cost-based electric tariff, primarily as a result of placing scrubbers for Plant Daniel Units 1 and 2 in service

163

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

in November 2015. The settlement agreement, accepted by the FERC, effective for services rendered beginning May 1, 2016, provides that base rates under the MRA cost-based electric tariff will produce additional annual base revenues of $7 million. 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 December 2015 Mississippi PSC order authorizing rates providing recovery of assets previously placed in service (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 36 months, (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 $11 million through the Kemper IGCC's projected in-service date of December 31, 2016.

Fuel Cost Recovery

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At September 30, 2016, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $17 million compared to $24 million at December 31, 2015. At September 30, 2016 and December 31, 2015, the amount of over-recovered wholesale MB fuel costs included in the balance sheets was $1 million. Effective with the first billing cycle for September 2016, fuel rates decreased $11 million annually for wholesale MRA customers and $1 million annually for wholesale MB customers.

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 April 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 in May 2015 and in June 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.

164

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Retail Regulatory Matters

Alabama Power

See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters – Alabama Power" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through various regulatory clauses and accounting orders. The balance of each regulatory clause recovery on the balance sheet follows:

Regulatory Clause	Balance Sheet Line Item	September 30, 2016		December 31, 2015
		(in millions)
Rate CNP Compliance	Under recovered regulatory clause revenues	$	—	$	43
	Deferred over recovered regulatory clause revenues	23		—
Rate CNP PPA	Under recovered regulatory clause revenues	52		99
	Deferred under recovered regulatory clause revenues	87		—
Retail Energy Cost Recovery	Other regulatory liabilities, current	—		238
	Deferred over recovered regulatory clause revenues	134		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	71		75

Environmental Accounting Order

In April 2016, as part of its environmental compliance strategy, Alabama Power ceased using coal at Plant Greene County Units 1 and 2 (300 MWs representing Alabama Power's ownership interest) and began operating Units 1 and 2 solely on natural gas in June 2016 and July 2016, respectively.

Georgia Power

Rate Plans

See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail 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 separate fuel cost recovery tariffs. See "Nuclear Construction" herein and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" and Southern Company under "Retail Regulatory Matters – Georgia Power – 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 Georgia Power under "Retail Regulatory Matters – Fuel Cost Recovery" and Southern Company under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery.

Pursuant to the terms and conditions of a settlement agreement related to Southern Company's acquisition of Southern Company Gas approved by the Georgia PSC on April 14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company (collectively, Utilities) each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement;

165

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

through December 31, 2022, such net merger savings applicable to each utility will be shared on a 60/40 basis between their respective customers and the Utilities; thereafter, all merger savings will be retained by customers. See Note (I) under "Southern Company – Merger with Southern Company Gas" for additional information regarding the Merger.

Integrated Resource Plan

See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail 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 (2016 IRP).

On July 28, 2016, the Georgia PSC voted to approve the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 combustion turbine (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. On August 31, 2016, Georgia Power sold its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc.

Additionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.

The Georgia PSC approved the reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. The timing of the recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date will be deferred for consideration in Georgia Power's base rate case required to be filed by July 1, 2019.

The Georgia PSC also approved the Renewable Energy Development Initiative to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.

The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve the nuclear option at a future generation site in Stewart County, Georgia. The timing of cost recovery 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 "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.

As of September 30, 2016 and December 31, 2015, Georgia Power's over recovered fuel balance totaled $125 million and $116 million, respectively. For September 30, 2016, the balance is included in over recovered regulatory clause revenues, current on Georgia Power's Condensed Balance Sheets and in other current liabilities on Southern Company's Condensed Balance Sheets. For December 31, 2015, the balance is included in over recovered regulatory clause revenues, current and other deferred credits and liabilities on Georgia Power's Condensed Balance Sheets and in other current liabilities and other deferred credits and liabilities on Southern Company's Condensed Balance Sheets. On May 17, 2016, the Georgia PSC approved Georgia Power's request to decrease fuel rates by 15% effective June 1, 2016, which will reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017.

166

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's or Georgia Power's revenues or net income, but will affect cash flow.

Storm Damage Recovery

As of September 30, 2016, the balance in Georgia Power's regulatory asset related to storm damage was $94 million. During October 2016, Hurricane Matthew caused significant damage to Georgia Power's transmission and distribution facilities. The total amount of restoration costs related to this hurricane is estimated to be between $130 million and $155 million, which will be charged to capital accounts or to the storm damage reserve. Georgia Power is accruing $30 million annually through December 31, 2019, as provided in the 2013 ARP, to the storm damage reserve to cover the operating and maintenance costs of damages from major storms to its transmission and distribution facilities, which is recoverable through base rates. The rate of recovery of storm damage costs after December 31, 2019 is expected to be adjusted in Georgia Power's base rate case required to be filed by July 1, 2019. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's or Georgia Power's financial statements. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Storm Damage Recovery" and Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information regarding Georgia Power's storm damage reserve.

Nuclear Construction

See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail 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).

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 performance guarantees, subject to a cap. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), 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%.

On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from Chicago Bridge & Iron Company, N.V. (CB&I) and changed the name of Stone & Webster, Inc. to WECTEC Global Project Services Inc. (WECTEC). Certain obligations of Westinghouse and WECTEC under the Vogtle 3 and 4 Agreement were originally guaranteed by Toshiba Corporation (Westinghouse's parent company) and The Shaw Group Inc. (which is now a subsidiary of CB&I), respectively. On March 9, 2016, in connection with Westinghouse's acquisition of WECTEC and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. was terminated. The guarantee of Toshiba Corporation remains in place. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. Additionally, as a result of credit rating downgrades of Toshiba Corporation, Westinghouse provided the Vogtle Owners with letters of credit in an aggregate amount of $920 million in accordance with, and subject to adjustment under, the terms of the Vogtle 3 and 4 Agreement.

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The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. 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 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected construction capital costs to be borne by Georgia Power increase by 5% above the certified cost or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. In February 2013, Georgia Power requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 (from April 2016) and the fourth quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the Georgia PSC Staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate until the completion of Plant Vogtle Unit 3 or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report, which included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion. Pursuant to the Georgia PSC's procedural order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent.

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). Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; and (v) provide that Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $256 million had been paid as of September 30, 2016. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs were reflected in Georgia Power's previously disclosed in-service cost estimate. Further, as part of the settlement and Westinghouse's acquisition of WECTEC: (i) Westinghouse engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.

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The Georgia PSC has approved fourteen VCM reports covering the periods through December 31, 2015, including construction capital costs incurred, which through that date totaled $3.3 billion. On January 21, 2016, Georgia Power submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review. In accordance with the Georgia PSC's subsequent order, on April 5, 2016, Georgia Power filed supplemental information in support of the Contractor Settlement Agreement and Georgia Power's position that all construction costs to date have been prudently incurred and that the current estimated in-service capital cost and schedule are reasonable.

On October 20, 2016, Georgia Power and the Georgia PSC Staff entered into 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 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 commercial operation. The ROE used to calculate the NCCR tariff will be 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 commercially operational by December 31, 2020, then (i) the ROE for purposes of calculating the NCCR tariff will be reduced an additional 300 basis points, and may, at the Georgia PSC's discretion, be accrued to be used for the benefit of customers, until such time as the units reach commercial operation 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 upon reaching commercial operation, 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 Vogtle Cost Settlement Agreement is subject to approval by the Georgia PSC, which is scheduled to vote on this matter on December 20, 2016. Accordingly, the terms of the Vogtle Cost Settlement Agreement are subject to change and the terms of any final agreement approved by the Georgia PSC may differ materially from the terms of the Vogtle Cost Settlement Agreement. If approved, the Vogtle Cost Settlement Agreement is expected to reduce Georgia Power's revenues for the years 2016 through 2020 by a total of approximately $325 million ($115 million reduction in net income).

On August 31, 2016, Georgia Power filed the fifteenth VCM report with the Georgia PSC covering the period from January 1 through June 30, 2016 requesting approval of $141 million of construction capital costs incurred during that period. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.8 billion as of September 30, 2016. Estimated financing costs during the construction period total approximately $2.4 billion, of which $1.2 billion had been incurred through September 30, 2016.

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(UNAUDITED)

On November 1, 2016, Georgia Power submitted its 2017 NCCR tariff filing requesting that the current NCCR tariff rate remain effective for 2017 if the Georgia PSC approves the Vogtle Cost Settlement Agreement. As required under the current order, Georgia Power concurrently submitted a 2017 NCCR tariff rate calculated using the current authorized 10.95% ROE, which would result in an increase of approximately $70 million.

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 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 either to the Vogtle Owners or the Contractor or to both.

As construction continues, the risk remains that challenges with Contractor performance including 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. Contractor performance and progress in recent months, primarily associated with Unit 3, has resulted in additional current schedule pressure of approximately three to four months and has increased the likelihood of further schedule impacts to that unit. Georgia Power expects the Contractor to employ mitigation efforts to maintain the current project schedule and believes the Contractor is responsible for any related costs under the Vogtle 3 and 4 Agreement. Should Unit 3 be placed in service after June 2019, Georgia Power estimates its financing costs to be approximately $22 million per month. Additionally, Georgia Power estimates its owner's costs to be approximately $2 million per month, net of delay liquidated damages and certain incentive payments that would no longer be required to be paid per the Contractor Settlement Agreement. The Contractor's progress on Unit 4 indicates that the current estimated in-service date of June 2020 remains achievable. In addition, the IRS has allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.

Future claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units.

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.

On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as its existing wholesale contracts expire. As a result, on September 13, 2016, the Florida PSC instructed Gulf Power to file its monthly earnings surveillance reports both including and excluding its share of investment and expenses related to Plant Scherer Unit 3 that is not covered by contracts. See "Retail Base Rate Cases" and "Cost Recovery Clauses" herein for additional information.

Retail Base Rate Cases

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

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(UNAUDITED)

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. In the third quarter 2016 and in accordance with the 2013 Rate Case Settlement Agreement, Gulf Power reversed reductions previously recorded to depreciation. As a result, for the first nine months of 2016, the net reduction in depreciation was zero.

On October 12, 2016, Gulf Power filed a petition (2016 Rate Case) with the Florida PSC requesting an increase in retail rates and charges of $106.8 million based on the projected test year of January 1, 2017 through December 31, 2017 and a retail ROE of 11% compared to the current retail ROE of 10.25%. The recoverability of the costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 will be decided in this matter. The Florida PSC is expected to make a decision on the 2016 Rate Case in the second quarter 2017. Gulf Power has requested that the increase in base rates, if approved by the Florida PSC, become effective in July 2017. The ultimate outcome of this matter cannot be determined at this time.

Cost Recovery Clauses

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

Regulatory Clause	Balance Sheet Line Item	September 30, 2016		December 31, 2015
		(in millions)
Fuel Cost Recovery	Other regulatory liabilities, current	$	20	$	18
Purchased Power Capacity Recovery	Other regulatory liabilities, current	3		—
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	—		1
Environmental Cost Recovery	Other regulatory liabilities, current	5		—
Environmental Cost Recovery	Under recovered regulatory clause revenues	—		19
Energy Conservation Cost Recovery	Other regulatory liabilities, current	—		4
Energy Conservation Cost Recovery	Under recovered regulatory clause revenues	2		—

On November 2, 2016, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2017. The net effect of the approved changes is a $41 million decrease in annual revenues for 2017. In general, the decreased revenues will not have a significant impact on net income since most of the revenues will be offset by lower expenses. However, certain costs associated with the ongoing ownership and operation of Plant Scherer Unit 3 were included in the environmental clause rate, which will have an impact of approximately $11 million and $14 million of additional revenue in 2016 and 2017, respectively. The final disposition of these costs and the related impact on rates is expected to be decided by the Florida PSC in the 2016 Rate Case as discussed previously. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

As a result of the cost to comply with environmental regulations imposed by the EPA, Gulf Power retired its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) on March 31, 2016. Gulf Power filed a petition with the

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(UNAUDITED)

Florida PSC requesting permission to recover the remaining net book value of Plant Smith Units 1 and 2 and the remaining materials and supplies associated with these units as of the retirement date. In connection with this request, Gulf Power reclassified approximately $63 million to a regulatory asset, including the remaining net book value of the units and the associated materials and supplies. On August 29, 2016, the Florida PSC approved Gulf Power's request to create a regulatory asset and defer the recovery over a period to be decided in the 2016 Rate Case.

Mississippi Power

Energy Efficiency

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Energy Efficiency" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's energy efficiency programs.

On May 3, 2016, the Mississippi PSC issued an order approving the annual Energy Efficiency Cost Rider Compliance filing, which included an anticipated reduction of $2 million in retail revenues for the year ending December 31, 2016.

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 April 1, 2016, Mississippi Power submitted its annual PEP lookback filing for 2015, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC.

On July 12, 2016, Mississippi Power submitted its annual projected PEP filing for 2016 which indicated no change in rates. The filing has been suspended for review by the Mississippi PSC.

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

Environmental Compliance Overview Plan

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's ECO Plan.

On August 17, 2016, the Mississippi PSC approved Mississippi Power's revised ECO Plan filing for 2016, which requested the maximum 2% annual increase in revenues, approximately $18 million, primarily related to Plant Daniel Units 1 and 2 scrubbers being placed in service in November 2015. The revised rates became effective with the first billing cycle for September 2016. Approximately $22 million of related revenue requirements in excess of the 2% maximum was deferred for inclusion in the 2017 filing.

Fuel Cost Recovery

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

At September 30, 2016, the amount of over-recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet was $58 million compared to $71 million at December 31, 2015.

The Mississippi PSC conditionally approved a decrease of $120 million annually in fuel cost recovery rates on January 5, 2016, effective with the first billing cycle for February 2016. On August 17, 2016, the Mississippi PSC approved an additional decrease of $51 million annually in fuel cost recovery rates effective with the first billing cycle for September 2016.

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Southern Company Gas

Natural Gas Cost Recovery

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

Regulatory Infrastructure Programs

Southern Company Gas' natural gas distribution utilities are involved in ongoing capital projects associated with infrastructure improvement programs that have been previously approved by their applicable state regulatory agencies and provide an appropriate return on invested capital. These infrastructure improvement programs update or expand the natural gas distribution systems of the utilities to improve safety and reliability and meet operational flexibility and growth. Southern Company Gas currently has approved infrastructure improvement programs in six different states with initial program lengths ranging from four to 10 years, with the longest set to expire in 2025. The average annual spend under these programs ranges from $10 million to $250 million.

Southern Company Gas currently has proposed infrastructure improvement programs pending approval by the applicable state regulatory agencies in Georgia and New Jersey requesting average annual spending of $44 million through 2020 and $110 million through 2027, respectively. The ultimate outcome of these matters cannot be determined at this time.

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 will utilize an IGCC technology with an expected output capacity of 582 MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in 2013. In connection with the Kemper IGCC, Mississippi Power constructed and plans to operate approximately 61 miles of CO₂ pipeline infrastructure for the planned 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 and continues to progress towards completing the remainder of the Kemper IGCC, including the gasifiers and the gas clean-up facilities. The initial production of syngas began on July 14, 2016 for gasifier "B" and on September 13, 2016 for gasifier "A." On October 11, 2016, the Kemper IGCC began testing using clean syngas from gasifier "A" and the related gas clean-up systems to produce electricity. Late on October 31, 2016, gasifier "A" experienced challenges associated with the ash removal systems, and on November 2, 2016, Mississippi Power determined a maintenance outage on gasifier "A" is needed to make improvements to the ash removal systems.

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Therefore, Mississippi Power has re-sequenced activities, and gasifier "B" is now expected to progress through testing and begin producing electricity during the gasifier "A" outage. In light of these changes, Mississippi Power has determined that integrated operation of both gasifiers will not occur by mid-November and has revised the expected in-service date for the remainder of the Kemper IGCC to December 31, 2016. The remaining schedule reflects the time expected to achieve production of electricity using gasifier "B," complete gasifier "A" outage activities, and resume electricity production using gasifier "A," as well as to complete the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.

Recovery of the costs subject to the cost cap and 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) remains subject to review and approval by the Mississippi PSC. 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 September 30, 2016 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	$	5.52		$	5.30
Lignite Mine and Equipment	0.21		0.23			0.23
CO2 Pipeline Facilities	0.14		0.11			0.11
AFUDC(d)	0.17		0.75			0.71
Combined Cycle and Related Assets Placed in Service – Incremental(e)	—		0.04			0.03
General Exceptions	0.05		0.10			0.09
Deferred Costs(e)	—		0.21			0.20
Additional DOE Grants(f)	—		(0.14		)	(0.14		)
Total Kemper IGCC	$	2.97	$	6.82		$	6.53

(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. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (e) 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 September 30, 2016. 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 September 30, 2016. 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.

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Of the total costs, including post-in-service costs for the lignite mine, incurred as of September 30, 2016, $3.70 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 $2.63 billion), $6 million in other property and investments, $81 million in fossil fuel stock, $46 million in materials and supplies, $33 million in other regulatory assets, current, $177 million in other regulatory assets, deferred, $4 million in other current assets, and $9 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 $88 million ($54 million after tax) in the third quarter 2016 and a total of $222 million ($137 million after tax) for the nine months ended September 30, 2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.63 billion ($1.63 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through September 30, 2016. The increase to the cost estimate in the third quarter of 2016 primarily reflects $53 million for the extension of the Kemper IGCC's projected in-service date from October 31, 2016 to December 31, 2016 and increased efforts related to operational readiness and challenges in start-up and commissioning activities, including the cost of repairs and modifications to gasifier "B" and mechanical improvements to coal feed and ash management systems, as well as certain post-in-service costs expected to be subject to the cost cap. The year-to-date increase to the cost estimate also includes $78 million for the extension of the Kemper IGCC's projected in-service date from August 31, 2016 to October 31, 2016. In addition, during the start-up and commissioning process, Mississippi Power is identifying potential improvement projects that ultimately may be completed subsequent to placing the remainder of the Kemper IGCC in service. If completed, such improvement projects would be expected to enhance plant performance, safety, and/or operations. The related potential costs 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 December 31, 2016 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 with respect to the Kemper IGCC beyond December 31, 2016 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 $15 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 "2015 Rate Case" herein.

Mississippi Power's analysis of the time needed to complete the start-up and commissioning activities for the Kemper IGCC will continue until the remaining Kemper IGCC assets are placed in service. The next steps for the facility include the testing and production of electricity using clean syngas from gasifier "B," as well as the generation of electricity using clean syngas from gasifier "A," which are scheduled to occur by the end of November. If integrated operation of both gasifiers does not occur by mid-December, the expected in-service date and related cost estimate for the Kemper IGCC likely would require further revision. 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, 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.

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(UNAUDITED)

Rate Recovery of Kemper IGCC Costs

See "FERC Matters" herein for additional information regarding Mississippi Power's MRA cost based tariff relating to recovery of a portion of the Kemper IGCC costs from Mississippi Power's wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See Note (G) under "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" for additional tax information related to the Kemper IGCC.

The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity.

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 based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with 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.

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).

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 September 30, 2016, AFUDC recorded since the original May 2014 estimated in-service date for the Kemper IGCC has totaled $352 million. 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.

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 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 below.

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(UNAUDITED)

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 with the first billing cycle for 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 entered into between Mississippi Power and the Mississippi Public Utilities Staff (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. Mississippi Power continues to evaluate its alternatives with respect to its investment and related costs associated with the 15% undivided interest.

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.

On July 27, 2016, the Court dismissed Greenleaf CO₂ Solutions, LLC (Greenleaf) motion for reconsideration of its previous decision to dismiss Greenleaf's appeal of the In-Service Asset Rate Order.

In addition to current estimated costs at September 30, 2016 of $6.82 billion, Mississippi Power anticipates that it will incur additional expenses in excess of current rates associated with operating the Kemper IGCC after it is placed in service until the Kemper IGCC cost recovery approach is finalized, which are expected to be material. These costs include, but are not limited to, regulatory costs, operational costs in excess of current rates, taxes, and additional carrying costs. Mississippi Power expects to request authority from the Mississippi PSC and 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. Mississippi Power is required to file its next rate request with the Mississippi PSC related to cost recovery for the Kemper IGCC by June 3, 2017. See "Regulatory Assets and Liabilities" below for additional information. As part of that filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation for the in-service assets.

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 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.

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 proceeding 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 following the start of commercial operations. Certain costs, including

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(UNAUDITED)

operations and maintenance, are materially higher than the amounts presented in the CPCN proceedings. 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. Mississippi Power expects the Mississippi PSC to address these issues in connection with its next rate request.

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 September 30, 2016, the balance associated with these regulatory assets was $105 million, of which $33 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $105 million as of September 30, 2016. The amortization period for these assets is expected to be determined by the Mississippi PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews. See "FERC Matters" herein for 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 September 30, 2016, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $7 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 will own 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

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(UNAUDITED)

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 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.

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, where the case is currently pending. However, the plaintiffs have filed a request to remand the case back to state court. 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 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.

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.

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(UNAUDITED)

(C) FAIR VALUE MEASUREMENTS

As of September 30, 2016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using
As of September 30, 2016:	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)	$	203	$	190	$	—	$	—	$	393
Interest rate derivatives	—		19		—		—		19
Foreign currency derivatives	—		23		—		—		23
Nuclear decommissioning trusts(b)	660		938		—		18		1,616
Cash equivalents	1,680		—		—		—		1,680
Other investments	9		—		1		—		10
Total	$	2,552	$	1,170	$	1	$	18	$	3,741
Liabilities:
Energy-related derivatives	$	267	$	274	$	—	$	—	$	541
Interest rate derivatives	—		7		—		—		7
Foreign currency derivatives	—		24		—		—		24
Contingent consideration	—		—		18		—		18
Total	$	267	$	305	$	18	$	—	$	590
Alabama Power
Assets:
Energy-related derivatives	$	—	$	8	$	—	$	—	$	8
Nuclear decommissioning trusts(c)
Domestic equity	373		72		—		—		445
Foreign equity	49		49		—		—		98
U.S. Treasury and government agency securities	—		22		—		—		22
Corporate bonds	22		148		—		—		170
Mortgage and asset backed securities	—		21		—		—		21
Private Equity	—		—		—		18		18
Other	—		7		—		—		7
Cash equivalents	410		—		—		—		410
Total	$	854	$	327	$	—	$	18	$	1,199
Liabilities:
Energy-related derivatives	$	—	$	21	$	—	$	—	$	21

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(UNAUDITED)

	Fair Value Measurements Using
As of September 30, 2016:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	15	$	—	$	—	$	15
Interest rate derivatives	—		10		—		—		10
Nuclear decommissioning trusts(c) (d)
Domestic equity	197		1		—		—		198
Foreign equity	—		125		—				125
U.S. Treasury and government agency securities	—		59		—		—		59
Municipal bonds	—		70		—		—		70
Corporate bonds	—		172		—		—		172
Mortgage and asset backed securities	—		149		—		—		149
Other	19		43		—		—		62
Cash equivalents	32		—		—		—		32
Total	$	248	$	644	$	—	$	—	$	892
Liabilities:
Energy-related derivatives	$	—	$	16	$	—	$	—	$	16
Gulf Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	—	$	1
Cash equivalents	20		—		—		—		20
Total	$	20	$	1	$	—	$	—	$	21
Liabilities:
Energy-related derivatives	$	—	$	51	$	—	$	—	$	51
Interest rate derivatives	—		6		—		—		6
Total	$	—	$	57	$	—	$	—	$	57
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	—	$	1
Cash equivalents	137		—		—		—		137
Total	$	137	$	1	$	—	$	—	$	138
Liabilities:
Energy-related derivatives	$	—	$	21	$	—	$	—	$	21
Interest rate derivatives	—		1		—		—		1
Total	$	—	$	22	$	—	$	—	$	22

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(UNAUDITED)

	Fair Value Measurements Using
As of September 30, 2016:	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	$	—	$	3	$	—	$	—	$	3
Foreign currency derivatives	—		23		—		—		23
Cash equivalents	647		—		—		—		647
Total	$	647	$	26	$	—	$	—	$	673
Liabilities:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Foreign currency derivatives	—		24		—		—		24
Contingent consideration	—		—		18		—		18
Total	$	—	$	27	$	18	$	—	$	45

(a) Excludes $7 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value.

(b) For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.

(c) Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies.

(d) Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of September 30, 2016, approximately $42 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 $49 million and $116 million, respectively, for the three and nine months ended September 30, 2016, and decreased by $65 million and $33 million, respectively, for the three and nine months ended September 30, 2015. Alabama Power recorded an increase in fair value of $26 million and $66 million, respectively, for the three and nine months ended September 30, 2016 and a decrease in fair value of $39 million and $19 million, respectively, for the three and nine months ended September 30, 2015 as a change in regulatory liabilities related to its AROs. Georgia Power recorded an increase in fair value of $23 million and $50 million, respectively, for the three and nine months ended September 30, 2016 and a decrease in fair value of $26 million and $14 million, respectively, for the three and nine months ended September 30, 2015 as a change in its regulatory asset related to its AROs.

Valuation Methodologies

The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present

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(UNAUDITED)

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 10-year period beginning at the commercial operation date. The obligation is measured at fair value using significant inputs such as forecasted facility generation in MW-hours, 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 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 September 30, 2016, the fair value measurements of private equity investments held in the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:

As of September 30, 2016:	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company	$	18	$	27	Not Applicable	Not Applicable
Alabama Power	$	18	$	27	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 ten years.

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(UNAUDITED)

As of September 30, 2016, 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	$	43,668	$	47,227
Alabama Power	$	7,091	$	7,961
Georgia Power	$	10,398	$	11,582
Gulf Power	$	1,184	$	1,267
Mississippi Power	$	2,981	$	2,967
Southern Power	$	4,608	$	4,821

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 the registrants.

(D) STOCKHOLDERS' EQUITY

Earnings per Share

For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:

	Three Months Ended September 30, 2016	Three Months Ended September 30, 2015	Nine Months Ended September 30, 2016	Nine Months Ended September 30, 2015
	(in millions)
As reported shares	968	910	940	910
Effect of options and performance share award units	7	2	5	3
Diluted shares	975	912	945	913

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 andnine months ended September 30, 2016 and were 15 million and 1 million for the three and nine months ended September 30, 2015, respectively.

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(UNAUDITED)

Changes in Stockholders' Equity

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

	Number of Common Shares			Common Stockholders' Equity			Preferred and Preference Stock of Subsidiaries						Total Stockholders' Equity
	Issued	Treasury								Noncontrolling Interests(*)
	(in thousands)			(in millions)
Balance at December 31, 2015	915,073	(3,352	)	$	20,592		$	609		$	781		$	21,982
Consolidated net income attributable to Southern Company	—	—		2,226			—			—			2,226
Other comprehensive income (loss)	—	—		(95		)	—			—			(95		)
Stock issued	65,725	2,599		3,265			—			—			3,265
Stock-based compensation	—	—		119			—			—			119
Cash dividends on common stock	—	—		(1,553		)	—			—			(1,553		)
Contributions from noncontrolling interests	—	—		—			—			357			357
Distributions to noncontrolling interests	—	—		—			—			(21		)	(21		)
Purchase of membership interests from noncontrolling interests	—	—		—			—			(129		)	(129		)
Net income attributable to noncontrolling interests	—	—		—			—			36			36
Other	—	(46	)	(7		)	—			—			(7		)
Balance at September 30, 2016	980,798	(799	)	$	24,547		$	609		$	1,024		$	26,180
Balance at December 31, 2014	908,502	(725	)	$	19,949		$	756		$	221		$	20,926
Consolidated net income attributable to Southern Company	—	—		2,096			—			—			2,096
Other comprehensive income (loss)	—	—		(7		)	—			—			(7		)
Stock issued	3,769	—		136			—			—			136
Stock-based compensation	—	—		78			—			—			78
Stock repurchased, at cost	—	(2,599	)	(115		)	—			—			(115		)
Cash dividends on common stock	—	—		(1,465		)	—			—			(1,465		)
Preference stock redemption	—	—		—			(150		)	—			(150		)
Contributions from noncontrolling interests	—	—		—			—			429			429
Distributions to noncontrolling interests	—	—		—			—			(13		)	(13		)
Net income attributable to noncontrolling interests	—	—		—			—			13			13
Other	—	(8	)	(8		)	3			—			(5		)
Balance at September 30, 2015	912,271	(3,332	)	$	20,664		$	609		$	650		$	21,923

(*) Primarily related to Southern Power Company and excludes redeemable noncontrolling interests. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

185

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(UNAUDITED)

(E) FINANCING

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 outstanding requiring liquidity support as of September 30, 2016 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 September 30, 2016, the traditional electric operating companies had approximately $358 million (comprised of approximately $87 million at Alabama Power, $250 million at Georgia Power, and $21 million at Gulf 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 September 30, 2016:

	Expires												Executable Term Loans				Due Within One Year
Company	2016		2017		2018		2020		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)								(in millions)				(in millions)				(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	50		65		165		—		280		280		45		—		45		70
Mississippi Power	100		75		—		—		175		150		—		15		15		160
Southern Power Company(b)	—		—		—		600		600		532		—		—		—		—
Southern Company Gas(c)	—		75		1,925		—		2,000		1,947		—		—		—		—
Other	—		55		—		—		55		55		20		—		20		35
Southern Company Consolidated	$	150	$	305	$	3,590	$	4,400	$	8,445	$	8,281	$	65	$	15	$	80	$	300

(a) Represents the Southern Company parent entity.

(b) Excluding its subsidiaries. See "Southern Power Project Credit Facilities" below and Note (I) under "Southern Power" for additional information.

(c) Southern Company Gas 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 restricted for working capital needs of Nicor Gas.

On May 24, 2016, Southern Company's $8.1 billion Bridge Agreement to provide Merger financing, to the extent necessary, was terminated.

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.

Southern Power Project Credit Facilities

In connection with the construction of solar facilities by RE Garland Holdings LLC, RE Roserock LLC, and RE Tranquillity LLC, indirect subsidiaries of Southern Power, each subsidiary entered into separate credit agreements (Project Credit Facilities), which are non-recourse to Southern Power (other than the subsidiary party to the agreement). Each Project Credit Facility provides (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 is secured by the membership interests of the respective project company, with proceeds directed to finance project costs related to the respective

186

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

solar facilities. Each Project Credit Facility is secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The table below summarizes each Project Credit Facility as of September 30, 2016.

Project	Maturity Date	Construction Loan Facility		Bridge Loan Facility		Total Loan Facility		Loan Facility Undrawn		Letter of Credit Facility		Letter of Credit Facility Undrawn
		(in millions)
Garland	Earlier of PPA COD or November 30, 2016	$	86	$	308	$	394	$	21	$	49	$	23
Roserock	Earlier of PPA COD or November 30, 2016(*)	63		180		243		34		23		16
Tranquillity	October 14, 2016	86		172		258		12		77		26
Total		$	235	$	660	$	895	$	67	$	149	$	65

(*) Subsequent to September 30, 2016, Roserock extended the maturity date of its Project Credit Facility to December 31, 2016.

The Project Credit Facilities above had total amounts outstanding as of September 30, 2016 of $828 million at a weighted average interest rate of 2.05%. For the three-month period ended September 30, 2016, these credit agreements had a maximum amount outstanding of $828 million and an average amount outstanding of $805 million at a weighted average interest rate of 2.02%.

Furthermore, in connection with the acquisition of the Henrietta solar facility on July 1, 2016, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. For the three-month period ended September 30, 2016, this credit agreement had a maximum amount outstanding of $217 million and an average amount outstanding of $137 million at a weighted average interest rate of 2.21%.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first nine months of 2016:

Company	Senior Note Issuances		Senior Note Maturities and Redemptions		Revenue Bond Maturities Redemptions and Repurchases		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions and Maturities(a)
	(in millions)
Southern Company(b)	$	8,500	$	500	$	—	$	800		$	—
Alabama Power	400		200		—		45			—
Georgia Power	650		700		4		300			5
Gulf Power	—		125		—		2			—
Mississippi Power	—		—		—		1,100			652
Southern Power	1,531		—		—		63			84
Southern Company Gas(c)	900		300		—		—			—
Other	—		—		—		—			60
Elimination(d)	—		—		—		(200		)	(225		)
Southern Company Consolidated	$	11,981	$	1,825	$	4	$	2,110		$	576

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

(b) Represents the Southern Company parent entity.

(c) Reflects only long-term debt financing activities occurring subsequent to completion of the Merger. The senior notes were issued by Southern Company Gas Capital and guaranteed by Southern Company Gas.

(d) Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements.

Southern Company

In May 2016, Southern Company issued the following series of senior notes for an aggregate principal amount of $8.5 billion:

• $0.5 billion of 1.55% Senior Notes due July 1, 2018;

• $1.0 billion of 1.85% Senior Notes due July 1, 2019;

• $1.5 billion of 2.35% Senior Notes due July 1, 2021;

• $1.25 billion of 2.95% Senior Notes due July 1, 2023;

• $1.75 billion of 3.25% Senior Notes due July 1, 2026;

• $0.5 billion of 4.25% Senior Notes due July 1, 2036; and

• $2.0 billion of 4.40% Senior Notes due July 1, 2046.

The net proceeds were used to fund a portion of the consideration for the Merger and related transaction costs and for other general corporate purposes.

In September 2016, Southern Company issued $800 million aggregate principal amount of Series 2016A 5.25% Junior Subordinated Notes due October 1, 2076. The proceeds were used to repay short-term indebtedness that was incurred to repay at maturity $500 million aggregate principal amount of Southern Company's Series 2011A 1.95% Senior Notes due September 1, 2016 and for other general corporate purposes.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Alabama Power

In January 2016, Alabama Power issued $400 million aggregate principal amount of Series 2016A 4.30% Senior Notes due January 2, 2046. The proceeds were used to repay at maturity $200 million aggregate principal amount of Alabama Power's Series FF 5.20% Senior Notes due January 15, 2016 and for general corporate purposes, including Alabama Power's continuous construction program.

In March 2016, Alabama Power entered into three bank term loan agreements with maturity dates of March 2021, in an aggregate principal amount of $45 million, one of which bears interest at 2.38% per annum and two of which bear interest based on three-month LIBOR.

Georgia Power

In March 2016, Georgia Power issued $325 million aggregate principal amount of Series 2016A 3.25% Senior Notes due April 1, 2026 and $325 million aggregate principal amount of Series 2016B 2.40% Senior Notes due April 1, 2021. An amount equal to the proceeds from the Series 2016A 3.25% Senior Notes due April 1, 2026 will be allocated to eligible green expenditures, including financing of or investments in solar generating facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar or wind generating facilities. The proceeds from the Series 2016B 2.40% Senior Notes due April 1, 2021 were used to repay at maturity $250 million aggregate principal amount of Georgia Power's Series 2013B Floating Rate Senior Notes due March 15, 2016, to repay a portion of Georgia Power's short-term indebtedness, and for general corporate purposes, including Georgia Power's continuous construction program.

In June 2016, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $300 million at a 2.571% interest rate through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.

Gulf Power

In May 2016, Gulf Power redeemed $125 million aggregate principal amount of its Series 2011A 5.75% Senior Notes due June 1, 2051.

Also in May 2016, Gulf Power entered into an 11-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $100 million aggregate principal amount and the proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes.

Mississippi Power

On January 28, 2016, Mississippi Power issued a promissory note for up to $275 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During the first nine months of 2016, Mississippi Power borrowed $100 million under this promissory note and an additional $100 million under a separate promissory note issued to Southern Company in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. Mississippi Power borrowed $900 million on March 8, 2016 under the term loan agreement and the remaining $300 million on October 7, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and the remaining $300 million to repay at maturity Mississippi Power's Series 2011A 2.35% Senior Notes due October 15, 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR. On June 27, 2016, Mississippi Power received a capital contribution from Southern Company of $225 million, the proceeds of which were used to repay to Southern Company a portion of the promissory note issued in November 2015. As of September 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.

In June 2016, Mississippi Power renewed a $10 million short-term note, which matures on June 30, 2017, bearing interest based on three-month LIBOR.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Southern Power

In June 2016, Southern Power issued €600 million aggregate principal amount of Series 2016A 1.00% Senior Notes due June 20, 2022 and €500 million aggregate principal amount of Series 2016B 1.85% Senior Notes due June 20, 2026. The proceeds are being allocated to renewable energy generation projects. Southern Power's obligations under its euro-denominated fixed-rate notes were effectively converted to fixed-rate U.S. dollars at issuance through cross-currency swaps, removing foreign currency exchange risk associated with the interest and principal payments. See Note (H) under "Foreign Currency Derivatives" for additional information.

In September 2016, Southern Power issued $290 million aggregate principal amount of Series 2016C 2.75% Senior Notes due September 20, 2023. The proceeds were used for general corporate purposes, including Southern Power's growth strategy and continuous construction program, as well as repayment of amounts outstanding under the Project Credit Facilities.

Also in September 2016, Southern Power repaid $80 million of an outstanding $400 million floating rate bank loan and extended the maturity date of the remaining $320 million from September 2016 to September 2018. In addition, Southern Power entered into a $60 million aggregate principal amount floating rate bank loan bearing interest based on one-month LIBOR due September 2017. The proceeds were used to repay existing indebtedness and for other general corporate purposes.

In addition, Southern Power issued $34 million in letters of credit during the nine months ended September 30, 2016.

During the nine months ended September 30, 2016, Southern Power's subsidiaries incurred an additional $691 million of short-term borrowings pursuant to the Project Credit Facilities at a weighted average interest rate of 2.05%. Furthermore, in connection with the acquisition of the Henrietta solar facility, a subsidiary of Southern Power assumed a $217 million construction loan, which was fully repaid prior to September 30, 2016. In addition, Southern Power's subsidiaries issued $16 million in letters of credit.

Southern Company Gas

In September 2016, Southern Company Gas Capital issued $350 million aggregate principal amount of 2.45% Senior Notes due October 1, 2023 and $550 million aggregate principal amount of 3.95% Senior Notes due October 1, 2046, both of which are guaranteed by Southern Company Gas. The proceeds were used to repay a $360 million promissory note issued to Southern Company for the purpose of funding a portion of the purchase price for Southern Company Gas' 50% equity interest in SNG, to fund Southern Company Gas' purchase of Piedmont Natural Gas Company, Inc.'s (Piedmont) interest in SouthStar Energy Services, LLC (SouthStar), to make a voluntary pension contribution, to repay at maturity $120 million aggregate principal amount of Series A Floating Rate Senior Notes due October 27, 2016, and for general corporate purposes. See Note (I) under "Southern Company– Investment in Southern Natural Gas" and " – Acquisition of Remaining Interest in SouthStar" for additional information regarding Southern Company Gas' investment in SNG and purchase of Piedmont's interest in SouthStar, respectively.

(F) RETIREMENT BENEFITS

Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2016. 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.

See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K for additional information.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Southern Company Gas has a defined benefit, trusteed, pension plan covering eligible employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended. Southern Company Gas made a $125 million voluntary contribution to the qualified pension plan in September 2016. Southern Company Gas also provides certain defined benefit and defined contribution plans for a selected group of management and highly compensated employees. Benefits under these non-qualified plans are largely unfunded and benefits are primarily paid using corporate assets. 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.

Components of the net periodic benefit costs for the three and nine months ended September 30, 2016 and 2015 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended September 30, 2016
Service cost	$	68		$	14		$	17		$	3		$	3
Interest cost	110			23			34			5			4
Expected return on plan assets	(203		)	(46		)	(64		)	(9		)	(9		)
Amortization:
Prior service costs	3			1			1			—			1
Net (gain)/loss	45			10			14			2			2
Net periodic pension cost	$	23		$	2		$	2		$	1		$	1
Nine Months Ended September 30, 2016
Service cost	$	192		$	43		$	52		$	9		$	9
Interest cost	311			71			102			14			14
Expected return on plan assets	(577		)	(138		)	(193		)	(26		)	(26		)
Amortization:
Prior service costs	10			2			4			1			1
Net (gain)/loss	120			30			41			5			5
Net periodic pension cost	$	56		$	8		$	6		$	3		$	3
Three Months Ended September 30, 2015
Service cost	$	65		$	14		$	18		$	3		$	3
Interest cost	111			26			38			5			5
Expected return on plan assets	(181		)	(44		)	(62		)	(8		)	(8		)
Amortization:
Prior service costs	6			2			2			1			—
Net (gain)/loss	53			14			19			2			3
Net periodic pension cost	$	54		$	12		$	15		$	3		$	3
Nine Months Ended September 30, 2015
Service cost	$	193		$	44		$	54		$	9		$	9
Interest cost	333			79			115			15			16
Expected return on plan assets	(543		)	(133		)	(188		)	(24		)	(25		)
Amortization:
Prior service costs	19			5			7			1			1
Net (gain)/loss	161			41			57			7			8
Net periodic pension cost	$	163		$	36		$	45		$	8		$	9

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended September 30, 2016
Service cost	$	6		$	1		$	2		$	—		$	—
Interest cost	20			5			7			1			—
Expected return on plan assets	(16		)	(6		)	(6		)	—			—
Amortization:
Prior service costs	1			1			—			—			—
Net (gain)/loss	5			—			3			—			1
Net periodic postretirement benefit cost	$	16		$	1		$	6		$	1		$	1
Nine Months Ended September 30, 2016
Service cost	$	17		$	4		$	5		$	1		$	1
Interest cost	55			14			22			2			2
Expected return on plan assets	(44		)	(19		)	(17		)	(1		)	(1		)
Amortization:
Prior service costs	4			3			1			—			—
Net (gain)/loss	12			1			7			—			1
Net periodic postretirement benefit cost	$	44		$	3		$	18		$	2		$	3
Three Months Ended September 30, 2015
Service cost	$	6		$	1		$	2		$	1		$	—
Interest cost	20			5			9			—			1
Expected return on plan assets	(15		)	(6		)	(6		)	—			—
Amortization:
Prior service costs	1			2			—			—			—
Net (gain)/loss	4			—			2			—			—
Net periodic postretirement benefit cost	$	16		$	2		$	7		$	1		$	1
Nine Months Ended September 30, 2015
Service cost	$	17		$	4		$	5		$	1		$	1
Interest cost	59			15			26			2			3
Expected return on plan assets	(44		)	(19		)	(18		)	(1		)	(1		)
Amortization:
Prior service costs	3			3			—			—			—
Net (gain)/loss	13			1			8			—			—
Net periodic postretirement benefit cost	$	48		$	4		$	21		$	2		$	3

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(G) INCOME TAXES

See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for additional tax information.

Current and Deferred Income Taxes

Net Operating Loss

Southern Company expects to be in a consolidated net operating loss (NOL) position for income tax purposes for the 2016 tax year. The NOL will limit the amount of positive cash flows resulting from bonus depreciation, ITCs, and PTCs for the tax year and will significantly increase deferred tax assets for the NOL and tax credit carryforwards. Portions of the NOL are expected to be carried back to prior tax years and forward to the 2017 tax year, which could further increase existing tax credit carryforwards. The ultimate outcome of this matter cannot be determined at this time.

Tax Credit Carryforwards

Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $1.2 billion and $26 million, respectively, as of September 30, 2016 and $554 million and $1 million, respectively, as of December 31, 2015. Additionally, Southern Company had $165 million of state ITC carryforwards for the state of Georgia as of September 30, 2016 compared to $188 million as of December 31, 2015. See "Unrecognized Tax Benefits" herein for further information.

The federal ITC carryforwards as of September 30, 2016 begin expiring in 2034 but are expected to be utilized by the end of 2021. The PTC carryforwards as of September 30, 2016 begin expiring in 2035 but are expected to be utilized by the end of 2021. The state ITC carryforwards for the state of Georgia as of September 30, 2016 expire between 2020 and 2026 but are expected to be fully utilized by the end of 2022.

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 29.1% for the nine months ended September 30, 2016 compared to 33.5% for the corresponding period in 2015. The effective tax rate decrease was primarily due to increased federal income tax benefits from ITCs and PTCs at Southern Power, partially offset by the impact of additional state income tax benefits recognized in 2015.

Mississippi Power

Mississippi Power's effective tax (benefit) rate was (276.2)% for the nine months ended September 30, 2016 compared to (20.9)% for the corresponding period in 2015. The effective tax rate decrease was primarily due to an increase in tax benefits related to the estimated probable losses on construction of the Kemper IGCC and an increase in non-taxable AFUDC equity.

Southern Power

Southern Power's effective tax (benefit) rate was (88.9)% for the nine months ended September 30, 2016 compared to 6.9% for the corresponding period in 2015. The effective tax rate decrease was primarily due to increased federal income tax benefits from ITCs related to solar projects expected to be placed in service in 2016 and additional PTCs related to wind projects in 2016 compared to 2015.

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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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Changes during 2016 for unrecognized tax benefits were as follows:

	Mississippi Power		Southern Power			Southern Company
	(in millions)
Unrecognized tax benefits as of December 31, 2015	$	421	$	8		$	433
Tax positions from current periods	—		12			12
Tax positions from prior periods	18		(1		)	13
Balance as of September 30, 2016	$	439	$	19		$	458

The tax positions from current periods primarily relate to federal income tax benefits from deferred ITCs and ITCs impacting the estimated annual effective tax rate for interim reporting purposes. The tax positions from prior periods primarily relate to federal income tax benefits from ITCs, and from deductions for Kemper IGCC-related research and experimental (R&E) expenditures. See "Section 174 Research and Experimental Deduction" below for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.

The impact on the effective tax rate, if recognized, is as follows:

	As of September 30, 2016						As of December 31, 2015
	Mississippi Power		Southern Power		Southern Company		Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	1	$	19	$	20	$	10
Tax positions not impacting the effective tax rate	438		—		438		423
Balance of unrecognized tax benefits	$	439	$	19	$	458	$	433

The tax positions impacting the effective tax rate primarily relate to federal income tax benefits from ITCs and Southern Company's estimate of the uncertainty related to the amount of those benefits. The impact on the effective tax rate is determined based on the amount of ITCs, which is uncertain. If these tax positions are not able to be recognized due to a federal audit adjustment equal to the estimated amount, the amount of tax credit carryforwards discussed above would be reduced by approximately $94 million.

Accrued interest for all tax positions other than Section 174 R&E deductions disclosed below was immaterial for all periods presented.

All of the registrants classify interest on tax uncertainties as interest expense. None of the registrants accrued any penalties on uncertain tax positions.

It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 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. The audits for the Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.

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(UNAUDITED)

Section 174 Research and Experimental Deduction

Southern Company has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and has 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. Subsequent to September 30, 2016, Southern Company and Mississippi Power responded to a notice of proposed assessment from the IRS, which is continuing to review the underlying support for the deduction. Due to the uncertainty related to this tax position, Southern Company and Mississippi Power had related unrecognized tax benefits associated with these R&E deductions of approximately $438 million and associated interest of $24 million as of September 30, 2016. It is reasonably possible that this matter will 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 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. 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 of Southern Company Gas have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain 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 traditional electric operating companies (with respect to wholesale generating capacity), Southern Power, and Southern Company Gas 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, Southern Power, and Southern Company Gas may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity and natural gas.

Southern Company Gas uses storage and transportation capacity contracts to manage market price risks. Southern Company Gas purchases natural gas for storage when the current market price paid to buy and transport natural gas plus the cost to store and finance the natural gas is less than the market price Southern Company Gas will receive in the future, resulting in a positive net operating margin. Southern Company Gas uses New York Mercantile Exchange (NYMEX) futures and over-the-counter (OTC) contracts to sell natural gas at that future price to substantially protect the operating margin ultimately realized when the stored natural gas is sold. Southern Company Gas also enters into transactions to secure transportation capacity between delivery points in order to

195

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(UNAUDITED)

serve its customers and various markets. Southern Company Gas uses NYMEX futures and OTC contracts to capture the price differential between the locations served by the capacity in order to substantially protect the operating margin ultimately realized when natural gas is physically flowed between the delivery points. These contracts generally meet the definition of derivatives, but are not designated as hedges for accounting purposes.

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 Southern Company Gas' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.

• Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.

• Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

At September 30, 2016, 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(*)	540	2020	2022
Alabama Power	75	2020	—
Georgia Power	148	2020	—
Gulf Power	57	2020	—
Mississippi Power	37	2020	—
Southern Power	9	2017	2016

(*) Southern Company Gas' derivative instruments are comprised of 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 3.2 billion mmBtu and short natural gas positions of 2.9 billion mmBtu as of September 30, 2016.

In addition to the volumes discussed in the above table, 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 5 million mmBtu for Southern Company and Georgia Power.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending September 30, 2017 are immaterial for all registrants.

Interest Rate Derivatives

Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the 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.

197

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At September 30, 2016, the following interest rate derivatives were outstanding:

	Notional Amount			Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date		Fair Value Gain (Loss) at September 30, 2016
	(in millions)							(in millions)
Cash Flow Hedges of Forecasted Debt
Gulf Power	$	80		3-month LIBOR	2.32%	December 2026		$	(6	)
Cash Flow Hedges of Existing Debt
Mississippi Power	900			1-month LIBOR	0.79%	March 2018		(1		)
Fair Value Hedges of Existing Debt
Southern Company(a)	250			1.30%	3-month LIBOR + 0.17%	August 2017		1
Southern Company(a)	300			2.75%	3-month LIBOR + 0.92%	June 2020		9
Georgia Power	250			5.40%	3-month LIBOR + 4.02%	June 2018		2
Georgia Power	200			4.25%	3-month LIBOR + 2.46%	December 2019		5
Georgia Power	500			1.95%	3-month LIBOR + 0.76%	December 2018		2
Derivatives not Designated as Hedges
Southern Power	65		(b)(e)	3-month LIBOR	2.50%	October 2016	(f)	—
Southern Power	47		(c)(e)	3-month LIBOR	2.21%	October 2016	(f)	—
Southern Power	65		(d)(e)	3-month LIBOR	2.21%	November 2016	(g)	—
Southern Company Consolidated	$	2,657						$	12

(a) Represents the Southern Company parent entity.

(b) Swaption at RE Tranquillity LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(c) Swaption at RE Roserock LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information. Subsequent to September 30, 2016, Roserock extended the maturity date of its swaption to December 31, 2016.

(d) Swaption at RE Garland Holdings LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(e) Amortizing notional amount.

(f) Represents the mandatory settlement date. Settlement will be based on a 15-year amortizing swap.

(g) Represents the mandatory settlement date. Settlement will be based on a 12-year amortizing swap.

The estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending September 30, 2017 are $(21) million for Southern Company and immaterial for all other registrants. Southern Company and certain subsidiaries have deferred gains and losses that are expected to be amortized into earnings through 2046.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

At September 30, 2016, the following foreign currency derivatives were outstanding:

	Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at September 30, 2016
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	(2	)
Southern Power	564		3.78%	500		1.85%	June 2026	1
Total	$	1,241		€	1,100			$	(1	)

The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to earnings for the next 12-month period ending September 30, 2017 are $(12) million for Southern Company and Southern Power.

Derivative Financial Statement Presentation and Amounts

Derivative contracts of Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are presented on a net basis in the financial statements to the extent that the contracts are subject to netting arrangements. Some of these energy-related and interest rate derivative contracts 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.

At September 30, 2016, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:

	As of September 30, 2016
Derivative Category and Balance Sheet Location	Assets		Liabilities
	(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	$	20	$	(62	)
Other deferred charges and assets/Other deferred credits and liabilities	13		(53		)
Total derivatives designated as hedging instruments for regulatory purposes	$	33	$	(115	)
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	$	4	$	(6	)
Other deferred charges and assets/Other deferred credits and liabilities	—		(1		)

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	As of September 30, 2016
Derivative Category and Balance Sheet Location	Assets			Liabilities
	(in millions)
Interest rate derivatives:
Other current assets/Liabilities from risk management activities, net of collateral	$	8		$	(7	)
Other deferred charges and assets/Other deferred credits and liabilities	11			—
Foreign currency derivatives:
Other current assets/Liabilities from risk management activities, net of collateral	$	—		$	(24	)
Other deferred charges and assets/Other deferred credits and liabilities	23			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	46		$	(38	)
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Liabilities from risk management activities, net of collateral	$	305		$	(345	)
Other deferred charges and assets/Other deferred credits and liabilities	58			(74		)
Total derivatives not designated as hedging instruments	$	363		$	(419	)
Gross amounts of recognized assets and liabilities	$	442		$	(572	)
Gross amounts offset in the Balance Sheet(*)	$	(283	)	$	394
Net amounts of assets and liabilities presented in the Balance Sheet	$	159		$	(178	)
Alabama Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Liabilities from risk management activities	$	4		$	(14	)
Other deferred charges and assets/Other deferred credits and liabilities	4			(7		)
Total derivatives designated as hedging instruments for regulatory purposes	$	8		$	(21	)
Gross amounts of recognized assets and liabilities	$	8		$	(21	)
Gross amounts offset in the Balance Sheet(*)	$	(7	)	$	7
Net amounts of assets and liabilities presented in the Balance Sheet	$	1		$	(14	)
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	7		$	(5	)
Other deferred charges and assets/Other deferred credits and liabilities	8			(11		)
Total derivatives designated as hedging instruments for regulatory purposes	$	15		$	(16	)
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	5		$	—
Other deferred charges and assets/Other deferred credits and liabilities	5			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	10		$	—
Gross amounts of recognized assets and liabilities	$	25		$	(16	)
Gross amounts offset in the Balance Sheet(*)	$	(11	)	$	11
Net amounts of assets and liabilities presented in the Balance Sheet	$	14		$	(5	)

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	As of September 30, 2016
Derivative Category and Balance Sheet Location	Assets			Liabilities
	(in millions)
Gulf Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Liabilities from risk management activities	$	1		$	(24	)
Other deferred charges and assets/Other deferred credits and liabilities	—			(27		)
Total derivatives designated as hedging instruments for regulatory purposes	$	1		$	(51	)
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Liabilities from risk management activities	$	—		$	(6	)
Gross amounts of recognized assets and liabilities	$	1		$	(57	)
Gross amounts offset in the Balance Sheet(*)	$	(1	)	$	1
Net amounts of assets and liabilities presented in the Balance Sheet	$	—		$	(56	)
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	—		$	(13	)
Other deferred charges and assets/Other deferred credits and liabilities	1			(8		)
Total derivatives designated as hedging instruments for regulatory purposes	$	1		$	(21	)
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	(1	)
Gross amounts of recognized assets and liabilities	$	1		$	(22	)
Gross amounts offset in the Balance Sheet(*)	$	(1	)	$	1
Net amounts of assets and liabilities presented in the Balance Sheet	$	—		$	(21	)
Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	2		$	(3	)
Other deferred charges and assets/Other deferred credits and liabilities	—			—
Foreign currency derivatives:
Other current assets/Other current liabilities	$	—		$	(24	)
Other deferred charges and assets/Other deferred credits and liabilities	23			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	25		$	(27	)
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	—
Gross amounts of recognized assets and liabilities	$	26		$	(27	)
Gross amounts offset in the Balance Sheet(*)	$	(1	)	$	1
Net amounts of assets and liabilities presented in the Balance Sheet	$	25		$	(26	)

(*) Includes any cash/financial collateral pledged or received.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At December 31, 2015, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at December 31, 2015
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	3	$	1	$	2	$	—	$	—
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets	$	3	$	—	$	—	$	—	$	3
Interest rate derivatives:
Other current assets	19		—		5		1		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	22	$	—	$	5	$	1	$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets	$	1	$	—	$	—	$	—	$	1
Interest rate derivatives:
Other current assets	3		—		—		—		3
Total derivatives not designated as hedging instruments	$	4	$	—	$	—	$	—	$	4
Total asset derivatives	$	29	$	1	$	7	$	1	$	7

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Liability Derivatives at December 31, 2015
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities(*)	$	130	$	40	$	12	$	49	$	29
Other deferred credits and liabilities	87		15		3		51		18
Total derivatives designated as hedging instruments for regulatory purposes	$	217	$	55	$	15	$	100	$	47	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities(*)	$	2	$	—	$	—	$	—	$	—	$	2
Interest rate derivatives:
Liabilities from risk management activities	23		15		—		—		—		—
Other deferred credits and liabilities	7		—		6		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	32	$	15	$	6	$	—	$	—	$	2
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities(*)	$	1	$	—	$	—	$	—	$	—	$	1
Total liability derivatives	$	250	$	70	$	21	$	100	$	47	$	3

(*) Georgia Power, Mississippi Power, and Southern Power include current liabilities related to derivatives in other current liabilities.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

In 2015, the derivative contracts of Southern Company, the traditional electric operating companies, and Southern Power are reported gross on each registrant's financial statements. Some of these energy-related and interest rate derivative contracts 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. Amounts related to energy-related derivative contracts and interest rate derivative contracts at December 31, 2015 are presented in the following table:

Derivative Contracts at December 31, 2015
	Fair Value
	Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power		Southern Power
	(in millions)
Assets
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet(a)	$	7		$	1		$	2		$	—	$	—	$	4
Gross amounts not offset in the Balance Sheet(b)	(6		)	(1		)	(2		)	—		—		(1		)
Net energy-related derivative assets	$	1		$	—		$	—		$	—	$	—	$	3
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet(a)	$	22		$	—		$	5		$	1	$	—	$	3
Gross amounts not offset in the Balance Sheet(b)	(9		)	—			(4		)	—		—		—
Net interest rate derivative assets	$	13		$	—		$	1		$	1	$	—	$	3
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet(a)	$	220		$	55		$	15		$	100	$	47	$	3
Gross amounts not offset in the Balance Sheet(b)	(6		)	(1		)	(2		)	—		—		(1		)
Net energy-related derivative liabilities	$	214		$	54		$	13		$	100	$	47	$	2
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet(a)	$	30		$	15		$	6		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet(b)	(9		)	—			(4		)	—		—		—
Net interest rate derivative liabilities	$	21		$	15		$	2		$	—	$	—	$	—

(a) As of December 31, 2015, none of the registrants offset fair value amounts for multiple derivative instruments executed with the same counterparty in the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented in the balance sheets are the same.

(b) Includes gross amounts subject to netting terms that are not offset in the balance sheets and any cash/financial collateral pledged or received.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At September 30, 2016 and December 31, 2015, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at September 30, 2016
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(52	)	$	(10	)	$	(2	)	$	(24	)	$	(13	)
Other regulatory assets, deferred	(42		)	(4		)	(4		)	(26		)	(8		)
Other regulatory liabilities, current(a)	8			1			4			—			—
Other regulatory liabilities, deferred(b)	1			—			1			—			—
Total energy-related derivative gains (losses)	$	(85	)	$	(13	)	$	(1	)	$	(50	)	$	(21	)

(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.

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2015
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(130	)	$	(40	)	$	(12	)	$	(49	)	$	(29	)
Other regulatory assets, deferred	(87		)	(15		)	(3		)	(51		)	(18		)
Other regulatory liabilities, current(*)	3			1			2			—			—
Total energy-related derivative gains (losses)	$	(214	)	$	(54	)	$	(13	)	$	(100	)	$	(47	)

(*) Georgia Power includes other regulatory liabilities, current in other current liabilities.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the three months ended September 30, 2016 and 2015, 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
	2016			2015				2016			2015
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	—		$	—		Amortization	$	1		$	—
Interest rate derivatives	(6		)	(28		)	Interest expense, net of amounts capitalized	(6		)	(2		)
Foreign currency derivatives	37			—			Interest expense, net of amounts capitalized	(6		)	—
							Other income (expense), net(*)	7			—
Total	$	31		$	(28	)		$	(4	)	$	(2	)
Alabama Power
Interest rate derivatives	$	—		$	(10	)	Interest expense, net of amounts capitalized	$	(2	)	$	(1	)
Georgia Power
Interest rate derivatives	$	—		$	(18	)	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Southern Power
Energy-related derivatives	$	—		$	—		Amortization	$	1		$	—
Foreign currency derivatives	37			—			Interest expense, net of amounts capitalized	(6		)	—
							Other income (expense), net(*)	7			—
Total	$	37		$	—			$	2		$	—

(*) 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.

206

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the nine months ended September 30, 2016 and 2015, the pre-tax effects of energy-related derivatives, interest rate derivatives, and foreign currency derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings 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
	2016			2015				2016			2015
	(in millions)							(in millions)
Southern Company
Energy-related derivatives	$	(1	)	$	—		Amortization	$	1		$	—
Interest rate derivatives	(189		)	(26		)	Interest expense, net of amounts capitalized	(13		)	(7		)
Foreign currency derivatives	(1		)	—			Interest expense, net of amounts capitalized	(7		)	—
							Other income (expense), net(*)	(13		)	—
Total	$	(191	)	$	(26	)		$	(32	)	$	(7	)
Alabama Power
Interest rate derivatives	$	(3	)	$	(9	)	Interest expense, net of amounts capitalized	$	(5	)	$	(2	)
Georgia Power
Interest rate derivatives	$	—		$	(17	)	Interest expense, net of amounts capitalized	$	(3	)	$	(3	)
Gulf Power
Interest rate derivatives	$	(7	)	$	—		Interest expense, net of amounts capitalized	$	—		$	—
Mississippi Power
Interest rate derivatives	$	(1	)	$	—		Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Southern Power
Energy-related derivatives	$	(1	)	$	—		Amortization	$	1		$	—
Interest rate derivatives	—			—			Interest expense, net of amounts capitalized	(1		)	(1		)
Foreign currency derivatives	(1		)	—			Interest expense, net of amounts capitalized	(7		)	—
							Other income (expense), net(*)	(13		)	—
Total	$	(2	)	$	—			$	(20	)	$	(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.

For the three and nine months ended September 30, 2016 and 2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:

Derivatives in Fair Value Hedging Relationships
		Gain (Loss)
		Three Months Ended September 30,					Nine Months Ended September 30,
Derivative Category	Statements of Income Location	2016			2015		2016		2015
		(in millions)					(in millions)
Southern Company
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	(9	)	$	15	$	15	$	19
Georgia Power
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	(5	)	$	7	$	10	$	9

207

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the three and nine months ended September 30, 2016 and 2015, 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.

For the three and nine months ended September 30, 2016 and 2015, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for all registrants.

Contingent Features

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At September 30, 2016, Southern Company had $111 million of collateral posted with derivative counterparties. The amount of collateral posted with the derivative counterparties for all other registrants was immaterial.

At September 30, 2016, the fair value of derivative liabilities with contingent features was $22 million 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 $22 million for all registrants and include certain agreements that could require collateral in the event that one or more Southern Company power pool participants or Southern Company has a credit rating change to below investment grade.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.

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. Therefore, Southern Company, the traditional electric operating companies, and Southern Power 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, formerly known as AGL Resources Inc., is an energy services holding company whose primary business is the distribution of natural gas through 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.

208

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

The Merger was accounted for using the acquisition method of accounting with the assets acquired and liabilities assumed recognized at fair value as of the acquisition date. The following table presents the preliminary purchase price allocation:

Southern Company Gas Purchase Price	September 30, 2016
	(in millions)
Current assets	$	1,557
Property, plant, and equipment	10,108
Goodwill	5,937
Intangible assets	400
Regulatory assets	1,118
Other assets	229
Current liabilities	(2,201		)
Other liabilities	(4,712		)
Long-term debt	(4,261		)
Noncontrolling interests	(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 $5.9 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 estimated fair values noted above are preliminary and are subject to change upon finalization of the purchase accounting assessment as additional information related to the fair value of assets and liabilities becomes available. Subsequent adjustments to the preliminary purchase price allocation are not expected to have a material impact on the results of operations and financial position of Southern Company.

The preliminary 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 the consolidated financial statements from the date of acquisition and consist of operating revenues of $543 million and net income of $4 million.

The following summarized unaudited pro forma consolidated statement of earnings information assumes that the acquisition of Southern Company Gas was completed on January 1, 2015. The summarized unaudited pro forma consolidated statement of earnings information includes adjustments for (i) intercompany sales, (ii) amortization of intangible assets, (iii) adjustments to interest expense to reflect current interest rates on Southern Company Gas debt and additional interest expense associated with borrowings by Southern Company to fund the Merger, and (iv) the elimination of nonrecurring expenses associated with the Merger.

	For the Nine Months Ended September 30,
	2016		2015
Operating revenues (in millions)	$	16,609	$	16,865
Net income attributable to Southern Company (in millions)	$	2,369	$	2,269
Basic EPS	$	2.50	$	2.43
Diluted EPS	$	2.48	$	2.42

209

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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.

During the three and nine months ended September 30, 2016, Southern Company recorded in its statements of income costs associated with the Merger of approximately $40.8 million and $104.1 million, respectively, of which $40.6 million and $73.5 million is included in operating expenses and $0.2 million and $30.6 million is included in other income and (expense), respectively. These costs include external transaction costs for financing, legal, and consulting services, as well as rate credits and additional compensation-related expenses.

See Note 12 to the financial statements of Southern Company under "Southern Company – Proposed Merger with AGL Resources" in Item 8 of the Form 10-K for additional information.

Acquisition of PowerSecure International, Inc.

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 allocation of the purchase price is as follows:

PowerSecure Purchase Price	September 30, 2016
	(in millions)
Current assets	$	172
Property, plant, and equipment	46
Goodwill	284
Intangible assets	101
Other assets	6
Current liabilities	(145		)
Long-term debt, including current portion	(18		)
Deferred credits and other liabilities	(17		)
Total purchase price	$	429

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $284 million was recognized as goodwill, which is primarily attributable to expected business expansion opportunities for PowerSecure. Southern Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes.

The valuation of identifiable intangible assets included customer relationships, trade names, patents, backlog, and software with estimated lives of one to 26 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).

The results of operations for PowerSecure have been included in the 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.

Alliance with Bloom Energy Corporation

On October 24, 2016, a subsidiary of Southern Company acquired from an affiliate of Bloom Energy Corporation (Bloom) all of the equity interests of 2016 ESA HoldCo, LLC and its subsidiary, 2016 ESA Project Company, LLC.

210

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

2016 ESA Project Company, LLC expects to acquire 50 MWs of Bloom fuel cell systems to serve commercial and industrial customers under long-term PPAs. In connection with this transaction, PowerSecure and Bloom agreed to pursue a strategic alliance to develop technology for behind-the-meter energy solutions.

Investment in Southern Natural Gas

On July 10, 2016, Southern Company and Kinder Morgan, Inc. (Kinder Morgan) entered into a definitive agreement for Southern Company to acquire a 50% equity interest in SNG, which is the owner of a 7,000-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, and Alabama to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. On August 31, 2016, Southern Company assigned its rights and obligations under the definitive agreement to a wholly-owned, indirect subsidiary of Southern Company Gas. On September 1, 2016, Southern Company Gas completed the acquisition for a purchase price of approximately $1.4 billion. The investment in SNG is accounted for using the equity method.

Acquisition of Remaining Interest in SouthStar

SouthStar is a retail natural gas marketer and markets natural gas to residential, commercial, and industrial customers, primarily in Georgia and Illinois. At September 30, 2016, Southern Company Gas had an 85% ownership interest in SouthStar, with Piedmont owning the remaining 15%. Subsequent to September 30, 2016, Southern Company Gas purchased Piedmont's 15% interest in SouthStar for $160 million. Beginning in the fourth quarter 2016, SouthStar will be fully consolidated with Southern Company Gas.

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. During the nine months ended September 30, 2016, the fair values of the assets and liabilities acquired of Desert Stateline, Garland, Garland A, Lost Hills Blackwell, Morelos, North Star, Roserock, and Tranquillity were finalized with no changes to the fair values reported.

During 2016, in accordance with its overall growth strategy, Southern Power or one of its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC and Southern Renewable Energy, Inc., acquired or contracted to acquire the projects discussed below. Acquisition-related costs were expensed as incurred and were not material. The acquisitions do not include any contingent consideration unless specifically noted.

211

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Project Facility

Resource

Seller; Acquisition Date

Approximate Nameplate Capacity (MW)

Location

Southern Power Percentage Ownership

Actual/Expected COD

PPA Counterparties for Plant Output

PPA Contract Period

Acquisitions for the Nine Months Ended September 30, 2016

Calipatria

Solar

Solar Frontier Americas Holding LLC February 11, 2016

20

Imperial County, CA

90

%

February 2016

San Diego Gas & Electric Company

20 years

East Pecos

Solar

First Solar, Inc. March 4, 2016

120

Pecos County, TX

100

%

December 2016

Austin Energy

15 years

Grant Plains

Wind

Apex Clean Energy Holdings, LLC August 26, 2016

147

Grant County, OK

100

%

December 2016

Oklahoma Municipal Power Authority and Steelcase Inc.

20 years and 12 years

(a)

Grant Wind

Wind

Apex Clean Energy Holdings, LLC April 7, 2016

151

Grant County, OK

100

%

April 2016

Western Farmers, East Texas, and Northeast Texas Electric Cooperative

20 years

Henrietta

Solar

SunPower Corp. July 1, 2016

102

Kings County, CA

51

%

(b)

July 2016

Pacific Gas and Electric Company

20 years

Lamesa

Solar

RES America Developments Inc. July 1, 2016

102

Dawson County, TX

100

%

First quarter 2017

City of Garland, Texas

15 years

Passadumkeag

Wind

Quantum Utility Generation, LLC June 30, 2016

42

Penobscot County, ME

100

%

July 2016

Western Massachusetts Electric Company

15 years

Rutherford

Solar

Cypress Creek Renewables, LLC July 1, 2016

74

Rutherford County, NC

90

%

December 2016

Duke Energy Carolinas, LLC

15 years

Acquisitions Subsequent to September 30, 2016

Mankato

Natural Gas

Calpine Corporation October 26, 2016

375

(c)

Mankato, MN

100

%

N/A(c)

Northern States Power Company

10 years

Wake Wind

Wind

Invenergy Wind Global LLC October 26, 2016

257

Floyd and Crosby Counties, TX

90.1

%

October 2016

Equinix Enterprises, Inc. and Owens Corning

12 years

(a) In addition to the 20-year and 12-year PPAs, the facility has a 10-year contract with Allianz Risk Transfer (Bermuda) Ltd.

(b) Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction.

(c) The Mankato facility is a fully operational 375-MW natural gas-fired combined-cycle facility with an additional 345-MW expansion under development.

Acquisitions During the Nine Months Ended September 30, 2016

Southern Power's aggregate purchase price for the project facilities acquired during the nine months ended September 30, 2016 was approximately $830 million, which includes $145 million of contingent consideration. Including the minority owner Turner Renewable Energy, LLC's (TRE) 10% ownership interest in Calipatria and Rutherford, SunPower Corp's 49% ownership interest in Henrietta, and the assumption of $217 million in

212

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

construction debt (non-recourse to Southern Power), the total aggregate purchase price is approximately $923 million for the project facilities acquired during the nine months ended September 30, 2016. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: $1.0 billion as CWIP, $58 million as property, plant, and equipment, $77 million as an intangible asset, $24 million as other assets, and $5 million as accounts payable; however, the allocations of the purchase price to individual assets have not been finalized. The intangible asset consists of an acquired PPA that will be amortized over its 20-year term. The estimated amortization for future periods is approximately $1 million in 2016 and $4 million per year thereafter. For East Pecos, Grant Plains, Lamesa, and Rutherford, which are currently under construction, total aggregate construction costs, excluding the acquisition costs, are expected to be $708 million to $775 million. The ultimate outcome of these matters cannot be determined at this time.

Acquisitions Subsequent to September 30, 2016

Southern Power's aggregate purchase price for acquisitions subsequent to September 30, 2016 was approximately $873 million. Including the minority owner Invenergy Wind Global LLC's 9.9% ownership interest in Wake Wind, the total aggregate purchase price is approximately $924 million.

As part of Southern Power's acquisition of Mankato, which has a fully operational 375-MW natural gas-fired combined-cycle facility, Southern Power has commenced construction of an additional 345-MW expansion which is covered with a 20-year PPA. Total aggregate construction costs, excluding the acquisition costs allocated to CWIP, are expected to be $170 million to $190 million. The ultimate outcome of this matter cannot be determined at this time.

Acquisition Agreements Executed but Not Yet Closed

During the nine months ended September 30, 2016 and subsequent to that date, Southern Power entered into agreements to acquire the following projects for an aggregate purchase price of approximately $1.2 billion:

• 51% ownership interest (through 100% ownership of the class A membership interests entitling Southern Power to 51% of all cash distributions and most of the federal tax benefits) in a 100-MW solar facility in Nevada covered with a 20-year PPA, which is expected to close in November 2016;

• 100% ownership interests in two wind facilities in Texas totaling 299 MWs, the majority of which is contracted under PPAs for the first 12 to 14 years of operation and are expected to close before the end of 2016; and

• 100% ownership interest in a 275-MW wind facility in Texas, the majority of which is contracted under a 12-year PPA and is expected to close in January 2017.

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

The aggregate amount of revenue recognized by Southern Power related to the project facilities acquired during the nine months ended September 30, 2016 included in the condensed consolidated statements of income for year-to-date 2016 is $14 million. The aggregate amount of net income, excluding impacts of ITCs and PTCs, attributable to Southern Power related to the project facilities acquired during the nine months ended September 30, 2016 included in the condensed consolidated statements of income is immaterial. These businesses did not have operating revenues or activities prior to completion of construction and their assets being placed in service; therefore, supplemental pro forma information as though the acquisitions occurred as of the beginning of 2016, and for the comparable 2015 period, is not meaningful and has been omitted.

Construction Projects

During the nine months ended September 30, 2016, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service, or continued construction of, the projects set forth in the following table. Through September 30, 2016, total costs of construction incurred for the following projects were $3.0 billion, of which $1.2 billion remains in CWIP. Including the total construction costs incurred through September 30, 2016

213

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

and the acquisition prices allocated to CWIP, total aggregate construction costs for the following projects are estimated to be $3.1 billion to $3.2 billion. The ultimate outcome of these matters cannot be determined at this time.

Solar Facility	Seller	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Counterparties for Plant Output	PPA Contract Period
Projects Completed During the Nine Months Ended September 30, 2016
Butler Solar Farm	Strata Solar Development, LLC	22	Taylor County, GA	February 2016	Georgia Power(a)	20 years
Desert Stateline(b)	First Solar Development, LLC	299(c)	San Bernardino County, CA	Through July 2016	Southern California Edison Company (SCE)	20 years
Garland A	Recurrent Energy, LLC	20	Kern County, CA	August 2016	SCE	20 years
Pawpaw	Longview Solar, LLC	30	Taylor County, GA	March 2016	Georgia Power(a)	30 years
Tranquillity	Recurrent Energy, LLC	205	Fresno County, CA	July 2016	Shell Energy North America (US), LP/SCE	18 years
Projects Under Construction as of September 30, 2016
Butler	CERSM, LLC and Community Energy, Inc.	103	Taylor County, GA	December 2016	Georgia Power(a)	30 years
Garland	Recurrent Energy, LLC	185	Kern County, CA	October 2016	SCE	15 years
Roserock	Recurrent Energy, LLC	160	Pecos County, TX	November 2016	Austin Energy	20 years
Sandhills	N/A	146	Taylor County, GA	October 2016	Cobb, Flint, Irwin, Middle Georgia and Sawnee Electric Membership Corporations	25 years

(a) Affiliate PPA approved by the FERC.

(b) On March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline. As a result, Southern Power and the class B member are entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction.

(c) The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 189 MWs were placed in service during the nine months ended September 30, 2016.

214

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(J) SEGMENT AND RELATED INFORMATION

The primary business of the Southern Company system is electricity sales by the traditional electric operating companies and Southern Power and, as a result of closing the Merger, 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 is an energy services holding company whose primary business is the distribution of natural gas through seven natural gas distribution utilities 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 products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $110 million and $313 million for the three and nine months ended September 30, 2016, respectively, and $104 million and $303 million for the three and nine months ended September 30, 2015, respectively. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.

215

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Financial data for business segments and products and services for the three and nine months ended September 30, 2016 and 2015 was as follows:

	Electric Utilities
	Traditional Electric Operating Companies		Southern Power		Eliminations			Total		Southern Company Gas		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended September 30, 2016:
Operating revenues	$	5,236	$	500	$	(117	)	$	5,619	$	543	$	139		$	(37	)	$	6,264
Segment net income (loss)(a)(b)	1,018		176		—			1,194		4		(67		)	(1		)	1,130
Nine Months Ended September 30, 2016:
Operating revenues	$	13,120	$	1,189	$	(330	)	$	13,979	$	543	$	311		$	(118	)	$	14,715
Segment net income (loss)(a)(c)	2,076		315		—			2,391		4		(161		)	(8		)	2,226
Total assets at September 30, 2016	$	71,448	$	12,351	$	(440	)	$	83,359	$	21,185	$	2,974		$	(1,156	)	$	106,362
Three Months Ended September 30, 2015:
Operating revenues	$	5,098	$	401	$	(109	)	$	5,390	$	—	$	37		$	(26	)	$	5,401
Segment net income (loss)(a)(b)	874		102		—			976		—		(18		)	1			959
Nine Months Ended September 30, 2015:
Operating revenues	$	13,123	$	1,086	$	(322	)	$	13,887	$	—	$	120		$	(86	)	$	13,921
Segment net income (loss)(a)(c)	1,912		181		—			2,093		—		3			—			2,096
Total assets at December 31, 2015	$	69,052	$	8,905	$	(397	)	$	77,560	$	—	$	1,819		$	(1,061	)	$	78,318

(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 $88 million ($54 million after tax) and $150 million ($93 million after tax) for the three months ended September 30, 2016 and 2015, 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 includes pre-tax charges for estimated probable losses on the Kemper IGCC of $222 million ($137 million after tax) and $182 million ($112 million after tax) for the nine months ended September 30, 2016 and 2015, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2016	$	4,808	$	613	$	198	$	5,619
Three Months Ended September 30, 2015	4,701		520		169		5,390
Nine Months Ended September 30, 2016	$	11,932	$	1,455	$	592	$	13,979
Nine Months Ended September 30, 2015	11,958		1,435		494		13,887

216

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	Southern Company Gas' Revenues
Period	Gas Distribution Operations		Gas Marketing Services		All Other			Total
	(in millions)
Three and Nine Months Ended September 30, 2016	$	420	$	126	$	(3	)	$	543

217

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.

With the completion of the Merger, Southern Company now owns Southern Company Gas, a company whose subsidiaries own and operate a natural gas business.

Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through natural gas distribution utilities. Southern Company Gas is involved in several other businesses that are mainly related and complementary to its primary business including: gas marketing services including the provision of natural gas commodity and related services to customers in competitive markets or markets that provide for customer choice, wholesale gas services including natural gas storage, gas pipeline arbitrage, and natural gas asset management and/or related logistics services, and gas midstream operations including high deliverability natural gas storage facilities and select pipelines. As a result, Southern Company is now subject to risks to which it was not previously subject and Southern Company stockholders may be adversely affected by these risks. These risks include the following:

• Transporting and storing natural gas involves risks that may result in accidents and other operating risks and costs. Southern Company Gas' natural gas distribution and storage activities involve a variety of inherent hazards and operating risks, such as leaks, accidents, explosions, and mechanical problems, which could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, and impairment of its operations.

• Southern Company Gas' natural gas business faces increasing competition. The natural gas business is highly competitive and increasingly complex. Southern Company Gas is facing increasing competition from other companies that supply energy, including electric, oil, and propane providers and, in some cases, energy marketing and trading companies.

• Southern Company Gas may experience reported net income volatility due to mark-to-market accounting. Southern Company Gas utilizes hedging instruments to lock in economic value in its wholesale natural gas segment, which are not designated as hedges for accounting purposes. The difference in accounting treatment for the underlying position and the financial instrument used to hedge the value of the contract can cause volatility in reported net income while the positions are open due to mark-to-market accounting.

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
Georgia Power
(a)1	By-Laws of Georgia Power, as amended effective August 17, 2016. (Designated in Form 8-K dated August 17, 2016, File No. 1-6468, as Exhibit 3.1.)
Mississippi Power
(a)1	By-Laws of Mississippi Power, as amended, effective October 25, 2016. (Designated in Form 8-K dated October 25, 2016, File No. 001-11229, as Exhibit 3.1.)

218

	(4) Instruments Describing Rights of Security Holders, Including Indentures
	Southern Company
	(a)1	-	Second Supplemental Indenture to Junior Subordinated Note Indenture, dated as of September 15, 2016, providing for the issuance of the Series 2016A 5.25% Junior Subordinated Notes due October 1, 2076. (Designated in Form 8-K dated September 12, 2016, File No. 1-3526, as Exhibit 4.4.)
	Southern Power
*	(f)1	-	Twelfth Supplemental Indenture to Senior Note Indenture, dated as of September 7, 2016.
*	(f)2	-	Thirteenth Supplemental Indenture to Senior Note Indenture, dated as of September 20, 2016, providing for the issuance of the Series 2016C 2.75% Senior Notes due September 20, 2023.
	(24) Power of Attorney and Resolutions
	Southern Company
	(a)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 1-3526 as Exhibit 24(a).)
	Alabama Power
	(b)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 1-3164 as Exhibit 24(b).)
	Georgia Power
	(c)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 1-6468 as Exhibit 24(c).)
	Gulf Power
	(d)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 001-31737 as Exhibit 24(d).)
	Mississippi Power
	(e)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 001-11229 as Exhibit 24(e)1.)
	(e)2	-	Power of Attorney for Anthony L. Wilson. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 001-11229 as Exhibit 24(e)2.)
	Southern Power
	(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 333-98553 as Exhibit 24(f)1.)
	(f)2	-	Power of Attorney for Joseph A. Miller. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 333-98553 as Exhibit 24(f)2.)
	(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.

219

*	(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.
	(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.

220

	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.
	(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

221

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: November 4, 2016

222

ALABAMA POWER COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	ALABAMA POWER COMPANY
By	Mark A. Crosswhite
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Philip C. Raymond
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 4, 2016

223

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: November 4, 2016

224

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: November 4, 2016

225

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
	President and Chief Executive Officer
	(Principal Executive Officer)
By	Moses H. Feagin
	Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: November 4, 2016

226

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: November 4, 2016

227