10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 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 June 30, 2016
The Southern Company	Par Value $5 Per Share	941,598,673
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

June 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	40
	Condensed Statements of Comprehensive Income	40
	Condensed Statements of Cash Flows	41
	Condensed Balance Sheets	42
	Management's Discussion and Analysis of Financial Condition and Results of Operations	44
	Georgia Power Company
	Condensed Statements of Income	57
	Condensed Statements of Comprehensive Income	57
	Condensed Statements of Cash Flows	58
	Condensed Balance Sheets	59
	Management's Discussion and Analysis of Financial Condition and Results of Operations	61
	Gulf Power Company
	Condensed Statements of Income	78
	Condensed Statements of Comprehensive Income	78
	Condensed Statements of Cash Flows	79
	Condensed Balance Sheets	80
	Management's Discussion and Analysis of Financial Condition and Results of Operations	82
	Mississippi Power Company
	Condensed Statements of Income	95
	Condensed Statements of Comprehensive Income	95
	Condensed Statements of Cash Flows	96
	Condensed Balance Sheets	97
	Management's Discussion and Analysis of Financial Condition and Results of Operations	99
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	123
	Condensed Consolidated Statements of Comprehensive Income	123
	Condensed Consolidated Statements of Cash Flows	124
	Condensed Consolidated Balance Sheets	125
	Management's Discussion and Analysis of Financial Condition and Results of Operations	127
	Notes to the Condensed Financial Statements	139
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	38
Item 4.	Controls and Procedures	38

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q

June 30, 2016

		Page Number
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	193
Item 1A.	Risk Factors	193
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	193
	Signatures	198

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
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 of Merger Sub with and into Southern Company Gas on the terms and subject to the conditions set forth in the Merger Agreement, with Southern Company Gas continuing as the surviving corporation and a wholly-owned, direct subsidiary of Southern Company

5

DEFINITIONS

(continued)

Term	Meaning
Merger Agreement	Agreement and Plan of Merger, dated August 23, 2015, among Southern Company, Southern Company Gas, and Merger Sub
Merger Sub	AMS Corp., a wholly-owned, direct subsidiary of Southern Company
Mirror CWIP	A regulatory liability account for use in mitigating future rate impacts for Mississippi Power customers
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
NRC	U.S. Nuclear Regulatory Commission
OCI	Other comprehensive income
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	Standard and Poor's Ratings Services, a division of The McGraw Hill Companies, 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.)
Southern Company system	Southern Company, the traditional electric operating companies, Southern Power, Southern Electric Generating Company, Southern Nuclear, SCS, Southern Communications Services, Inc., and other subsidiaries as of June 30, 2016
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 retail 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, 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 or Southern Company Gas' 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 subsidiaries 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 or Southern Company Gas' 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 June 30,						For the Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	3,748		$	3,714		$	7,124		$	7,256
Wholesale revenues	446			448			842			915
Other electric revenues	166			162			348			325
Other revenues	99			13			137			24
Total operating revenues	4,459			4,337			8,451			8,520
Operating Expenses:
Fuel	1,023			1,200			1,934			2,412
Purchased power	189			171			354			315
Cost of sales	58			—			77			—
Other operations and maintenance	1,099			1,100			2,206			2,222
Depreciation and amortization	569			500			1,110			987
Taxes other than income taxes	255			245			511			497
Estimated loss on Kemper IGCC	81			23			134			32
Total operating expenses	3,274			3,239			6,326			6,465
Operating Income	1,185			1,098			2,125			2,055
Other Income and (Expense):
Allowance for equity funds used during construction	45			39			98			102
Interest expense, net of amounts capitalized	(293		)	(180		)	(539		)	(393		)
Other income (expense), net	(29		)	(12		)	(57		)	(19		)
Total other income and (expense)	(277		)	(153		)	(498		)	(310		)
Earnings Before Income Taxes	908			945			1,627			1,745
Income taxes	272			302			494			576
Consolidated Net Income	636			643			1,133			1,169
Less:
Dividends on Preferred and Preference Stock of Subsidiaries	12			14			23			31
Net income attributable to noncontrolling interests	12			—			13			—
Consolidated Net Income Attributable to Southern Company	$	612		$	629		$	1,097		$	1,138
Common Stock Data:
Earnings per share (EPS) —
Basic EPS	$	0.65		$	0.69		$	1.19		$	1.25
Diluted EPS	$	0.65		$	0.69		$	1.18		$	1.25
Average number of shares of common stock outstanding (in millions)
Basic	934			909			925			910
Diluted	940			912			931			914
Cash dividends paid per share of common stock	$	0.5600		$	0.5425		$	1.1025		$	1.0675

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

10

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2016			2015		2016			2015
	(in millions)					(in millions)
Consolidated Net Income	$	636		$	643	$	1,133		$	1,169
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(13), $12, $(85), and $1, respectively	(20		)	19		(137		)	1
Reclassification adjustment for amounts included in net income, net of tax of $10, $1, $11, and $2, respectively	16			2		18			3
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $-, $1, $1, and $2, respectively	1			1		2			3
Total other comprehensive income (loss)	(3		)	22		(117		)	7
Less:
Dividends on preferred and preference stock of subsidiaries	12			14		23			31
Comprehensive income attributable to noncontrolling interests	12			—		13			—
Consolidated Comprehensive Income Attributable to    Southern Company	$	609		$	651	$	980		$	1,145

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

11

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2016			2015
	(in millions)
Operating Activities:
Consolidated net income	$	1,133		$	1,169
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	1,306			1,171
Deferred income taxes	279			783
Allowance for equity funds used during construction	(98		)	(102		)
Stock based compensation expense	69			66
Hedge settlements	(201		)	(3		)
Estimated loss on Kemper IGCC	134			32
Income taxes receivable, non-current	—			(444		)
Other, net	(69		)	(3		)
Changes in certain current assets and liabilities —
-Receivables	(197		)	(158		)
-Fossil fuel stock	70			136
-Other current assets	(53		)	(99		)
-Accounts payable	(71		)	(311		)
-Accrued taxes	74			(60		)
-Accrued compensation	(222		)	(269		)
-Mirror CWIP	—			82
-Other current liabilities	(39		)	117
Net cash provided from operating activities	2,115			2,107
Investing Activities:
Business acquisitions, net of cash acquired	(897		)	(408		)
Property additions	(3,486		)	(2,239		)
Investment in restricted cash	(8,608		)	—
Distribution of restricted cash	649			—
Nuclear decommissioning trust fund purchases	(585		)	(933		)
Nuclear decommissioning trust fund sales	580			928
Cost of removal, net of salvage	(99		)	(87		)
Change in construction payables, net	(260		)	56
Prepaid long-term service agreement	(82		)	(110		)
Other investing activities	113			27
Net cash used for investing activities	(12,675		)	(2,766		)
Financing Activities:
Increase in notes payable, net	471			184
Proceeds —
Long-term debt issuances	12,038			3,075
Common stock issuances	1,383			116
Short-term borrowings	—			320
Redemptions and repurchases —
Long-term debt	(1,272		)	(939		)
Interest-bearing refundable deposits	—			(275		)
Preferred and preference stock	—			(412		)
Common stock repurchased	—			(115		)
Short-term borrowings	(475		)	(250		)
Distributions to noncontrolling interests	(11		)	(1		)
Capital contributions from noncontrolling interests	179			78
Purchase of membership interests from noncontrolling interests	(129		)	—
Payment of common stock dividends	(1,023		)	(972		)
Other financing activities	(108		)	(47		)
Net cash provided from financing activities	11,053			762
Net Change in Cash and Cash Equivalents	493			103
Cash and Cash Equivalents at Beginning of Period	1,404			710
Cash and Cash Equivalents at End of Period	$	1,897		$	813
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $61 and $57 capitalized for 2016 and 2015, respectively)	$	458		$	374
Income taxes, net	(138		)	(16		)
Noncash transactions — Accrued property additions at end of period	549			345

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

12

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2016			At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,897		$	1,404
Restricted cash and cash equivalents	7,963			—
Receivables —
Customer accounts receivable	1,281			1,058
Unbilled revenues	590			397
Under recovered regulatory clause revenues	12			63
Income taxes receivable, current	—			144
Other accounts and notes receivable	247			398
Accumulated provision for uncollectible accounts	(14		)	(13		)
Fossil fuel stock, at average cost	798			868
Materials and supplies, at average cost	1,210			1,061
Vacation pay	181			178
Prepaid expenses	563			495
Other regulatory assets, current	350			402
Other current assets	71			71
Total current assets	15,149			6,526
Property, Plant, and Equipment:
In service	78,112			75,118
Less accumulated depreciation	24,778			24,253
Plant in service, net of depreciation	53,334			50,865
Other utility plant, net	174			233
Nuclear fuel, at amortized cost	934			934
Construction work in progress	9,451			9,082
Total property, plant, and equipment	63,893			61,114
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,578			1,512
Leveraged leases	763			755
Goodwill	264			2
Other intangible assets, net of amortization of $14 and $12 at June 30, 2016 and December 31, 2015, respectively	490			317
Miscellaneous property and investments	230			166
Total other property and investments	3,325			2,752
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,580			1,560
Unamortized loss on reacquired debt	220			227
Other regulatory assets, deferred	5,460			4,989
Income taxes receivable, non-current	413			413
Other deferred charges and assets	833			737
Total deferred charges and other assets	8,506			7,926
Total Assets	$	90,873		$	78,318

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

13

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At June 30, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	2,724		$	2,674
Notes payable	1,372			1,376
Accounts payable	1,493			1,905
Customer deposits	408			404
Accrued taxes —
Accrued income taxes	13			19
Other accrued taxes	398			484
Accrued interest	289			249
Accrued vacation pay	229			228
Accrued compensation	335			549
Asset retirement obligations, current	349			217
Liabilities from risk management activities	95			156
Other regulatory liabilities, current	115			278
Other current liabilities	694			590
Total current liabilities	8,514			9,129
Long-term Debt	35,368			24,688
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	12,563			12,322
Deferred credits related to income taxes	183			187
Accumulated deferred investment tax credits	1,427			1,219
Employee benefit obligations	2,485			2,582
Asset retirement obligations, deferred	4,129			3,542
Unrecognized tax benefits	380			370
Other cost of removal obligations	1,154			1,162
Other regulatory liabilities, deferred	335			254
Other deferred credits and liabilities	724			720
Total deferred credits and other liabilities	23,380			22,358
Total Liabilities	67,262			56,175
Redeemable Preferred Stock of Subsidiaries	118			118
Redeemable Noncontrolling Interests	47			43
Stockholders' Equity:
Common Stockholders' Equity:
Common stock, par value $5 per share —
Authorized — 1.5 billion shares
Issued — June 30, 2016: 942 million shares
— December 31, 2015: 915 million shares
Treasury — June 30, 2016: 0.8 million shares
— December 31, 2015: 3.4 million shares
Par value	4,708			4,572
Paid-in capital	7,499			6,282
Treasury, at cost	(30		)	(142		)
Retained earnings	10,085			10,010
Accumulated other comprehensive loss	(247		)	(130		)
Total Common Stockholders' Equity	22,015			20,592
Preferred and Preference Stock of Subsidiaries	609			609
Noncontrolling Interests	822			781
Total Stockholders' Equity	23,446			21,982
Total Liabilities and Stockholders' Equity	$	90,873		$	78,318

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

14

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2016 vs. SECOND 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 Southern Power Company and owns other direct and indirect subsidiaries. Discussion of the results of operations is focused on the Southern Company system's primary business as of June 30, 2016 of electricity sales by the traditional electric operating companies and Southern Power. The four traditional electric operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. 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 on these businesses, 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

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.

Prior to the completion of the Merger on July 1, 2016, Southern Company and Southern Company Gas operated as separate companies. Accordingly, except for specific references to the Merger, the discussion and analysis of results of operations and financial condition as of and for the three and six months ended June 30, 2016 set forth herein relate solely to Southern Company and do not include Southern Company Gas. Following the Merger, the results of operations and financial condition of Southern Company Gas will be consolidated with those of Southern Company. The descriptions herein of strategy and outlook and the risks and challenges Southern Company faces include Southern Company Gas, to the extent material. 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 six months ended June 30, 2016, Southern Company recorded in its statements of income external transaction costs for financing, legal, and consulting services associated with the Merger of approximately $43.4 million and $63.3 million, respectively, of which $26.9 million and $32.9 million is included in operating expenses and $16.5 million and $30.4 million is included in other income and (expense), respectively.

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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(17)	(2.7)	$(41)	(3.6)

Consolidated net income attributable to Southern Company was $612 million ($0.65 per share) for the second quarter 2016 compared to $629 million ($0.69 per share) for the second quarter 2015. For year-to-date 2016, consolidated net income attributable to Southern Company was $1.10 billion ($1.19 per share) compared to $1.14 billion ($1.25 per share) for the corresponding period in 2015. These decreases were primarily the result of higher interest expenses, higher depreciation and amortization, and higher charges related to revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC. These decreases were partially offset by increases in retail revenues resulting from retail 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. Also contributing to the year-to-date 2016 decrease was lower retail revenues due to milder weather compared to the corresponding period in 2015.

Retail Revenues

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$34	0.9	$(132)	(1.8)

In the second quarter 2016, retail revenues were $3.75 billioncompared to $3.71 billion for the corresponding period in 2015. For year-to-date 2016, retail revenues were $7.1 billion compared to $7.3 billion for the corresponding period in 2015.

Details of the changes in retail revenues were as follows:

	Second Quarter 2016					Year-to-Date 2016
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	3,714				$	7,256
Estimated change resulting from –
Rates and pricing	186			5.0		296			4.1
Sales growth (decline)	(18		)	(0.5	)	4			0.1
Weather	(2		)	(0.1	)	(87		)	(1.2	)
Fuel and other cost recovery	(132		)	(3.5	)	(345		)	(4.8	)
Retail – current year	$	3,748		0.9	%	$	7,124		(1.8	)%

Revenues associated with changes in rates and pricing increased in the second 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. The increase in rates and pricing was also due to the 2015 correction of a Georgia Power

16

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

billing error to a small number of large commercial and industrial customers and the implementation of rates for certain Kemper IGCC in-service assets at Mississippi Power.

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 second quarter 2016 when compared to the corresponding period in 2015. Weather-adjusted residential KWH sales and weather-adjusted commercial KWH sales decreased 0.2% and 1.9%, respectively, in the second quarter 2016 primarily due to decreased customer usage, partially offset by customer growth. Industrial KWH sales decreased 1.9% in the second quarter 2016 primarily in the chemicals, primary metals, textiles, and pipeline sectors, partially offset by increases in the paper and lumber sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector.

Revenues attributable to changes in sales increased slightly for year-to-date 2016 when compared to the corresponding period in 2015. Weather-adjusted residential KWH sales increased 0.6% for year-to-date 2016 due to customer growth, partially offset by decreased customer usage. Weather-adjusted commercial KWH sales decreased 0.6% for year-to-date 2016 primarily due to decreased customer usage, partially offset by customer growth. Industrial KWH sales decreased 1.5% for year-to-date 2016 primarily in the chemicals, primary metals, non-manufacturing, textiles, and pipeline sectors, partially offset by increases in the paper, stone, clay, and glass, and lumber sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector.

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 0.7%, weather-adjusted commercial sales decreased 0.4%, and industrial KWH sales decreased 1.4% as compared to the corresponding period in 2015.

Fuel and other cost recovery revenues decreased $132 million and $345 million in the second 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 includeprovisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.

Wholesale Revenues

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	(0.4)	$(73)	(8.0)

Wholesale revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale 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 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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

In the second quarter 2016, wholesale revenues were $446 million compared to $448 million for the corresponding period in 2015. This decrease was primarily related to a $21 million decrease in capacity revenues, partially offset by a $19 million increase in energy revenues. The decrease in capacity revenues was 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. The increase in energy revenues was primarily due to an increase in short-term sales and renewable energy sales at Southern Power, partially offset by lower fuel prices.

For year-to-date 2016, wholesale revenues were $842 million compared to $915 million for the corresponding period in 2015. This decrease was primarily related to a $64 million decrease in capacity revenues and a $9 million decrease in energy revenues. The decrease in capacity revenues was 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, unit retirements as well as the expiration of wholesale contracts at Georgia Power, and the expiration of Plant Scherer Unit 3 power sales agreements at Gulf Power. The decrease in energy revenues was primarily due to lower fuel prices, partially offset by an increase in short-term sales and renewable energy sales at Southern Power.

See FUTURE EARNINGS POTENTIAL – "Retail 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.

Other Revenues

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$86	N/M	$113	N/M

N/M - Not meaningful

In the second quarter 2016, other revenues were $99 million compared to $13 million for the corresponding period in 2015. For year-to-date 2016, other revenues were $137 million compared to $24 million for the corresponding period in 2015. These increases were primarily due to $59 million in revenues from products and services at PowerSecure International, Inc. (PowerSecure), which was acquired on May 9, 2016. Additionally, for the second quarter and year-to-date 2016, revenues from certain unregulated sales of products and services by the traditional electric operating companies of $20 million and $46 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 – Acquisition of PowerSecure International, Inc." 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

Fuel and Purchased Power Expenses

	Second Quarter 2016 vs. Second Quarter 2015				Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(177	)	(14.8)	$	(478	)	(19.8)
Purchased power	18			10.5	39			12.4
Total fuel and purchased power expenses	$	(159	)		$	(439	)

In the second quarter 2016, total fuel and purchased power expenses were $1.2 billion compared to $1.4 billion for the corresponding period in 2015. The decrease was primarily the result of a $159 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas and coal prices.

For year-to-date 2016, total fuel and purchased power expenses were $2.3 billion compared to $2.7 billion for the corresponding period in 2015. The decrease was primarily the result of a $376 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas and coal prices and a $63 million net decrease in the volume of KWHs generated and purchased.

Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Retail 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.

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

	Second Quarter 2016	Second Quarter 2015	Year-to-Date 2016	Year-to-Date 2015
Total generation (billions of KWHs)	45	46	89	92
Total purchased power (billions of KWHs)	4	4	8	6
Sources of generation (percent) —
Coal	32	39	30	36
Nuclear	16	15	17	16
Gas	48	42	47	44
Hydro	2	3	4	3
Other Renewables	2	1	2	1
Cost of fuel, generated (cents per net KWH) —
Coal	3.20	3.37	3.22	3.52
Nuclear	0.82	0.84	0.82	0.75
Gas	2.24	2.76	2.20	2.73
Average cost of fuel, generated (cents per net KWH)	2.33	2.70	2.28	2.70
Average cost of purchased power (cents per net KWH)(*)	5.03	5.63	5.14	6.26

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

Fuel

In the second quarter 2016, fuel expense was $1.0 billion compared to $1.2 billion for the corresponding period in 2015. The decrease was primarily due to a 19.2% decrease in the volume of KWHs generated by coal, an 18.8%

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

decrease in the average cost of natural gas per KWH generated, and a 5.0% decrease in the average cost of coal per KWH generated, partially offset by a 14.7% increase in the volume of KWHs generated by natural gas.

For year-to-date 2016, fuel expense was $1.9 billion compared to $2.4 billion for the corresponding period in 2015. The decrease was primarily due to a 20.4% decrease in the volume of KWHs generated by coal, a 19.4% decrease in the average cost of natural gas per KWH generated, and an 8.5% decrease in the average cost of coal per KWH generated, partially offset by a 4.6% increase in the volume of KWHs generated by natural gas.

Purchased Power

In the second quarter 2016, purchased power expense was $189 million compared to $171 million for the corresponding period in 2015. The increase was primarily due to a 20.9% increase in the volume of KWHs purchased, partially offset by a 10.7% decrease in the average cost per KWH purchased, primarily as a result of lower natural gas and coal prices.

For year-to-date 2016, purchased power expense was $354 million compared to $315 million for the corresponding period in 2015. The increase was primarily due to a 33.0% increase in the volume of KWHs purchased, partially offset by a 17.9% decrease in the average cost per KWH purchased, primarily as a result of lower natural gas and coal prices.

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

Cost of Sales

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$58	N/M	$77	N/M

N/M - Not meaningful

In the second quarter and year-to-date 2016, cost of sales were $58 million and $77 million, respectively. These costs were primarily related to sales of products and services by PowerSecure, which was acquired on May 9, 2016. Additionally, for the second quarter and year-to-date 2016, costs of $13 million and $32 million, respectively, related to certain unregulated sales of products and services by the traditional electric operating companies, were reclassified as cost of 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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(0.1)	$(16)	(0.7)

Other operations and maintenance expenses decreased slightly in the second quarter 2016 as compared to the corresponding period in 2015. The decrease was primarily related to a $22 million decrease in employee compensation and benefits including pension costs and an $18 million decrease in scheduled outage and maintenance costs at generation facilities, partially offset by $28 million in transaction fees related to the Merger and the acquisition of PowerSecure and $10 million in operations and maintenance expenses at PowerSecure since the acquisition closed on May 9, 2016.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other operations and maintenance expenses decreased slightly for year-to-date 2016 as compared to the corresponding period in 2015. The decrease was primarily due to a $45 million decrease in scheduled outage and maintenance costs at generation facilities and a $36 million decrease in employee compensation and benefits including pension costs. These decreases were partially offset by $34 million in transaction fees related to the Merger and the acquisition of PowerSecure, $10 million in operations and maintenance expenses at PowerSecure since the acquisition closed on May 9, 2016, and an increase of $10 million in general business expenses associated with Southern Power's overall growth strategy.

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.

Depreciation and Amortization

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$69	13.8	$123	12.5

In the second quarter 2016, depreciation and amortization was $569 million compared to $500 million for the corresponding period in 2015. The increase was primarily due to additional plant in service at the traditional electric operating companies and Southern Power.

For year-to-date 2016, depreciation and amortization was $1.1 billion compared to $987 million for the corresponding period in 2015. The increase was primarily due to an $86 million increase related to additional plant in service at the traditional electric operating companies and Southern Power. Also contributing to the increase, Gulf Power recorded $13 million less of a reduction in depreciation compared to the corresponding period in 2015, as authorized by the Florida PSC.

See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Gulf Power – 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 Case" herein for additional information.

Estimated Loss on Kemper IGCC

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$58	N/M	$102	N/M

N/M - Not meaningful

In the second quarter 2016 and 2015, estimated probable losses on the Kemper IGCC of $81 million and $23 million, respectively, were recorded at Southern Company. For year-to-date 2016 and 2015, estimated probable losses on the Kemper IGCC of $134 million and $32 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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$113	62.8	$146	37.2

In the second quarter 2016, interest expense, net of amounts capitalized was $293 million compared to $180 million in the corresponding period in 2015. For year-to-date 2016, interest expense, net of amounts capitalized was $539 million compared to $393 million in the corresponding period in 2015. These increases were primarily due to an increase in outstanding long-term debt related to the Merger, as well as increases in average outstanding long-term debt balances and higher interest rates at the traditional electric operating companies. Also contributing to the increases 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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(17)	N/M	$(38)	N/M

N/M - Not meaningful

In the second quarter 2016, other income (expense), net was $(29) million compared to $(12) million for the corresponding period in 2015. For year-to-date 2016, other income (expense), net was $(57) million compared to $(19) million for the corresponding period in 2015. These changes were primarily due to fees associated with the Bridge Agreement for the Merger. Additionally, in the second quarter 2016, revenues and costs associated with certain unregulated sales of products and services by the traditional electric operating companies were reclassified to other revenues and cost of sales for consistency of presentation on a consolidated basis following the PowerSecure acquisition. For the second quarter and year-to-date 2016, net amounts reclassified were $7 million and $14 million, respectively.

See "Other Revenues" and "Cost of Sales" herein and 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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(30)	(9.9)	$(82)	(14.2)

In the second quarter 2016, income taxes were $272 million compared to $302 million for the corresponding period in 2015. For year-to-date 2016, income taxes were $494 million compared to $576 million for the corresponding period in 2015. These decreases were primarily due to increased federal income tax benefits from ITCs and PTCs at Southern Power and increased tax benefits related to the estimated probable losses on Mississippi Power's construction of the Kemper IGCC, partially offset by 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

22

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

a result of closing the Merger on July 1, 2016, Southern Company Gas' primary business of natural gas distribution. 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 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 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' retail operations and wholesale 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 under which Southern Company will acquire a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG), which is the owner of a 7,600-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, Alabama, and the Gulf of Mexico to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. In addition, the agreement commits Southern Company and Kinder Morgan to cooperatively pursue specific growth opportunities to develop natural gas infrastructure through SNG. Southern Company expects to finance the purchase price of approximately $1.5 billion with a mix of equity and debt in a credit-supportive manner. Southern Company's investment in SNG will be accounted for under the equity method of accounting.

The transaction is subject to the notification and clearance and reporting requirements under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Southern Company and Kinder Morgan expect to complete the transaction in the third quarter or early in the fourth quarter 2016. The ultimate outcome of this matter cannot be determined at this time.

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

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through market-based contracts.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 and regional haze regulations.

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 have 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.

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 July 7, 2016, the Georgia Environmental Protection Division (EPD) proposed 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 proposed Georgia EPD regulations are expected to be finalized in October 2016 and are not anticipated to have a material impact on the Southern Company system's compliance obligations under the CCR Rule. See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company's asset retirement obligations (ARO) as of June 30, 2016.

Retail Regulatory Matters

Retail 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

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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.

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 renewable energy credits (REC) is specified in each respective PPA. The party that owns the RECs retains the right to use them.

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.

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.

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 RECs 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.

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.

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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 May 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 – Fuel Cost Recovery" 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 fuel cost recovery and the NCCR tariff, respectively.

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 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. Georgia Power exercised its contractual option to sell its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc., with an expected closing date in late August 2016.

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 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. 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 2019 general base rate case.

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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.

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 will cover approximately 24% of the unit through 2019. The expiration of these contracts is not expected to have a material impact on Southern Company's earnings. Gulf Power is actively evaluating alternatives, including, without limitation, rededication of the asset to serve retail customers for whom it was originally planned and built, replacement long-term wholesale contracts or other sales into the wholesale market, or an asset sale. 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 the contracts expire. The ultimate outcome of this matter cannot be determined at this time.

Construction Program

Overview

The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new generating facilities, as well as adding or changing fuel sources for certain existing units, adding environmental control equipment, and expanding the transmission and 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 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.

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

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Integrated Coal Gasification Combined Cycle

Mississippi Power's current cost estimate for the Kemper IGCC in total is approximately $6.68 billion, which includes approximately $5.43 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 $2.55 billion ($1.57 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through June 30, 2016. Mississippi Power's current cost estimate includes costs through October 31, 2016, which reflects a one-month extension. The initial production of syngas began on July 14, 2016 and testing has continued on gasifier 'B' and the related lignite feed and ash systems. The schedule extension provides for time to complete mechanical equipment modifications to the gasifiers' supporting systems to increase capacity to the levels necessary to complete the remaining start-up activities and achieve sustained operations on both gasifiers. The remaining schedule also reflects the time expected to complete the initial operation and testing of the facility's syngas clean-up systems, as well as 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 to complete construction 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.

Litigation

On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff, 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 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.

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

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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 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 $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

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$540 million ($333 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $2.55 billion ($1.57 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through June 30, 2016.

Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up 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. 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, 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).

Mississippi Power's revised cost estimate includes costs through October 31, 2016. Any extension of the in-service date beyond October 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 October 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 $14 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.

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 unchangedand 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 compensation in 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.

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FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at June 30, 2016. Through June 30, 2016, Southern Company has incurred non-recoverable cash expenditures of $2.28 billion and is expected to incur approximately $0.27 billion in additional non-recoverable cash expenditures through completion of the construction and start-up of the Kemper IGCC. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $2.1 billion for the first six months of 2016 and the corresponding period in 2015. Net cash used for investing activities totaled $12.7 billion for the first six months of 2016 primarily due to an investment in restricted cash to be used to complete the Merger, as well as construction of generation, transmission, and distribution facilities and installation of equipment to comply with environmental standards. Net cash provided from financing activities totaled $11.1 billion for the first six months of 2016 primarily due to issuances of long-term debt and common stock associated with financing and completing the Merger. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2016 include increases of $10.7 billion in long-term debt, $8.0 billion in restricted cash and cash equivalents, and $1.4 billion in total common stockholder's equity primarily associated with financing and completing the Merger; an increase of $2.8 billion in total property, plant, and equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities; and increases of $0.7 billion in AROs and $0.5 billion in other regulatory assets, deferred primarily related to changes in ash pond closure strategy primarily for Georgia Power. See Notes (A) and (I) to the Condensed Financial Statements herein under "Asset Retirement Obligations" and "Southern Company – Merger with Southern Company Gas," respectively, for additional information.

At the end of the second quarter 2016, the market price of Southern Company's common stock was $53.63 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $23.38 per share, representing a market-to-book ratio of 229%, compared to $46.79, $22.59, and 207%, respectively, at the end of 2015. Southern Company's common stock dividend for the second quarter 2016 was $0.560 per share compared to $0.5425 per share in the second 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 description of Southern Company's capital requirements for the construction programs of the Southern Company system, including estimated capital expenditures for new 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. Approximately $3.3 billion will be required through June 30, 2017 to fund maturities of long-term debt, which includes $0.6 billion with respect to Southern Company Gas that was assumed subsequent to June 30, 2016 in connection with the Merger. In addition, approximately $1.5 billion will be required for Southern Company's acquisition of a 50% equity interest in SNG, which is expected to be completed in the third quarter or early in the fourth quarter 2016. See "Sources of Capital" and Note (I) to the Condensed Financial Statements under "Southern Company – Natural Gas Pipeline Venture" herein for additional information.

The Southern Company system's construction program is currently estimated to total $9.4 billion for 2016, $5.2 billion for 2017, and $5.5 billion for 2018. These amounts include expenditures of approximately $0.7 billion related to the construction and start-up of the Kemper IGCC in 2016; $0.6 billion, $0.7 billion, and $0.4 billion to

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continue construction on Plant Vogtle Units 3 and 4 in 2016, 2017, and 2018, respectively; and $4.4 billion, $0.9 billion, and $1.4 billion for Southern Power's acquisitions and/or construction of new generating facilities in 2016, 2017, and 2018, respectively. In addition, Southern Company Gas' construction program is currently estimated to total $0.8 billion for the period from July 1, 2016 to December 31, 2016.

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; 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. 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.

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 and Southern Company Gas' capital requirements. See "Capital Requirements and Contractual Obligations" herein for additional information.

Except as described herein, the traditional electric operating companies, Southern Company Gas, and Southern Power plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, term loans, short-term borrowings, and equity contributions or loans from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information.

In addition, Georgia Power 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 June 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

32

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 June 30, 2016, Southern Company's current assets exceeded current liabilities by $6.6 billion. Excluding restricted cash of $8.0 billion associated with the Merger, Southern Company's current liabilities exceeded current assets by $1.3 billion, primarily due to long-term debt that is due within one year of $2.7 billion, including approximately $0.9 billion at the parent company, $0.2 billion at Alabama Power, $0.7 billion at Georgia Power, $0.2 billion at Gulf Power, $0.3 billion at Mississippi Power, and $0.4 billion at Southern Power. 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 and Southern Power, equity contributions and/or loans from Southern Company to meet their short-term capital needs. In addition, for the remainder of 2016, Georgia Power expects to utilize borrowings through the FFB Credit Facility as an additional source of long-term borrowed funds.

At June 30, 2016, Southern Company and its subsidiaries had approximately $1.9 billion of cash and cash equivalents. In addition, Southern Company had approximately $8.0 billion of restricted cash, which was subsequently used to complete the Merger. Committed credit arrangements with banks at June 30, 2016 were as follows:

	Expires												Executable Term Loans				Due Within One Year
Company(a)	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	$	—	$	—	$	1,000	$	1,250	$	2,250	$	2,250	$	—	$	—	$	—	$	—
Alabama Power	3		32		500		800		1,335		1,335		—		—		—		35
Georgia Power	—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	75		40		165		—		280		280		45		—		45		70
Mississippi Power	115		60		—		—		175		150		—		15		15		160
Southern Power Company(b)	—		—		—		600		600		560		—		—		—		—
Other	25		45		—		40		110		80		20		—		20		50
Total	$	218	$	177	$	1,665	$	4,440	$	6,500	$	6,387	$	65	$	15	$	80	$	315

(a) Excludes Southern Company Gas as the Merger was not completed at June 30, 2016. Southern Company Gas has committed credit arrangements with banks totaling $2.0 billion at July 1, 2016, of which $0.1 billion expire in 2017 and $1.9 billion expire in 2018.

(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.

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

33

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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, and Southern Power Company 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 June 30, 2016 was approximately $1.9 billion. In addition, at June 30, 2016, the traditional electric operating companies had approximately $320 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

Southern Company, the traditional electric operating companies, and Southern Power 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, and Southern Power 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 June 30, 2016(a)				Short-term Debt During the Period(a,b)
	Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
Commercial paper	$	478	0.8	%	$	1,082	0.8	%	$	1,712
Short-term bank debt	125		1.5	%	215		1.5	%	262
Total	$	603	1.0	%	$	1,297	0.9	%

(a) Excludes Southern Company Gas as the Merger was not completed at June 30, 2016.

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

In addition to the short-term borrowings in the table above, the Project Credit Facilities had total amounts outstanding as of June 30, 2016 of $769 million at a weighted average interest rate of 2.02%. For the three-month period ended June 30, 2016, these credit agreements had a maximum amount outstanding of $769 million and an average amount outstanding of $586 million at a weighted average interest rate of 2.03%.

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

Credit Rating Risk

At June 30, 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 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.

34

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	29
At BBB- and/or Baa3	$	597
Below BBB- and/or Baa3	$	2,519

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.

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 Merger and for other general corporate purposes.

In addition, during the first six months of 2016, Southern Company issued approximately 11.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $494 million.

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

Company(a)	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(b)
	(in millions)
Southern Company	$	8,500	$	—	$	—	$	—		$	—
Alabama Power	400		200		—		45			—
Georgia Power	650		500		4		300			3
Gulf Power	—		125		—		—			—
Mississippi Power	—		—		—		1,100			651
Southern Power	1,241		—		—		2			4
Other	—		—		—		—			10
Elimination(c)	—		—		—		(200		)	(225		)
Total	$	10,791	$	825	$	4	$	1,247		$	443

(a) Excludes Southern Company Gas as the Merger was not completed at June 30, 2016.

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

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

35

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 Merger and related transaction costs 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 to repay existing indebtedness and for other general corporate purposes. Mississippi Power borrowed $900 million under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016, upon satisfaction of certain customary conditions. Mississippi Power used the initial proceeds to repay $900 million in maturing bank notes on March 8, 2016 and expects the remaining $300 million to be used to repay senior notes maturing in October 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 under the FFB Credit Facility in an aggregate principal amount of $300 million in June 2016. The interest rate applicable to the $300 million principal amount is 2.571% for an interest period that extends to 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 six months ended June 30, 2016, Southern Power's subsidiaries borrowed an additional $632 million pursuant to the Project Credit Facilities at a weighted average interest rate of 2.00%. Subsequent to June 30, 2016, Southern Power's subsidiaries borrowed $48 million pursuant to the Project Credit Facilities at a weighted average interest rate of 1.98%.

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 will be 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.

36

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

37

PART I

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

During the six months ended June 30, 2016, there were no material changes to each registrant'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 (H) to the Condensed Financial Statements herein for information relating to derivative instruments.

Item 4. Controls and Procedures.

(a) Evaluation of disclosure controls and procedures.

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

(b) Changes in internal controls over financial reporting.

There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, or Southern Power Company'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 second 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 Company'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 will be conducting control reviews pursuant to Section 404 of the Sarbanes-Oxley 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.

38

ALABAMA POWER COMPANY

39

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,316		$	1,326		$	2,510		$	2,594
Wholesale revenues, non-affiliates	67			57			130			123
Wholesale revenues, affiliates	9			20			31			35
Other revenues	52			52			105			104
Total operating revenues	1,444			1,455			2,776			2,856
Operating Expenses:
Fuel	295			343			564			653
Purchased power, non-affiliates	40			45			76			86
Purchased power, affiliates	55			49			88			103
Other operations and maintenance	355			370			747			768
Depreciation and amortization	175			160			347			318
Taxes other than income taxes	94			90			191			184
Total operating expenses	1,014			1,057			2,013			2,112
Operating Income	430			398			763			744
Other Income and (Expense):
Allowance for equity funds used during construction	6			14			16			29
Interest expense, net of amounts capitalized	(74		)	(69		)	(147		)	(134		)
Other income (expense), net	(4		)	(14		)	(11		)	(18		)
Total other income and (expense)	(72		)	(69		)	(142		)	(123		)
Earnings Before Income Taxes	358			329			621			621
Income taxes	142			122			245			235
Net Income	216			207			376			386
Dividends on Preferred and Preference Stock	5			7			9			17
Net Income After Dividends on Preferred and Preference Stock	$	211		$	200		$	367		$	369

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2016		2015		2016			2015
	(in millions)				(in millions)
Net Income	$	216	$	207	$	376		$	386
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $3, $(1), and $-, respectively	—		5		(2		)	1
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $1, and $1, respectively	1		—		2			1
Total other comprehensive income (loss)	1		5		—			2
Comprehensive Income	$	217	$	212	$	376		$	388

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

40

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	376		$	386
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	419			387
Deferred income taxes	175			60
Allowance for equity funds used during construction	(16		)	(29		)
Other, net	(37		)	(23		)
Changes in certain current assets and liabilities —
-Receivables	64			(115		)
-Fossil fuel stock	(32		)	19
-Other current assets	(67		)	(52		)
-Accounts payable	(75		)	(212		)
-Accrued taxes	98			177
-Accrued compensation	(50		)	(66		)
-Retail fuel cost over recovery	(60		)	25
-Other current liabilities	8			40
Net cash provided from operating activities	803			597
Investing Activities:
Property additions	(645		)	(612		)
Nuclear decommissioning trust fund purchases	(200		)	(278		)
Nuclear decommissioning trust fund sales	200			278
Cost of removal, net of salvage	(51		)	(28		)
Change in construction payables	(27		)	28
Other investing activities	(18		)	(14		)
Net cash used for investing activities	(741		)	(626		)
Financing Activities:
Proceeds —
Senior notes issuances	400			975
Capital contributions from parent company	237			10
Pollution control revenue bonds	—			80
Other long-term debt issuances	45			—
Redemptions and repurchases —
Preferred and preference stock	—			(412		)
Pollution control revenue bonds	—			(134		)
Senior notes	(200		)	(250		)
Payment of common stock dividends	(382		)	(286		)
Other financing activities	(13		)	(32		)
Net cash provided from (used for) financing activities	87			(49		)
Net Change in Cash and Cash Equivalents	149			(78		)
Cash and Cash Equivalents at Beginning of Period	194			273
Cash and Cash Equivalents at End of Period	$	343		$	195
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $7 and $10 capitalized for 2016 and 2015, respectively)	$	131		$	118
Income taxes, net	(122		)	47
Noncash transactions — Accrued property additions at end of period	94			35

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

41

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2016			At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	343		$	194
Receivables —
Customer accounts receivable	357			332
Unbilled revenues	174			119
Under recovered regulatory clause revenues	7			43
Income taxes receivable, current	—			142
Other accounts and notes receivable	35			20
Affiliated companies	32			50
Accumulated provision for uncollectible accounts	(9		)	(10		)
Fossil fuel stock, at average cost	271			239
Materials and supplies, at average cost	412			398
Vacation pay	66			66
Prepaid expenses	100			83
Other regulatory assets, current	87			115
Other current assets	10			10
Total current assets	1,885			1,801
Property, Plant, and Equipment:
In service	25,572			24,750
Less accumulated provision for depreciation	8,889			8,736
Plant in service, net of depreciation	16,683			16,014
Nuclear fuel, at amortized cost	368			363
Construction work in progress	423			801
Total property, plant, and equipment	17,474			17,178
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	69			71
Nuclear decommissioning trusts, at fair value	759			737
Miscellaneous property and investments	101			96
Total other property and investments	929			904
Deferred Charges and Other Assets:
Deferred charges related to income taxes	519			522
Deferred under recovered regulatory clause revenues	136			99
Other regulatory assets, deferred	1,100			1,114
Other deferred charges and assets	113			103
Total deferred charges and other assets	1,868			1,838
Total Assets	$	22,156		$	21,721

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

42

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	200		$	200
Accounts payable —
Affiliated	293			278
Other	294			410
Customer deposits	88			88
Accrued taxes —
Accrued income taxes	10			—
Other accrued taxes	93			38
Accrued interest	80			73
Accrued vacation pay	55			55
Accrued compensation	72			119
Liabilities from risk management activities	17			55
Other regulatory liabilities, current	81			240
Other current liabilities	41			39
Total current liabilities	1,324			1,595
Long-term Debt	6,894			6,654
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,413			4,241
Deferred credits related to income taxes	68			70
Accumulated deferred investment tax credits	114			118
Employee benefit obligations	360			388
Asset retirement obligations	1,502			1,448
Other cost of removal obligations	699			722
Other regulatory liabilities, deferred	106			136
Deferred over recovered regulatory clause revenues	102			—
Other deferred credits and liabilities	69			76
Total deferred credits and other liabilities	7,433			7,199
Total Liabilities	15,651			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	2,589			2,341
Retained earnings	2,445			2,461
Accumulated other comprehensive loss	(32		)	(32		)
Total common stockholder's equity	6,224			5,992
Total Liabilities and Stockholder's Equity	$	22,156		$	21,721

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

43

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2016 vs. SECOND 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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$11	5.5	$(2)	(0.5)

Alabama Power's net income after dividends on preferred and preference stock for the second quarter 2016 was $211 million compared to $200 million for the corresponding period in 2015. The increase was primarily related to 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 decreases in customer usage and AFUDC and increases in interest expense and depreciation and amortization.

Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2016 was $367 million compared to $369 million for the corresponding period in 2015. The decrease was primarily related to a decrease in retail revenues associated with milder weather for year-to-date 2016 compared to the corresponding period in 2015, a decrease in AFUDC, and increases in interest expense, taxes other than income taxes, and depreciation and amortization. These decreases to income were partially offset by an increase in revenue under Rate CNP Compliance, a decrease in non-fuel operations and maintenance expenses, and a decrease in dividends on preferred and preference stock.

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Retail Revenues

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(10)	(0.8)	$(84)	(3.2)

In the second quarter 2016, retail revenues were $1.32 billion compared to $1.33 billion for the corresponding period in 2015. For year-to-date 2016, retail revenues were $2.51 billion compared to $2.59 billion for the corresponding period in 2015.

Details of the changes in retail revenues were as follows:

	Second Quarter 2016					Year-to-Date 2016
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	1,326				$	2,594
Estimated change resulting from –
Rates and pricing	43			3.2		77			3.0
Sales growth (decline)	(9		)	(0.7	)	(1		)	(0.1	)
Weather	(3		)	(0.2	)	(48		)	(1.8	)
Fuel and other cost recovery	(41		)	(3.1	)	(112		)	(4.3	)
Retail – current year	$	1,316		(0.8	)%	$	2,510		(3.2	)%

Revenues associated with changes in rates and pricing increased in the second 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 second quarter and year-to-date 2016 when compared to the corresponding periods in 2015. Industrial KWH sales decreased 5.5% and 4.5% for the second 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 chemicals, primary metals, and pipelines 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 1.6% for the second quarter 2016 and remained relatively flat year-to-date 2016. Weather-adjusted residential KWH sales remained relatively flat for the second quarter and year-to-date 2016.

Revenues resulting from changes in weather decreased in the second quarter and year-to-date 2016 due to milder weather experienced in Alabama Power's service territory compared to the corresponding periods in 2015. For the second quarter 2016, the resulting decreases were 0.2% and 0.4% for residential and commercial sales revenue, respectively. For year-to-date 2016, the resulting decreases were 3.5% and 1.2% for residential and commercial sales revenue, respectively.

Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2016 when compared to the corresponding periods 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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Wholesale Revenues – Non-Affiliates

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$10	17.5	$7	5.7

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 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 second quarter 2016, wholesale revenues from sales to non-affiliates were $67 million compared to $57 million for the corresponding period in 2015. The increase was primarily due to a 40.6% increase in KWH sales as the result of a new wholesale contract effective December 2015, partially offset by a 16.7% 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 $130 million compared to $123 million for the corresponding period in 2015. The increase was primarily due to a 21.1% increase in KWH sales as a result of a new wholesale contract effective December 2015, partially offset by a 12.6% decrease in the price of energy as a result of lower gas prices.

Wholesale Revenues – Affiliates

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(11)	(55.0)	$(4)	(11.4)

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

In the second quarter 2016, wholesale revenues from sales to affiliates were $9 million compared to $20 million for the corresponding period in 2015. The decrease was primarily related to a 44.4% decrease in KWH sales and a 19.2% decrease in the price of energy due to the availability of lower cost generation in the Southern Company system in 2016.

Fuel and Purchased Power Expenses

	Second Quarter 2016 vs. Second Quarter 2015				Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(48	)	(14.0)	$	(89	)	(13.6	)
Purchased power – non-affiliates	(5		)	(11.1)	(10		)	(11.6	)
Purchased power – affiliates	6			12.2	(15		)	(14.6	)
Total fuel and purchased power expenses	$	(47	)		$	(114	)

In the second quarter 2016, total fuel and purchased power expenses were $390 million compared to $437 million for the corresponding period in 2015. The decrease was primarily due to a $38 million decrease related to the average cost of purchased power and a $20 million decrease related to the average cost of fuel. These decreases were partially offset by an $11 million net increase related to the volume of KWHs generated and purchased.

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For year-to-date 2016, fuel and purchased power expenses were $728 million compared to $842 million for the corresponding period in 2015. The decrease was primarily due to a $51 million net decrease related to the volume of KWHs generated and purchased, a $39 million decrease related to the average cost of fuel, and a $24 million decrease related to the average cost of purchased power.

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

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

	Second Quarter 2016	Second Quarter 2015	Year-to-Date 2016	Year-to-Date 2015
Total generation (billions of KWHs)	13	15	28	29
Total purchased power (billions of KWHs)	3	2	4	4
Sources of generation (percent) —
Coal	53	59	46	53
Nuclear	23	20	25	23
Gas	20	15	19	17
Hydro	4	6	10	7
Cost of fuel, generated (cents per net KWH) —
Coal	2.84	2.89	2.85	2.89
Nuclear	0.79	0.82	0.78	0.81
Gas	2.52	3.10	2.49	3.06
Average cost of fuel, generated (cents per net KWH)(a)	2.28	2.50	2.20	2.41
Average cost of purchased power (cents per net KWH)(b)	3.94	5.48	4.37	5.00

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

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

Fuel

In the second quarter 2016, fuel expense was $295 million compared to $343 million for the corresponding period in 2015. The decrease was primarily due to a 17.7% decrease in the volume of KWHs generated by coal and an 18.7% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, partially offset by a 19.9% increase in the volume of KWHs generated by natural gas.

For year-to-date 2016, fuel expense was $564 million compared to $653 million for the corresponding period in 2015. The decrease was primarily due to an 18.6% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and a 16.5% decrease in the volume of KWHs generated by coal, partially offset by a 12.7% increase in the volume of KWHs generated by natural gas.

Purchased Power – Non-Affiliates

For year-to-date 2016, purchased power expense from non-affiliates was $76 million compared to $86 million for the corresponding period in 2015. The decrease was primarily related to a 4.4% decrease in the average cost of purchased power per KWH due to lower natural gas prices and a 4.4% decrease in the amount of energy purchased.

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ALABAMA POWER COMPANY

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 service territory, and the availability of the Southern Company system's generation.

Purchased Power – Affiliates

For year-to-date 2016, purchased power expense from affiliates was $88 million compared to $103 million for the corresponding period in 2015. The decrease was primarily related to an 18.1% decrease in the average cost of purchased power per KWH as a result of lower natural gas prices. The decrease was partially offset by a 4.7% increase in the amount of energy purchased due to the availability of lower cost generation in the Southern Company system in 2016.

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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(15)	(4.1)	$(21)	(2.7)

In the second quarter 2016, other operations and maintenance expenses were $355 million compared to $370 million for the corresponding period in 2015. The decrease was primarily due to decreases of $10 million in employee benefit costs including pension costs and $6 million in distribution overhead line maintenance expenses. These decreases were partially offset by an increase of $5 million in scheduled steam and other power generation outage costs.

For year-to-date 2016, other operations and maintenance expenses were $747 million compared to $768 million for the corresponding period in 2015. The decrease was primarily due to decreases of $19 million in employee benefit costs including pension costs, $10 million in scheduled steam and other power generation outage costs, and $6 million in distribution overhead line maintenance expenses. These decreases were partially offset by an $8 million increase in nuclear generation outage amortization.

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

Depreciation and Amortization

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$15	9.4	$29	9.1

In the second quarter 2016, depreciation and amortization was $175 million compared to $160 million for the corresponding period in 2015. For year-to-date 2016, depreciation and amortization was $347 million compared to $318 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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Taxes Other Than Income Taxes

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$4	4.4	$7	3.8

For year-to-date 2016, taxes other than income taxes were $191 million compared to $184 million for the corresponding period in 2015. The increase was primarily due to increases in state and municipal utility license tax bases, increases in ad valorem taxes primarily due to an increase in assessed value of property, and an increase in payroll taxes.

Allowance for Equity Funds Used During Construction

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(8)	(57.1)	$(13)	(44.8)

In the second quarter 2016, AFUDC equity was $6 million compared to $14 million for the corresponding period in 2015. For year-to-date 2016, AFUDC equity was $16 million compared to $29 million for the corresponding period in 2015. These decreases were primarily associated with capital projects being placed in service for environmental and steam generation in 2016.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$5	7.2	$13	9.7

For year-to-date 2016, interest expense, net of amounts capitalized was $147 million compared to $134 million for the corresponding period in 2015. The increase was primarily due to an increase in debt issuances and a reduction in amounts capitalized, partially offset by maturities and a redemption of long-term debt. See 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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$10	71.4	$7	38.9

In the second quarter 2016, other income (expense), net was $(4) million compared to $(14) million for the corresponding period in 2015. For year-to-date 2016, other income (expense), net was $(11) million compared to $(18) million for the corresponding period in 2015. The changes were primarily due to decreases in donations, partially offset by decreases in sales of non-utility property in 2016.

Income Taxes

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$20	16.4	$10	4.3

In the second quarter 2016, income taxes were $142 million compared to $122 million for the corresponding period in 2015. The increase was primarily due to higher pre-tax earnings in 2016 and state tax credits taken in 2015.

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ALABAMA POWER COMPANY

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For year-to-date 2016, income taxes were $245 million compared to $235 million for the corresponding period in 2015. The increase was primarily due to state tax credits taken in 2015.

Dividends on Preferred and Preference Stock

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	(28.6)	$(8)	(47.1)

For year-to-date 2016, dividends on preferred and preference stock were $9 million compared to $17 million for the corresponding period in 2015. These decreases were 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 and regional haze regulations.

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

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compliance requirements, costs, or deadlines, and all Alabama Power units that are subject to the MATS rule have 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.

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, the Alabama Rivers Alliance and American Rivers filed an additional rehearing request and also filed a petition for review at 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

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 May 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 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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 in additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early 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 June 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

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

Net cash provided from operating activities totaled $803 million for the first six months of 2016, an increase of $206 million as compared to the first six months of 2015. The increase in net cash provided from operating activities was primarily due to the timing of vendor payments and lower income tax payments as a result of bonus depreciation. Net cash used for investing activities totaled $741 million for the first six months of 2016 primarily due to gross property additions related to environmental, distribution, transmission, and steam generation. Net cash provided from financing activities totaled $87 million for the first six months of 2016 primarily due to issuances of long-term debt and a capital contribution from Southern Company, partially offset by a redemption of long-term debt and common stock dividend payments. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2016 include increases of $296 million in property, plant, and equipment, primarily due to additions to environmental, transmission, distribution, and nuclear generation, $248 million in additional paid-in capital due to capital contributions from Southern Company, $240 million in long-term debt primarily due to the issuance of additional senior notes, and $172 million in accumulated deferred income taxes related to bonus depreciation. Other significant changes include decreases of $159 million in other regulatory liabilities, current, primarily due to the timing of fuel cost recovery and $142 million in income taxes receivable following the receipt of a federal income tax refund.

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 $200 million will be required through June 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" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's environmental compliance strategy.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing 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.

53

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

At June 30, 2016, Alabama Power had approximately $343 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2016 were as follows:

Expires												Due Within One Year
2016		2017		2018		2020		Total		Unused		Term Out		No Term Out
(in millions)								(in millions)				(in millions)
$	3	$	32	$	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 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 June 30, 2016 was approximately $890 million. In addition, at June 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 June 30, 2016. No short-term debt was outstanding at June 30, 2016.

54

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 June 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	$	333

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.

55

GEORGIA POWER COMPANY

56

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,907		$	1,872		$	3,624		$	3,686
Wholesale revenues, non-affiliates	40			50			82			118
Wholesale revenues, affiliates	10			4			15			12
Other revenues	94			90			202			178
Total operating revenues	2,051			2,016			3,923			3,994
Operating Expenses:
Fuel	439			503			815			1,029
Purchased power, non-affiliates	92			78			175			138
Purchased power, affiliates	111			115			250			263
Other operations and maintenance	439			467			896			943
Depreciation and amortization	214			202			425			418
Taxes other than income taxes	100			97			197			195
Total operating expenses	1,395			1,462			2,758			2,986
Operating Income	656			554			1,165			1,008
Other Income and (Expense):
Interest expense, net of amounts capitalized	(99		)	(93		)	(193		)	(182		)
Other income (expense), net	8			1			26			16
Total other income and (expense)	(91		)	(92		)	(167		)	(166		)
Earnings Before Income Taxes	565			462			998			842
Income taxes	213			180			373			320
Net Income	352			282			625			522
Dividends on Preferred and Preference Stock	5			5			9			9
Net Income After Dividends on Preferred and Preference Stock	$	347		$	277		$	616		$	513

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions)				(in millions)
Net Income	$	352	$	282	$	625	$	522
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $9, $-, and $-, respectively	—		14		—		—
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $1, and $1, respectively	1		1		1		1
Total other comprehensive income (loss)	1		15		1		1
Comprehensive Income	$	353	$	297	$	626	$	523

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

57

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	625		$	522
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	530			512
Deferred income taxes	157			(6		)
Allowance for equity funds used during construction	(24		)	(10		)
Deferred expenses	39			28
Contract amendment	—			(118		)
Settlement of asset retirement obligations	(52		)	(9		)
Other, net	6			9
Changes in certain current assets and liabilities —
-Receivables	(25		)	(21		)
-Fossil fuel stock	61			101
-Prepaid income taxes	(1		)	86
-Other current assets	11			(38		)
-Accounts payable	6			(110		)
-Accrued taxes	(137		)	(125		)
-Accrued compensation	(44		)	(61		)
-Other current liabilities	17			14
Net cash provided from operating activities	1,169			774
Investing Activities:
Property additions	(1,058		)	(853		)
Nuclear decommissioning trust fund purchases	(386		)	(655		)
Nuclear decommissioning trust fund sales	380			649
Cost of removal, net of salvage	(34		)	(46		)
Change in construction payables, net of joint owner portion	(75		)	26
Prepaid long-term service agreements	(14		)	(40		)
Other investing activities	17			28
Net cash used for investing activities	(1,170		)	(891		)
Financing Activities:
Increase in notes payable, net	39			44
Proceeds —
Capital contributions from parent company	239			23
Pollution control revenue bonds	—			170
Senior notes	650			—
FFB loan	300			600
Short-term borrowings	—			250
Redemptions and repurchases —
Pollution control revenue bonds	(4		)	(65		)
Senior notes	(500		)	(125		)
Short-term borrowings	—			(250		)
Payment of common stock dividends	(653		)	(517		)
Other financing activities	(16		)	(13		)
Net cash provided from financing activities	55			117
Net Change in Cash and Cash Equivalents	54			—
Cash and Cash Equivalents at Beginning of Period	67			24
Cash and Cash Equivalents at End of Period	$	121		$	24
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $10 and $5 capitalized for 2016 and 2015, respectively)	$	174		$	170
Income taxes, net	78			240
Noncash transactions — Accrued property additions at end of period	288			171

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

58

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2016			At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	121		$	67
Receivables —
Customer accounts receivable	592			541
Unbilled revenues	293			188
Joint owner accounts receivable	51			227
Income taxes receivable, current	—			114
Other accounts and notes receivable	52			57
Affiliated	16			18
Accumulated provision for uncollectible accounts	(2		)	(2		)
Fossil fuel stock, at average cost	340			402
Materials and supplies, at average cost	477			449
Vacation pay	93			91
Prepaid income taxes	157			156
Other regulatory assets, current	123			123
Other current assets	55			92
Total current assets	2,368			2,523
Property, Plant, and Equipment:
In service	33,045			31,841
Less accumulated provision for depreciation	11,087			10,903
Plant in service, net of depreciation	21,958			20,938
Other utility plant, net	174			171
Nuclear fuel, at amortized cost	566			572
Construction work in progress	4,655			4,775
Total property, plant, and equipment	27,353			26,456
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	62			64
Nuclear decommissioning trusts, at fair value	819			775
Miscellaneous property and investments	42			43
Total other property and investments	923			882
Deferred Charges and Other Assets:
Deferred charges related to income taxes	677			679
Other regulatory assets, deferred	2,524			2,152
Other deferred charges and assets	170			173
Total deferred charges and other assets	3,371			3,004
Total Assets	$	34,015		$	32,865

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

59

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	658		$	712
Notes payable	197			158
Accounts payable —
Affiliated	407			411
Other	541			750
Customer deposits	268			264
Accrued taxes —
Accrued income taxes	—			12
Other accrued taxes	199			325
Accrued interest	107			99
Accrued vacation pay	64			62
Accrued compensation	88			142
Asset retirement obligations, current	323			179
Other current liabilities	299			181
Total current liabilities	3,151			3,295
Long-term Debt	10,120			9,616
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,788			5,627
Deferred credits related to income taxes	104			105
Accumulated deferred investment tax credits	199			204
Employee benefit obligations	901			949
Asset retirement obligations, deferred	2,249			1,737
Other deferred credits and liabilities	302			347
Total deferred credits and other liabilities	9,543			8,969
Total Liabilities	22,814			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	6,527			6,275
Retained earnings	4,024			4,061
Accumulated other comprehensive loss	(14		)	(15		)
Total common stockholder's equity	10,935			10,719
Total Liabilities and Stockholder's Equity	$	34,015		$	32,865

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

60

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2016 vs. SECOND 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.

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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$70	25.3	$103	20.1

Georgia Power's net income after dividends on preferred and preference stock was $347 million for the second quarter 2016 compared to $277 million for the corresponding period in 2015. For year-to-date 2016, net income after dividends on preferred and preference stock was $616 million compared to $513 million for the corresponding period in 2015. The increases were 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, and lower non-fuel operating expenses. The increases were partially offset by decreases in retail base revenues due to milder weather for year-to-date 2016 compared to the corresponding period in 2015.

61

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$35	1.9	$(62)	(1.7)

In the second quarter 2016, retail revenues were $1.91 billion compared to $1.87 billion for the corresponding period in 2015. For year-to-date 2016, retail revenues were $3.62 billion compared to $3.69 billion for the corresponding period in 2015.

Details of the changes in retail revenues were as follows:

	Second Quarter 2016					Year-to-Date 2016
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	1,872				$	3,686
Estimated change resulting from –
Rates and pricing	101			5.4		146			3.9
Sales growth (decline)	(6		)	(0.3	)	2			0.1
Weather	2			0.1		(31		)	(0.8	)
Fuel cost recovery	(62		)	(3.3	)	(179		)	(4.9	)
Retail – current year	$	1,907		1.9	%	$	3,624		(1.7	)%

Revenues associated with changes in rates and pricing increased in the second 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, as well as 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 decreased in the second quarter 2016 and increased slightly year-to-date 2016 when compared to the corresponding periods in 2015. Weather-adjusted residential KWH sales increased 0.6%, weather-adjusted commercial KWH sales decreased 1.7%, and weather-adjusted industrial KWH sales increased 0.6% in the second quarter 2016 when compared to the corresponding period in 2015. For year-to-date 2016, weather-adjusted residential KWH sales increased 0.5%, weather-adjusted commercial KWH sales decreased 0.5%, and weather-adjusted industrial KWH sales increased 1.0% when compared to the corresponding period in 2015. An increase of approximately 26,000 residential customers since June 30, 2015 contributed to the increase in weather-adjusted residential KWH sales. A decline in average customer usage contributed to the decrease in weather-adjusted commercial KWH sales, partially offset by an increase of approximately 3,000 commercial customers since June 30, 2015. Increased demand in the paper, rubber, and non-manufacturing sectors was the main contributor to the increase in weather-adjusted industrial KWH sales, partially offset by decreased demand in the pipeline, military, and textiles sectors.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased $62 million and $179 million in the second quarter and year-to-date 2016, respectively, when compared to the corresponding periods in 2015 primarily due to lower coal and natural gas prices and lower energy sales. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.

62

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Non-Affiliates

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(10)	(20.0)	$(36)	(30.5)

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 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 second quarter 2016, wholesale revenues from sales to non-affiliates were $40 million compared to $50 million for the corresponding period in 2015 related to an $8 million decrease in capacity revenues and a $2 million decrease in energy revenues. For year-to-date 2016, wholesale revenues from sales to non-affiliates were $82 million compared to $118 million for the corresponding period in 2015 related to a $21 million decrease in capacity revenues and a $15 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 after March 31, 2015 as a result of Georgia Power's environmental compliance strategy. The decreases in energy revenues were primarily due to lower fuel prices. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" and "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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$4	4.4	$24	13.5

In the second quarter 2016, other revenues were $94 million compared to $90 million for the corresponding period in 2015. The increase was primarily due to a $3 million increase in outdoor lighting revenues. For year-to-date 2016, other revenues were $202 million compared to $178 million for the corresponding period in 2015. The increase was primarily due to a $14 million increase related to customer temporary facilities services revenues and a $6 million increase in outdoor lighting revenues.

Fuel and Purchased Power Expenses

	Second Quarter 2016 vs. Second Quarter 2015					Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	(64	)	(12.7	)	$	(214	)	(20.8	)
Purchased power – non-affiliates	14			17.9		37			26.8
Purchased power – affiliates	(4		)	(3.5	)	(13		)	(4.9	)
Total fuel and purchased power expenses	$	(54	)			$	(190	)

63

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the second quarter 2016, total fuel and purchased power expenses were $642 million compared to $696 million in the corresponding period in 2015. The decrease in the second quarter 2016 was due to a decrease of $63 million in the average cost of fuel and purchased power related to lower coal and natural gas prices, partially offset by a $9 million net increase related to the volume of KWHs generated and purchased to meet customer demand.

For year-to-date 2016, total fuel and purchased power expenses were $1.24 billion compared to $1.43 billion in the corresponding period in 2015. The decrease in year-to-date 2016 was primarily due to a decrease of $152 million in the average cost of fuel and purchased power related to lower coal and natural gas prices and a $38 million net decrease related to the volume of KWHs generated and purchased, primarily as a result of milder weather as compared to the corresponding period in 2015 resulting in lower customer demand.

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

	Second Quarter 2016	Second Quarter 2015	Year-to-Date 2016	Year-to-Date 2015
Total generation (billions of KWHs)	17	17	33	34
Total purchased power (billions of KWHs)	6	6	12	11
Sources of generation (percent) —
Coal	36	40	33	37
Nuclear	24	24	24	23
Gas	38	34	40	38
Hydro	2	2	3	2
Cost of fuel, generated (cents per net KWH) —
Coal	3.37	3.75	3.45	4.18
Nuclear	0.84	0.85	0.85	0.71
Gas	2.18	2.67	2.10	2.65
Average cost of fuel, generated (cents per net KWH)	2.29	2.66	2.26	2.76
Average cost of purchased power (cents per net KWH)(*)	4.45	4.56	4.38	4.47

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

Fuel

In the second quarter 2016, fuel expense was $439 million compared to $503 million in the corresponding period in 2015. The decrease was primarily due to a 13.9% decrease in the average cost of fuel per KWH generated primarily resulting from lower coal and natural gas prices and a 10.4% decrease in the volume of KWHs generated by coal, partially offset by a 9.7% increase in the volume of KWHs generated by natural gas.

For year-to-date 2016, fuel expense was $815 million compared to $1.03 billion in the corresponding period in 2015. The decrease was primarily due to an 18.1% decrease in the average cost of fuel per KWH generated primarily resulting from lower coal and natural gas prices and a 12.7% decrease in the volume of KWHs generated by coal.

64

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Purchased Power – Non-Affiliates

In the second quarter 2016, purchased power expense from non-affiliates was $92 million compared to $78 million in the corresponding period in 2015. The increase was primarily due to a 19.7% increase in the volume of KWHs purchased, partially offset by a 4.7% 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 $175 million compared to $138 million in the corresponding period in 2015. The increase was primarily due to a 38.5% increase in the volume of KWHs purchased, partially offset by a 13.9% 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 service territory, and the availability of the Southern Company system's generation.

Purchased Power – Affiliates

In the second quarter 2016, purchased power expense from affiliates was $111 million compared to $115 million in the corresponding period in 2015. The decrease was the result of a 3.0% decrease in the average cost per KWH purchased, partially offset by a 5.2% increase in the volume of KWHs purchased as Georgia Power's units generally dispatched at a higher cost than other Southern Company system resources. For year-to-date 2016, purchased power expense from affiliates was $250 million compared to $263 million in the corresponding period in 2015. The decrease was the result of a 1.6% decrease in the average cost per KWH purchased and a 2.8% decrease in the volume of KWHs purchased.

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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(28)	(6.0)	$(47)	(5.0)

In the second quarter 2016, other operations and maintenance expenses were $439 million compared to $467 million in the corresponding period in 2015. The decrease was primarily due to decreases of $25 million in scheduled generation outage and maintenance costs and $11 million in employee benefits including pension costs, partially offset by an increase of $10 million in transmission expenses.

For year-to-date 2016, other operations and maintenance expenses were $896 million compared to $943 million in the corresponding period in 2015. The decrease was primarily due to decreases of $42 million in generation scheduled outage and maintenance costs and $18 million in employee benefits including pension costs, partially offset by an increase of $14 million in transmission expenses.

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

Depreciation and Amortization

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$12	5.9	$7	1.7

In the second quarter 2016, depreciation and amortization was $214 million compared to $202 million in the corresponding period in 2015. The increase was primarily due to a $9 million increase to additional plant in service

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and a $9 million increase in other cost of removal, partially offset by a decrease of $5 million related to amortization of nuclear construction financing costs that was completed in December 2015.

For year-to-date 2016, depreciation and amortization was $425 million compared to $418 million in the corresponding period in 2015. The increase was primarily due to a $16 million increase to additional plant in service and a $9 million increase in other cost of removal, partially offset by a decrease of $9 million related to amortization of nuclear construction financing costs that was completed in December 2015 and a decrease of $9 million related to unit retirements.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$6	6.5	$11	6.0

In the second quarter 2016, interest expense, net of amounts capitalized was $99 million compared to $93 million in the corresponding period in 2015. The increase was primarily due to a $10 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.

For year-to-date 2016, interest expense, net of amounts capitalized was $193 million compared to $182 million in the corresponding period in 2015. The increase was primarily due to a $16 million increase in interest due to additional long-term borrowings from the FFB, partially offset by an increase of $5 million in AFUDC debt.

Income Taxes

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$33	18.3	$53	16.6

In the second quarter 2016, income taxes were $213 million compared to $180 million in the corresponding period in 2015. For year-to-date 2016, income taxes were $373 million compared to $320 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.

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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. 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 and regional haze regulations.

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 Georgia Power units that are subject to the MATS rule have 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.

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 July 7, 2016, the Georgia Environmental Protection Division (EPD) proposed 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 proposed Georgia EPD regulations are expected to be finalized in October 2016 and 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 June 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

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and 4 are being collected through the NCCR tariff and fuel costs are collected through separate fuel cost recovery tariffs. See "Fuel Cost Recovery" below 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 fuel cost recovery and the NCCR tariff, respectively.

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.

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.

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. Georgia Power exercised its contractual option to sell its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc., with an expected closing date in late August 2016.

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 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. 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 2019 general base rate case.

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.

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

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 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.

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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 (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) as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated Vogtle Owner's costs associated with the proposed 18-month Contractor delay 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. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service and contemplated in a general base rate case, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.

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 $250 million had been paid as of June 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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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. The Staff is conducting a review of all costs incurred related to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the Contractor Settlement Agreement, and is authorized to engage in related settlement discussions with Georgia Power and any intervenors.

The order provides that the Staff is required to report to the Georgia PSC by October 19, 2016 with respect to the status of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of Plant Vogtle Units 3 and 4, the Georgia PSC will then conduct a hearing to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing Georgia Power to file a request for an amendment to the certificate for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority.

The Georgia PSC has approved thirteen VCM reports covering the periods through June 30, 2015, including construction capital costs incurred, which through that date totaled $3.1 billion. On February 26, 2016, Georgia Power filed its fourteenth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2015. The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. Georgia Power is requesting approval of $160 million of construction capital costs incurred during that period. Georgia Power incurred approximately $141 million in total construction capital costs during the period of January 1, 2016 through June 30, 2016. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.7 billion as of June 30, 2016. The in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion, of which $1.1 billion had been incurred through June 30, 2016.

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, assembly, delivery, and installation of plant equipment, the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS 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.

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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 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. Georgia Power expects to record charges of approximately $30 million during the remainder of 2016. Such charges 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

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

Net cash provided from operating activities totaled $1.17 billion for the first six months of 2016 compared to $774 million for the corresponding period in 2015. The increase was primarily due to the timing of vendor payments. Net cash used for investing activities totaled $1.17 billion for the first six months of 2016 compared to $891 million 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 provided from financing activities totaled $55 million for the first six months of 2016 compared to $117 million in the corresponding period in 2015. The decrease in cash provided from financing activities is primarily due to maturities of long-term debt, higher common stock dividends, and lower borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, partially offset by senior note issuances and higher capital contributions received 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 six months of 2016 include an increase in property, plant, and equipment of $897 million to comply with environmental standards and construction of generation, transmission, and distribution facilities and increases in current and deferred ARO liabilities of $656 million and other regulatory assets, deferred of $372 million primarily related to changes in ash pond closure strategy. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – 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 $658 million will be required through June 30, 2017 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

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GEORGIA POWER COMPANY

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing 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.

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 June 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 June 30, 2016, Georgia Power's current liabilities exceeded current assets by $783 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 June 30, 2016, Georgia Power had approximately $121 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks at June 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.

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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

A portion of the unused credit with banks is allocated to provide liquidity support to Georgia Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2016 was approximately $868 million. In addition, at June 30, 2016, Georgia Power had $212 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each 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 June 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	$	197	0.8	%	$	164	0.8	%	$	443

(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 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 June 30, 2016 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	87
Below BBB- and/or Baa3	$	1,288

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

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 power generation facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar power or wind generation 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 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. The interest rate applicable to the $300 million principal amount is 2.571% for an interest period that extends to 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 addition to any financings that may be necessary to meet capital requirements and contractual obligations, Georgia Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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GULF POWER COMPANY

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GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	319		$	327		$	602		$	620
Wholesale revenues, non-affiliates	15			27			31			52
Wholesale revenues, affiliates	15			13			36			35
Other revenues	16			17			31			34
Total operating revenues	365			384			700			741
Operating Expenses:
Fuel	107			122			201			232
Purchased power, non-affiliates	32			25			62			50
Purchased power, affiliates	4			9			5			17
Other operations and maintenance	77			91			155			185
Depreciation and amortization	42			40			80			60
Taxes other than income taxes	29			28			58			56
Total operating expenses	291			315			561			600
Operating Income	74			69			139			141
Other Income and (Expense):
Allowance for equity funds used during construction	—			3			—			8
Interest expense, net of amounts capitalized	(12		)	(12		)	(25		)	(26		)
Other income (expense), net	(1		)	(1		)	(2		)	(2		)
Total other income and (expense)	(13		)	(10		)	(27		)	(20		)
Earnings Before Income Taxes	61			59			112			121
Income taxes	24			21			44			44
Net Income	37			38			68			77
Dividends on Preference Stock	3			3			5			5
Net Income After Dividends on Preference Stock	$	34		$	35		$	63		$	72

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2016			2015		2016			2015
	(in millions)					(in millions)
Net Income	$	37		$	38	$	68		$	77
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1), $-, $(3), and $-, respectively	(1		)	—		(4		)	—
Total other comprehensive income (loss)	(1		)	—		(4		)	—
Comprehensive Income	$	36		$	38	$	64		$	77

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

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GULF POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	68		$	77
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	83			64
Deferred income taxes	16			40
Other, net	(3		)	3
Changes in certain current assets and liabilities —
-Receivables	(6		)	(15		)
-Fossil fuel stock	34			6
-Prepaid income taxes	2			12
-Other current assets	(1		)	1
-Accounts payable	(7		)	(9		)
-Accrued taxes	17			15
-Accrued compensation	(12		)	(10		)
-Other current liabilities	4			(1		)
Net cash provided from operating activities	195			183
Investing Activities:
Property additions	(68		)	(148		)
Cost of removal, net of salvage	(4		)	(7		)
Change in construction payables	(7		)	(15		)
Other investing activities	(5		)	(4		)
Net cash used for investing activities	(84		)	(174		)
Financing Activities:
Increase in notes payable, net	46			4
Proceeds —
Common stock issued to parent	—			20
Short-term borrowings	—			40
Redemptions and repurchases — Senior notes	(125		)	—
Payment of common stock dividends	(60		)	(65		)
Other financing activities	—			(3		)
Net cash used for financing activities	(139		)	(4		)
Net Change in Cash and Cash Equivalents	(28		)	5
Cash and Cash Equivalents at Beginning of Period	74			39
Cash and Cash Equivalents at End of Period	$	46		$	44
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $- and $3 capitalized for 2016 and 2015, respectively)	$	28		$	26
Income taxes, net	(3		)	(9		)
Noncash transactions — Accrued property additions at end of period	13			28

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

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GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2016			At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	46		$	74
Receivables —
Customer accounts receivable	81			76
Unbilled revenues	77			54
Under recovered regulatory clause revenues	5			20
Income taxes receivable, current	—			27
Other accounts and notes receivable	3			9
Affiliated companies	10			1
Accumulated provision for uncollectible accounts	(1		)	(1		)
Fossil fuel stock, at average cost	74			108
Materials and supplies, at average cost	56			56
Other regulatory assets, current	65			90
Other current assets	17			22
Total current assets	433			536
Property, Plant, and Equipment:
In service	5,032			5,045
Less accumulated provision for depreciation	1,351			1,296
Plant in service, net of depreciation	3,681			3,749
Other utility plant, net	—			62
Construction work in progress	68			48
Total property, plant, and equipment	3,749			3,859
Other Property and Investments	4			4
Deferred Charges and Other Assets:
Deferred charges related to income taxes	60			61
Other regulatory assets, deferred	523			427
Other deferred charges and assets	49			33
Total deferred charges and other assets	632			521
Total Assets	$	4,818		$	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 June 30, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	195		$	110
Notes payable	187			142
Accounts payable —
Affiliated	46			55
Other	44			44
Customer deposits	36			36
Accrued taxes —
Accrued income taxes	5			4
Other accrued taxes	25			9
Accrued interest	8			9
Accrued compensation	13			25
Deferred capacity expense, current	22			22
Other regulatory liabilities, current	19			22
Liabilities from risk management activities	32			49
Other current liabilities	30			40
Total current liabilities	662			567
Long-term Debt	987			1,193
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	905			893
Employee benefit obligations	126			129
Deferred capacity expense	130			141
Asset retirement obligations	128			113
Other cost of removal obligations	237			233
Other regulatory liabilities, deferred	46			47
Other deferred credits and liabilities	90			102
Total deferred credits and other liabilities	1,662			1,658
Total Liabilities	3,311			3,418
Preference Stock	147			147
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — June 30, 2016: 5,642,717 shares
— December 31, 2015: 5,642,717 shares	503			503
Paid-in capital	573			567
Retained earnings	288			285
Accumulated other comprehensive loss	(4		)	—
Total common stockholder's equity	1,360			1,355
Total Liabilities and Stockholder's Equity	$	4,818		$	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

SECOND QUARTER 2016 vs. SECOND 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 will cover approximately 24% of the unit through 2019. The expiration of these contracts will have a material negative impact on Gulf Power's earnings in 2016 and may continue to have a material negative impact in future years until Gulf Power is able to find a suitable alternative related to this asset. Gulf Power is actively evaluating alternatives, including, without limitation, rededication of the asset to serve retail customers for whom it was originally planned and built, replacement long-term wholesale contracts or other sales into the wholesale market, or an asset sale. 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 the contracts expire. The ultimate outcome of this matter cannot be determined at this time.

In 2013, the Florida PSC voted to approve a settlement agreement (Rate Case Settlement Agreement) related to Gulf Power's retail base rate case. Under the terms of the Rate Case Settlement Agreement, Gulf Power is authorized to reduce depreciation and record a regulatory asset as an offset to the other cost of removal regulatory liability in an aggregate amount up to $62.5 million from January 2014 through June 2017, of which $34.9 million had been recorded as of June 30, 2016, and to accrue a return similar to AFUDC on certain transmission system upgrades placed into service after January 2014 until January 1, 2017. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters– Retail Base Rate Case" herein for additional details of the Rate Case Settlement Agreement.

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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(2.9)	$(9)	(12.5)

Gulf Power's net income after dividends on preference stock for the second quarter 2016 was $34 million compared to $35 million for the corresponding period in 2015. The decrease was primarily due to lower non-affiliated wholesale capacity revenues, partially offset by lower operations and maintenance expenses.

Gulf Power's net income after dividends on preference stock for year-to-date 2016 was $63 million compared to $72 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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(8)	(2.4)	$(18)	(2.9)

In the second quarter 2016, retail revenues were $319 million compared to $327 million for the corresponding period in 2015. For year-to-date 2016, retail revenues were $602 million compared to $620 million for the corresponding period in 2015.

Details of the changes in retail revenues were as follows:

	Second Quarter 2016					Year-to-Date 2016
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	327				$	620
Estimated change resulting from –
Rates and pricing	9			2.8		17			2.7
Sales growth (decline)	(1		)	(0.3	)	1			0.2
Weather	(2		)	(0.6	)	(7		)	(1.1	)
Fuel and other cost recovery	(14		)	(4.3	)	(29		)	(4.7	)
Retail – current year	$	319		(2.4	)%	$	602		(2.9	)%

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

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 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.

Revenues attributable to changes in sales decreased slightly in the second quarter 2016 when compared to the corresponding period in 2015. For the second quarter 2016, weather-adjusted KWH sales to residential and commercial customers decreased 1.3% and 2.6%, respectively, due to lower customer usage, partially offset by

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

customer growth. KWH sales to industrial customers increased 1.2% for the second quarter 2016 primarily due to decreased customer co-generation, partially offset by changes in customers' operations.

Revenues attributable to changes in sales increased slightly year-to-date 2016 when compared to the corresponding period in 2015. Weather-adjusted KWH sales to residential customers increased 0.6% due to customer growth, partially offset by lower customer usage. Weather-adjusted KWH sales to commercial customers decreased 1.4% due to lower customer usage, partially offset by customer growth. KWH sales to industrial customers increased 3.9% primarily due to decreased customer co-generation, partially offset by changes in customers' operations.

Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2016 when compared to the corresponding periods in 2015, primarily due to a decrease in fuel costs as a result of decreased generation and lower purchased power energy costs. Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and the difference between projected and actual costs and revenues related to energy conservation and environmental compliance. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.

Wholesale Revenues – Non-Affiliates

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(12)	(44.4)	$(21)	(40.4)

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 service territory, and the availability of the Southern Company system's generation.

In the second quarter 2016, wholesale revenues from sales to non-affiliates were $15 million compared to $27 million for the corresponding period in 2015. For year-to-date 2016, wholesale revenues from sales to non-affiliates were $31 million compared to $52 million for the corresponding period in 2015. These decreases were primarily due to a 52.5% and 47.6% decrease for the second quarter and year-to-date 2016, respectively, in capacity revenues resulting from the expiration of Plant Scherer Unit 3 long-term sales agreements.

Fuel and Purchased Power Expenses

	Second Quarter 2016 vs. Second Quarter 2015					Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	(15	)	(12.3	)	$	(31	)	(13.4	)
Purchased power – non-affiliates	7			28.0		12			24.0
Purchased power – affiliates	(5		)	(55.6	)	(12		)	(70.6	)
Total fuel and purchased power expenses	$	(13	)			$	(31	)

In the second quarter 2016, total fuel and purchased power expenses were $143 million compared to $156 million for the corresponding period in 2015. The decrease was primarily due to a $14 million decrease in the average cost of fuel and purchased power as a result of lower generation from Gulf Power's coal-fired resources.

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For year-to-date 2016, total fuel and purchased power expenses were $268 million compared to $299 million for the corresponding period in 2015. The decrease was primarily the result of a $37 million decrease due to the lower average cost of fuel and purchased power as a result of lower generation from Gulf Power's coal-fired resources, partially offset by a $6 million increase related to the volume of KWHs generated and purchased.

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

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

	Second Quarter 2016	Second Quarter 2015	Year-to-Date 2016	Year-to-Date 2015
Total generation (millions of KWHs)	2,064	2,360	3,880	4,596
Total purchased power (millions of KWHs)	1,629	1,336	3,389	2,594
Sources of generation (percent) –
Coal	54	61	48	60
Gas	46	39	52	40
Cost of fuel, generated (cents per net KWH) –
Coal	4.14	4.05	4.05	4.02
Gas	4.11	4.38	3.92	4.17
Average cost of fuel, generated (cents per net KWH)	4.12	4.18	3.98	4.08
Average cost of purchased power (cents per net KWH)(*)	3.50	4.25	3.35	4.31

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

Fuel

In the second quarter 2016, fuel expense was $107 million compared to $122 million for the corresponding period in 2015. The decrease was primarily due to a 22.5% decrease in the volume of KWHs generated by Gulf Power's coal-fired generation resources and a 1.4% decrease in the average cost of fuel. The decreases were partially offset by a 2.8% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.

For year-to-date 2016, fuel expense was $201 million compared to $232 million for the corresponding period in 2015. The decrease was primarily due to a 31.4% decrease in the volume of KWHs generated by Gulf Power's coal-fired generation resources and a 2.5% decrease in the average cost of fuel. The decreases were partially offset by a 7.7% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.

Purchased Power – Non-Affiliates

In the second quarter 2016, purchased power expense from non-affiliates was $32 million compared to $25 million for the corresponding period in 2015. The increase was primarily due to a 49.9% increase in the volume of KWHs purchased due to the availability of lower cost energy, partially offset by a 25.8% decrease in the average cost per KWH purchased due to lower energy costs from gas-fired and wind market resources.

For year-to-date 2016, purchased power expense from non-affiliates was $62 million compared to $50 million for the corresponding period in 2015. The increase was primarily due to a 61.8% increase in the volume of KWHs purchased due to the availability of lower cost energy, partially offset by a 29.2% decrease in the average cost per KWH purchased due to lower energy costs from gas-fired and wind market resources.

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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 service territory, and the availability of the Southern Company system's generation.

Purchased Power – Affiliates

In the second quarter 2016, purchased power expense from affiliates was $4 million compared to $9 million for the corresponding period in 2015. The decrease was primarily due to a 47.9% decrease in the volume of KWHs purchased due to lower territorial loads resulting from milder weather and a 22.7% decrease in the average cost per KWH purchased due to lower power pool interchange rates as a result of lower natural gas prices and lower off-peak energy prices of renewable market resources.

For year-to-date 2016, purchased power expense from affiliates was $5 million compared to $17 million for the corresponding period in 2015. The decrease was primarily due to a 54.5% decrease in the volume of KWHs purchased due to lower territorial loads resulting from milder weather and a 30.5% decrease in the average cost per KWH purchased due to lower power pool interchange rates as a result of lower natural gas 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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(14)	(15.4)	$(30)	(16.2)

In the second quarter 2016, other operations and maintenance expenses were $77 million compared to $91 million for the corresponding period in 2015. For year-to-date 2016, other operations and maintenance expenses were $155 million compared to $185 million for the corresponding period in 2015. These decreases were primarily due to decreases in routine and planned maintenance expenses at generation 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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$2	5.0	$20	33.3

For year-to-date 2016, depreciation and amortization was $80 million compared to $60 million for the corresponding period in 2015. The increase was primarily due to $13 million less of a reduction in depreciation compared to the corresponding period in 2015, as authorized in the Rate Case Settlement Agreement, as well as property additions at generation, transmission, and distribution facilities.

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 Case" herein for additional information.

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Allowance for Equity Funds Used During Construction

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(3)	N/M	$(8)	N/M

N/M - Not meaningful

In the second quarter and year-to-date 2016, AFUDC equity was immaterial compared to $3 million and $8 million for the corresponding periods in 2015, respectively. These decreases were primarily due to environmental control projects at generation 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, and the successful remarketing of wholesale capacity as current contracts expire. 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 and regional haze regulations.

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 have 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.

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 (205 MWs) 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 will cover approximately 24% of the unit through 2019. The expiration of these contracts will have a material negative impact on Gulf Power's earnings in 2016 and may continue to have a material negative impact in future years until Gulf Power is able to find a suitable alternative related to this asset. Gulf Power is actively evaluating alternatives, including, without limitation, rededication of the asset to serve retail customers for whom it was originally planned and built, replacement long-term wholesale contracts or other sales into the wholesale market, or an asset sale. 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 the contracts expire. The ultimate outcome of this matter cannot be determined at this time.

Retail Base Rate Case

In 2013, the Florida PSC approved the 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, 2015, and the first six months of 2016, Gulf Power recognized reductions in depreciation of $8.4 million, $20.1 million, and $6.4 million, respectively.

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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.

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.

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 has 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. This amount is comprised of the reclassification of the net book value of these units from other utility plant, net and the associated materials and supplies, both as of March 31, 2016. The retirement of these units is not expected to have a material impact on Gulf Power's financial statements as Gulf Power expects to recover these amounts through its rates; however, the ultimate outcome depends on future rate proceedings with the Florida PSC and cannot be determined at this time.

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

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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 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 in 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 June 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 $195 million for the first six months of 2016 compared to $183 million for the corresponding period in 2015. The $12 million increase in net cash was primarily due to a federal income tax refund and the timing of fossil fuel stock purchases, partially offset by increases in accounts receivable. Net cash used for investing activities totaled $84 million in the first six months of 2016 primarily due to property additions to utility plant. Net cash used for financing activities totaled $139 million for the first six months of 2016 primarily due to the payment of common stock dividends and a redemption of long-term debt, partially offset by an increase 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 six months of 2016 include decreases of $125 million in long-term debt due to a redemption and $110 million in net property, plant, and equipment primarily due to the retirement of Plant Smith Units 1 and 2.

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

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interest, leases, derivative obligations, preference stock dividends, purchase commitments, and trust funding requirements. Approximately $195 million will be required through June 30, 2017 to fund maturities of long-term debt. See "Financing Activities" herein for additional information.

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

Sources of Capital

Gulf Power plans to obtain the funds required 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 June 30, 2016, Gulf Power had approximately $46 million of cash and cash equivalents. Committed credit arrangements with banks at June 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)
$	75	$	40	$	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

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revenue bonds outstanding requiring liquidity support as of June 30, 2016 was approximately $82 million. In addition, at June 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.

Details of short-term borrowings were as follows:

	Short-term Debt at June 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	$	87	0.8	%	$	62	0.8	%	$	94
Short-term bank debt	100		1.2	%	54		1.2	%	100
Total	$	187	1.0	%	$	116	1.0	%

(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 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 June 30, 2016 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	137
Below BBB- and/or Baa3	$	526

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 second 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 is

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limited because its long-term sales agreements shift substantially all fuel cost responsibility to the purchaser. However, Gulf Power could become 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. Gulf Power is actively evaluating alternatives, including, without limitation, rededication of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs) to serve retail customers for whom it was originally planned and built, replacement long-term wholesale contracts or other sales into the wholesale market, or an asset sale. 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 the contracts expire. The ultimate outcome of this matter cannot be determined at this time.

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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MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	206		$	189		$	389		$	357
Wholesale revenues, non-affiliates	60			63			120			141
Wholesale revenues, affiliates	7			18			16			45
Other revenues	4			5			8			9
Total operating revenues	277			275			533			552
Operating Expenses:
Fuel	81			115			157			229
Purchased power, non-affiliates	1			2			1			3
Purchased power, affiliates	4			2			9			4
Other operations and maintenance	68			68			136			144
Depreciation and amortization	45			30			84			57
Taxes other than income taxes	25			23			50			48
Estimated loss on Kemper IGCC	81			23			134			32
Total operating expenses	305			263			571			517
Operating Income (Loss)	(28		)	12			(38		)	35
Other Income and (Expense):
Allowance for equity funds used during construction	30			25			59			53
Interest expense, net of amounts capitalized	(15		)	30			(31		)	19
Other income (expense), net	(1		)	(1		)	(3		)	(2		)
Total other income and (expense)	14			54			25			70
Earnings (Loss) Before Income Taxes	(14		)	66			(13		)	105
Income taxes (benefit)	(17		)	16			(27		)	20
Net Income	3			50			14			85
Dividends on Preferred Stock	1			1			1			1
Net Income After Dividends on Preferred Stock	$	2		$	49		$	13		$	84

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions)				(in millions)
Net Income	$	3	$	50	$	14	$	85
Other comprehensive income (loss)	—		—		—		—
Comprehensive Income	$	3	$	50	$	14	$	85

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

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CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	14		$	85
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	82			55
Deferred income taxes	(16		)	694
Investment tax credits	—			32
Allowance for equity funds used during construction	(59		)	(53		)
Regulatory assets associated with Kemper IGCC	(10		)	(50		)
Estimated loss on Kemper IGCC	134			32
Income taxes receivable, non-current	—			(544		)
Other, net	3			8
Changes in certain current assets and liabilities —
-Receivables	15			6
-Fossil fuel stock	6			5
-Prepaid income taxes	34			24
-Other current assets	(3		)	(7		)
-Accounts payable	(12		)	(25		)
-Accrued taxes	19			(51		)
-Accrued interest	—			(7		)
-Accrued compensation	(12		)	(12		)
-Over recovered regulatory clause revenues	4			32
-Mirror CWIP	—			82
-Customer liability associated with Kemper refunds	(69		)	—
-Other current liabilities	7			3
Net cash provided from operating activities	137			309
Investing Activities:
Property additions	(403		)	(428		)
Construction payables	(11		)	(15		)
Capital grant proceeds	137			—
Other investing activities	(19		)	(17		)
Net cash used for investing activities	(296		)	(460		)
Financing Activities:
Increase in notes payable, net	—			475
Proceeds —
Capital contributions from parent company	226			77
Long-term debt issuance to parent company	200			—
Other long-term debt issuances	900			—
Short-term borrowings	—			30
Redemptions —
Short-term borrowings	(475		)	—
Long-term debt to parent company	(225		)	—
Other long-term debt	(425		)	(350		)
Other financing activities	(3		)	(2		)
Net cash provided from financing activities	198			230
Net Change in Cash and Cash Equivalents	39			79
Cash and Cash Equivalents at Beginning of Period	98			133
Cash and Cash Equivalents at End of Period	$	137		$	212
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $49 and $39, net of $23 and $37 capitalized for 2016 and 2015, respectively)	$	26		$	2
Income taxes, net	(122		)	(181		)
Noncash transactions —
Accrued property additions at end of period	94			99
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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MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2016		At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	137	$	98
Receivables —
Customer accounts receivable	35		26
Unbilled revenues	46		36
Income taxes receivable, current	—		20
Other accounts and notes receivable	5		10
Affiliated companies	12		20
Fossil fuel stock, at average cost	99		104
Materials and supplies, at average cost	77		75
Other regulatory assets, current	97		95
Prepaid income taxes	5		39
Other current assets	7		8
Total current assets	520		531
Property, Plant, and Equipment:
In service	4,809		4,886
Less accumulated provision for depreciation	1,248		1,262
Plant in service, net of depreciation	3,561		3,624
Construction work in progress	2,429		2,254
Total property, plant, and equipment	5,990		5,878
Other Property and Investments	11		11
Deferred Charges and Other Assets:
Deferred charges related to income taxes	317		290
Other regulatory assets, deferred	520		525
Income taxes receivable, non-current	544		544
Other deferred charges and assets	85		61
Total deferred charges and other assets	1,466		1,420
Total Assets	$	7,987	$	7,840

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

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MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	343		$	728
Notes payable	25			500
Accounts payable —
Affiliated	87			85
Other	120			135
Customer deposits	16			16
Accrued taxes —
Accrued income taxes	57			—
Other accrued taxes	48			85
Accrued interest	19			18
Accrued compensation	14			26
Asset retirement obligations, current	21			22
Over recovered regulatory clause liabilities	100			96
Customer liability associated with Kemper refunds	5			73
Other current liabilities	41			52
Total current liabilities	896			1,836
Long-term Debt:
Long-term debt, affiliated	551			576
Long-term debt, non-affiliated	2,164			1,310
Total Long-term Debt	2,715			1,886
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	773			762
Deferred credits related to income taxes	8			8
Accumulated deferred investment tax credits	5			5
Employee benefit obligations	148			153
Asset retirement obligations, deferred	157			154
Unrecognized tax benefits	368			368
Other cost of removal obligations	169			165
Other regulatory liabilities, deferred	74			71
Other deferred credits and liabilities	40			40
Total deferred credits and other liabilities	1,742			1,726
Total Liabilities	5,353			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	3,122			2,893
Accumulated deficit	(553		)	(566		)
Accumulated other comprehensive loss	(6		)	(6		)
Total common stockholder's equity	2,601			2,359
Total Liabilities and Stockholder's Equity	$	7,987		$	7,840

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2016 vs. SECOND 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 October 31, 2016, which reflects a one-month extension. The initial production of syngas began on July 14, 2016 and testing has continued on gasifier 'B' and the related lignite feed and ash systems. The schedule extension provides for time to complete mechanical equipment modifications to the gasifiers' supporting systems to increase capacity to the levels necessary to complete the remaining start-up activities and achieve sustained operations on both gasifiers. The remaining schedule also reflects the time expected to complete the initial operation and testing of the facility's syngas clean-up systems, as well as 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 $6.68 billion, which includes approximately $5.43 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 $81 million ($50 million after tax) in the second quarter 2016 and a total of $134 million ($83 million after tax) for the six months ended June 30,2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.55 billion ($1.57 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through June 30, 2016. The current cost estimate includes costs through October 31, 2016.

In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation (the 2015 Stipulation) between Mississippi Power and the Mississippi Public Utilities Staff (MPUS), authorizing rates

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. Further proceedings related to cost recovery for the Kemper IGCC are expected after the remainder of the Kemper IGCC is placed in service, which is currently expected to occur by October 31, 2016. The ultimate outcome of these matters cannot be determined at this time.

Southern Company and Mississippi Power are defendants in lawsuits that allege improper disclosure of important facts about the Kemper IGCC. One lawsuit was filed in Harrison County Circuit Court by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean and seeks unspecified actual damages, punitive damages, and attorney's fees, costs, and interest. Another lawsuit was filed by Treetop Midstream Services, LLC (Treetop) and other related parties and seeks $100 million in compensatory damages, as well as punitive damages, costs, and interest. 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.

On March 8, 2016, Mississippi Power borrowed $900 million under a new term loan agreement with a syndicate of financial institutions and used the proceeds to repay $900 million in maturing bank loans. Mississippi Power has the right to borrow the $300 million remaining under the agreement on or before October 15, 2016 and expects to use those funds to repay senior notes maturing in October 2016. On June 27, 2016, Mississippi Power received a $225 million capital contribution from Southern Company which was used to repay to Southern Company a portion of an existing promissory note.

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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(47)	(95.9)	$(71)	(84.5)

Mississippi Power's net income after dividends on preferred stock for the second quarter 2016 was $2 million compared to $49 million for the corresponding period in 2015. The decrease was primarily related to higher pre-tax charges of $81 million ($50 million after tax) in the second quarter 2016 compared to pre-tax charges of $23 million ($14 million after tax) in the second quarter 2015 for revisions of the estimated costs expected to be incurred on

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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 also due to a decrease in interest on deposits resulting from the termination of an asset purchase agreement between Mississippi Power and SMEPA in May 2015. Also contributing to the decrease was higher depreciation and amortization and a decrease in wholesale revenues, partially offset by an increase in retail revenues.

For year-to-date 2016, net income after dividends on preferred stock was $13 million compared to $84 million for the corresponding period in 2015. The decrease was primarily related to higher pre-tax charges of $134 million ($83 million after tax) in 2016 compared to pre-tax charges of $32 million ($20 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 also due to a decrease in interest on deposits resulting from the termination of an asset purchase agreement between Mississippi Power and SMEPA in May 2015. Also contributing to the decrease was higher depreciation and amortization and a decrease in wholesale revenues, 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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$17	9.0	$32	9.0

In the second quarter 2016, retail revenues were $206 million compared to $189 million for the corresponding period in 2015. For year-to-date 2016, retail revenues were $389 million compared to $357 million for the corresponding period in 2015.

Details of the changes in retail revenues were as follows:

	Second Quarter 2016					Year-to-Date 2016
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	189				$	357
Estimated change resulting from –
Rates and pricing	32			16.9		57			16.0
Sales growth (decline)	(1		)	(0.5	)	3			0.8
Weather	1			0.5		(2		)	(0.6	)
Fuel and other cost recovery	(15		)	(7.9	)	(26		)	(7.2	)
Retail – current year	$	206		9.0	%	$	389		9.0	%

Revenues associated with changes in rates and pricing increased in the second 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 second quarter 2016 when compared to the corresponding period in 2015. Weather-adjusted KWH sales to residential and commercial customers decreased 2.2% and 4.0%, respectively, in the second quarter 2016 due to decreased customer usage, partially offset by customer growth.

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

KWH sales to industrial customers increased 2.9% in the second quarter 2016 due to increased usage by larger customers.

Revenues attributable to changes in sales were relatively flat for year-to-date 2016 when compared to the corresponding period in 2015. Weather-adjusted KWH sales to commercial customers decreased 1.9% due to decreased customer usage, partially offset by customer growth. KWH sales to industrial customers and weather-adjusted KWH sales to residential customers were relatively flat.

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 increased 3.0%, weather-adjusted KWH sales to commercial customers increased 1.6%, and KWH sales to industrial customers increased 1.0% as compared to the corresponding period in 2015.

Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2016 when compared to the corresponding periods in 2015, primarily as a result of lower recoverable fuel costs. See "Fuel and Purchased Power Expenses" herein for additional information. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.

Wholesale Revenues – Non-Affiliates

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(3)	(4.8)	$(21)	(14.9)

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

In the second quarter 2016, wholesale revenues from sales to non-affiliates were $60 million compared to $63 million for the corresponding period in 2015. The decrease was primarily due to a $6 million decrease in energy revenues primarily resulting from lower fuel prices, partially offset by a $3 million increase in base and capacity revenues primarily resulting from a wholesale rate increase. For year-to-date 2016, wholesale revenues from sales to non-affiliates were $120 million compared to $141 million for the corresponding period in 2015. The decrease was primarily due to a $14 million decrease in energy revenues primarily resulting from lower fuel prices and decreased usage and a $7 million decrease in base and capacity revenues primarily resulting from milder weather.

102

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Affiliates

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(11)	(61.1)	$(29)	(64.4)

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

In the second 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 $9 million decrease in KWH sales resulting from a decrease in sales from coal generation and a $2 million decrease associated with lower natural gas prices.

For year-to-date 2016, wholesale revenues from sales to affiliates were $16 million compared to $45 million for the corresponding period in 2015. The decrease was due to a $23 million decrease in KWH sales resulting from a decrease in sales from coal generation and a $6 million decrease associated with lower natural gas prices.

Fuel and Purchased Power Expenses

	Second Quarter 2016 vs. Second Quarter 2015				Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(34	)	(29.6)	$	(72	)	(31.4	)
Purchased power – non-affiliates	(1		)	(50.0)	(2		)	(66.7	)
Purchased power – affiliates	2			100.0	5			125.0
Total fuel and purchased power expenses	$	(33	)		$	(69	)

In the second quarter 2016, total fuel and purchased power expenses were $86 million compared to $119 million for the corresponding period in 2015. The decrease was due to a $16 million decrease in the volume of KWHs generated and purchased and a $17 million decrease in the average cost of fuel.

For year-to-date 2016, total fuel and purchased power expenses were $167 million compared to $236 million for the corresponding period in 2015. The decrease was due to a $34 million decrease in the volume of KWHs generated and purchased and a $35 million decrease in the average cost of fuel.

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.

103

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	Second Quarter 2016	Second Quarter 2015	Year-to-Date 2016	Year-to-Date 2015
Total generation (millions of KWHs)	3,728	4,109	7,315	8,455
Total purchased power (millions of KWHs)	188	114	449	227
Sources of generation (percent) –
Coal	5	18	8	20
Gas	95	82	92	80
Cost of fuel, generated (cents per net KWH) –
Coal	5.49	4.14	4.16	3.64
Gas	2.17	2.71	2.16	2.69
Average cost of fuel, generated (cents per net KWH)	2.33	2.98	2.32	2.90
Average cost of purchased power (cents per net KWH)	2.55	3.19	2.33	3.37

Fuel

In the second quarter 2016, fuel expense was $81 million compared to $115 million for the corresponding period in 2015. The decrease was due to a 10% decrease in the volume of KWHs generated, primarily as a result of milder weather, and a 22% decrease in the average cost of fuel per KWH generated primarily due to higher gas-fired generation, including the Kemper IGCC combined cycle that was placed in service in 2014. The decrease in volume included a decrease in coal-fired generation of 76% and an increase in gas-fired generation of 5%.

For year-to-date 2016, total fuel expense was $157 million compared to $229 million for the corresponding period in 2015. The decrease was due to a 15% decrease in the volume of KWHs generated, primarily as a result of milder weather, and a 20% decrease in the average cost of fuel per KWH generated primarily due to higher gas-fired generation, including the Kemper IGCC combined cycle that was placed in service in 2014. The decrease in volume also included a 68% decrease in coal-fired generation.

Purchased Power

Energy purchases will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Energy purchases from affiliates are made in accordance with the IIC, as approved by the FERC.

Other Operations and Maintenance Expenses

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$(8)	(5.6)

For year-to-date 2016, other operations and maintenance expenses were $136 million compared to $144 million for the corresponding period in 2015. The decrease was primarily due to a $16 million decrease in generation outage costs, a $4 million decrease primarily related to pension costs, a $2 million decrease in transmission and distribution overhead line maintenance and vegetation management, and a $2 million decrease in uncollectibles expense and customer incentives. The decreases were partially offset by a $16 million increase in maintenance expenses related to the combined cycle and the associated common facilities portion of the Kemper IGCC that Mississippi Power began expensing in the third quarter 2015 in connection with the implementation of interim rates associated with the Kemper IGCC in-service assets. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

Depreciation and Amortization

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$15	50.0	$27	47.4

In the second quarter 2016, depreciation and amortization was $45 million compared to $30 million for the corresponding period in 2015. For year-to-date 2016, depreciation and amortization was $84 million compared to $57 million for the corresponding period in 2015. These increases were primarily due to additional amortization expenses and lower deferrals associated with the Kemper IGCC combined cycle assets of $13 million and $22 million in the second quarter and year-to-date 2016, respectively, in accordance with the In-Service Asset Rate Order. Additionally, increases of $2 million and $5 million in the second quarter and year-to-date 2016, respectively, are related to additional plant in service.

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

Estimated Loss on Kemper IGCC

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$58	N/M	$102	N/M

N/M - Not meaningful

In the second quarters of 2016 and 2015, estimated probable losses on the Kemper IGCC of $81 million and $23 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 $134 million and $32 million, respectively, were recorded at Mississippi Power. These losses reflect revisions of estimated costs expected to be incurred on the construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions.

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

Allowance for Equity Funds Used During Construction

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$5	20.0	$6	11.3

In the second quarter of 2016, AFUDC equity was $30 million compared to $25 million for the corresponding period in 2015. For year-to-date 2016, AFUDC equity was $59 million compared to $53 million for the corresponding period in 2015. The increase was driven by a higher AFUDC equity rate and an increase in Kemper IGCC AFUDC, primarily associated with the wholesale settlement agreement removing all Kemper IGCC CWIP from rate base, partially offset by placing the Plant Daniel scrubbers in service in November 2015. See Note 3 to the

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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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$45	N/M	$50	N/M

N/M - Not meaningful

In the second quarter 2016, interest expense, net of amounts capitalized was $15 million compared to $(30) million for the corresponding period in 2015. For year-to-date 2016, interest expense, net of amounts capitalized was $31 million compared to $(19) million for the corresponding period in 2015. The increases were primarily due to a $38 million and a $31 million decrease for the second quarter and year-to-date 2016, respectively, in interest on deposits resulting from the termination of an asset purchase agreement between Mississippi Power and SMEPA in May 2015. In addition, these increases were related to additional long-term debt and decreases in amounts capitalized, partially offset by a decrease in interest on Mirror CWIP.

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

Income Taxes (Benefit)

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(33)	N/M	$(47)	N/M

N/M - Not meaningful

In the second quarter 2016, income tax benefit was $(17) million compared to an expense of $16 million for the corresponding period in 2015. For year-to-date 2016, income tax benefit was $(27) million compared to an expense of $20 million for the corresponding period in 2015. The changes were primarily due to the reduction in pre-tax earnings related to 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

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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 and regional haze regulations.

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 have 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.

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. 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. The increase is primarily due to the Plant Daniel Units 1 and 2 scrubbers, which were placed in service in November 2015. 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

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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 $8 million through the Kemper IGCC's projected in-service date of October 31, 2016.

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.

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

Fuel Cost Recovery

At June 30, 2016, the amount of over-recovered retail fuel costs included on the balance sheet was $76 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 of February. As required by the order, on February 1, 2016, Mississippi Power submitted updated natural gas price forecasts and resulting fuel factors to the Mississippi PSC. If approved by the Mississippi PSC, the updated forecast would decrease fuel cost recovery rates by an additional $36 million annually. The ultimate outcome of this matter cannot be determined at this time.

Integrated Coal Gasification Combined Cycle

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

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Kemper IGCC Overview

Construction of Mississippi Power's Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. 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 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 in-service date for the remainder of the Kemper IGCC is currently expected to occur by October 31, 2016, which reflects a one-month extension. The initial production of syngas began on July 14, 2016 and testing has continued on gasifier 'B' and the related lignite feed and ash systems. The schedule extension provides for time to complete mechanical equipment modifications to the gasifiers' supporting systems to increase capacity to the levels necessary to complete the remaining start-up activities and achieve sustained operations on both gasifiers. The remaining schedule also reflects the time expected to complete the initial operation and testing of the facility's syngas clean-up systems, as well as the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.

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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 June 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	$	5.43		$	5.15
Lignite Mine and Equipment	0.21		0.23			0.23
CO2 Pipeline Facilities	0.14		0.11			0.12
AFUDC(d)	0.17		0.72			0.66
Combined Cycle and Related Assets Placed in Service – Incremental(e)	—		0.03			0.02
General Exceptions	0.05		0.10			0.09
Deferred Costs(e)	—		0.20			0.19
Additional DOE Grants	—		(0.14		)	(0.14		)
Total Kemper IGCC	$	2.97	$	6.68		$	6.32

(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 reflect estimated costs through October 31, 2016.

(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 June 30, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, are not included in the Current Cost Estimate and the Actual Costs at June 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 June 30, 2016, $3.59 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 $2.55 billion), $6 million in other property and investments, $81 million in fossil fuel stock, $46 million in materials and supplies, $35 million in other regulatory assets, current, $180 million in other regulatory assets, deferred, $1 million in other current assets, and $11 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 $81 million($50 million after tax) in the second quarter 2016 and a total of $134 million ($83 million after tax) for the six months ended June 30, 2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.55 billion ($1.57 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through June 30, 2016. The increase to the cost estimate in 2016 primarily reflects costs for the extension of the Kemper IGCC's projected in-service date through October 31, 2016 and increased efforts related to operational readiness and challenges in

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start-up and commissioning activities, which includes the cost of repairs and modifications associated with the lignite feed process and the refractory lining for the gasifiers. Any extension of the in-service date beyond October 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 October 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 $14 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. Significant testing activities, including those for coal feed and gasification systems, as well as the initial operation and testing of the facility's gas clean-up systems and production of clean syngas, and, ultimately the generation of electricity, remain in process. 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, 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 to complete construction and start-up 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 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.

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-

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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. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed 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 in September 2015, subject to refund and certain other conditions.

On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full the 2015 Stipulation entered into between Mississippi Power and the MPUS regarding the In-Service Asset Proposal. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. 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's motion for reconsideration of its previous decision to dismiss Greenleaf's appeal of the In-Service Asset Rate Order.

Pursuant to the In-Service Asset Rate Order, Mississippi Power is required to file a subsequent rate request within 18 months. As part of the filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation.

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

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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.

Mississippi Power expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at June 30, 2016 of $6.68 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, and additional carrying costs. Mississippi Power will seek approval from the Mississippi PSC to defer these costs for future rate recovery to be determined in connection with the final Kemper IGCC cost recovery approach ultimately approved. See "Regulatory Assets and Liabilities" below for additional information.

Regulatory Assets and Liabilities

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

In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015 and 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 June 30, 2016, the balance associated with these regulatory assets was $114 million, of which $35 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $101 million as of June 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 "2013 MPSC Rate Order" herein for information related to the July 7, 2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP. Also see "FERC Matters" herein for information related to the 2016 settlement agreement with wholesale customers.

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.

The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. At June 30, 2016, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $5 million. See "2015 Rate Case" herein 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.

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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, 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. 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.

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.

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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.

Other Matters

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

TheultimateoutcomeofsuchpendingorpotentiallitigationagainstMississippi Powercannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementshereinorinNote3tothefinancialstatementsofMississippi 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 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

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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 $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 incurred charges of $2.55 billion ($1.57 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through June 30, 2016.

Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up 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. 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, 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).

Mississippi Power's revised cost estimate includes costs through October 31, 2016. Any extension of the in-service date beyond October 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 October 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 $14 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.

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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 in additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 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 six months ended June 30, 2016 were negatively affected by revisions to the cost estimate for the Kemper IGCC.

Through June 30, 2016, Mississippi Power has incurred non-recoverable cash expenditures of $2.28 billion and is expected to incur approximately $0.27 billion in additional non-recoverable cash expenditures through completion of the construction and start-up of the Kemper IGCC.

For the three-year period from 2016 through 2018, Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows. 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 six months of 2016, Mississippi Power borrowed from Southern Company $100 million under this promissory note and an additional $100 million under a separate promissory note issued 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 under the term loan agreement and has the right to borrow the remaining $300 million on or before 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 June 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.

As of June 30, 2016, Mississippi Power's current liabilities exceeded current assets by approximately $376 million primarily due to $300 million in senior notes scheduled to mature on October 15, 2016, $40 million of variable rate pollution control revenue bonds backed by short-term credit facilities, and $25 million in short-term debt. Mississippi Power intends to utilize operating cash flows, the remaining $300 million under the term loan, 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 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 $137 million for the first six months of 2016, a decrease of $172 million as compared to the corresponding period in 2015. The decrease in cash provided from operating activities is primarily due to lower research and experimental (R&E) tax deductions and the cessation of Mirror CWIP collections and subsequent refund payments, partially offset by income taxes receivable associated with R&E deductions and accrued taxes. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal

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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 $296 million for the first six months of 2016 primarily due to receipt of $137 million in Additional DOE Grants for the Kemper IGCC and gross property additions related to the Kemper IGCC. Net cash provided from financing activities totaled $198 million for the first six months of 2016 primarily due to long-term debt issuances and capital contributions from Southern Company, partially offset by redemptions of long-term debt and short-term borrowings. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2016 include an increase in long-term debt of $829 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 $175 million primarily due to the Kemper IGCC and the customer liability associated with Kemper IGCC refunds decreased $68 million. Total common stockholder's equity increased $242 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 June 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.

The construction program of Mississippi Power is currently estimated to be $920 million for 2016, $218 million for 2017, and $264 million for 2018, which includes expenditures related to the construction of the Kemper IGCC of $745 million in 2016.

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.

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 seeMANAGEMENT'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.

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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 six months of 2016, Mississippi Power borrowed from Southern Company $100 million pursuant to the $275 million promissory note with a $50 million draw occurring on each of January 29, 2016 and March 14, 2016, and an additional $100 million under a separate promissory note issued 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 under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and expects the remaining $300 million to be used to repay senior notes maturing in October 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 June 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.

Mississippi Power intends to utilize operating cash flows, the remaining $300 million under the term loan, 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 June 30, 2016, Mississippi Power had approximately $137 million of cash and cash equivalents. Committed credit arrangements with banks at June 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)
$	115	$	60	$	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 (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.

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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 June 30, 2016 was approximately $40 million.

Details of short-term borrowings were as follows:

	Short-term Debt at June 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 June 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 June 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 $251 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

In January 2016, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $275 million, which matures on December 1, 2017, bearing interest based on one-month LIBOR. As of June 30, 2016, Mississippi Power had borrowed $100 million under this promissory note with a $50 million draw occurring on each of January 29, 2016 and March 14, 2016. In addition, on January 19, 2016, Mississippi Power borrowed $100 million from Southern Company pursuant to a promissory note issued in November 2015. 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 existing promissory note issued in November 2015. As of June 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.

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 to repay existing indebtedness and for other general corporate purposes. Mississippi Power borrowed $900 million under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016, upon satisfaction of certain customary conditions. Mississippi Power used the initial proceeds to repay $900 million in maturing bank notes on March 8, 2016 and

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expects the remaining $300 million to be used to repay senior notes maturing in October 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR.

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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SOUTHERN POWER COMPANY

AND SUBSIDIARY COMPANIES

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	264		$	250		$	480		$	481
Wholesale revenues, affiliates	107			85			204			199
Other revenues	2			2			4			4
Total operating revenues	373			337			688			684
Operating Expenses:
Fuel	96			105			187			243
Purchased power, non-affiliates	21			18			35			34
Purchased power, affiliates	2			4			8			14
Other operations and maintenance	86			69			162			121
Depreciation and amortization	81			60			154			118
Taxes other than income taxes	6			6			13			12
Total operating expenses	292			262			559			542
Operating Income	81			75			129			142
Other Income and (Expense):
Interest expense, net of amounts capitalized	(22		)	(23		)	(43		)	(45		)
Other income (expense), net	1			1			1			1
Total other income and (expense)	(21		)	(22		)	(42		)	(44		)
Earnings Before Income Taxes	60			53			87			98
Income taxes (benefit)	(41		)	1			(65		)	13
Net Income	101			52			152			85
Less: Net income attributable to noncontrolling interests	12			6			13			6
Net Income Attributable to Southern Power	$	89		$	46		$	139		$	79

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2016			2015		2016			2015
	(in millions)					(in millions)
Net Income	$	101		$	52	$	152		$	85
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(15), $-, $(15) and $-, respectively	(24		)	—		(24		)	—
Reclassification adjustment for amounts included in net income, net of tax of $8, $-, $8, and $-, respectively	13			—		14			—
Total other comprehensive income (loss)	(11		)	—		(10		)	—
Less: Comprehensive income attributable to noncontrolling interests	12			6		13			6
Comprehensive Income Attributable to Southern Power	$	78		$	46	$	129		$	79

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	152		$	85
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	159			121
Deferred income taxes	(71		)	59
Investment tax credits	—			153
Amortization of investment tax credits	(15		)	(10		)
Deferred revenues	(31		)	(21		)
Accrued income taxes, non-current	—			100
Other, net	9			10
Changes in certain current assets and liabilities —
-Receivables	(76		)	(26		)
-Prepaid income taxes	(147		)	(102		)
-Other current assets	5			5
-Accounts payable	4			(31		)
-Accrued taxes	62			(110		)
-Other current liabilities	—			18
Net cash provided from operating activities	51			251
Investing Activities:
Business acquisitions	(502		)	(408		)
Property additions	(1,281		)	(154		)
Change in construction payables	(137		)	38
Payments pursuant to long-term service agreements	(43		)	(45		)
Investment in restricted cash	(646		)	—
Distribution of restricted cash	649			—
Other investing activities	(25		)	(1		)
Net cash used for investing activities	(1,985		)	(570		)
Financing Activities:
Increase (decrease) in notes payable, net	695			(195		)
Proceeds —
Senior notes	1,241			650
Capital contributions	300			—
Distributions to noncontrolling interests	(11		)	(1		)
Capital contributions from noncontrolling interests	179			78
Purchase of membership interests from noncontrolling interests	(129		)	—
Payment of common stock dividends	(136		)	(65		)
Other financing activities	(13		)	(3		)
Net cash provided from financing activities	2,126			464
Net Change in Cash and Cash Equivalents	192			145
Cash and Cash Equivalents at Beginning of Period	830			75
Cash and Cash Equivalents at End of Period	$	1,022		$	220
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $21 and $1 capitalized for 2016 and 2015, respectively)	$	42		$	35
Income taxes, net	115			(72		)
Noncash transactions — Accrued property additions at end of period	108			38

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2016		At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,022	$	830
Receivables —
Customer accounts receivable	115		75
Other accounts receivable	23		19
Affiliated companies	60		30
Fossil fuel stock, at average cost	14		16
Materials and supplies, at average cost	120		63
Prepaid income taxes	192		45
Other current assets	31		30
Total current assets	1,577		1,108
Property, Plant, and Equipment:
In service	8,348		7,275
Less accumulated provision for depreciation	1,374		1,248
Plant in service, net of depreciation	6,974		6,027
Construction work in progress	1,852		1,137
Total property, plant, and equipment	8,826		7,164
Other Property and Investments:
Goodwill	2		2
Other intangible assets, net of amortization of $14 and $12 at June 30, 2016 and December 31, 2015, respectively	316		317
Total other property and investments	318		319
Deferred Charges and Other Assets:
Prepaid long-term service agreements	165		166
Other deferred charges and assets — affiliated	23		9
Other deferred charges and assets — non-affiliated	173		139
Total deferred charges and other assets	361		314
Total Assets	$	11,082	$	8,905

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At June 30, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	403		$	403
Notes payable	831			137
Accounts payable —
Affiliated	80			66
Other	175			327
Accrued taxes —
Accrued income taxes	9			198
Other accrued taxes	16			5
Accrued interest	22			23
Contingent consideration	23			36
Other current liabilities	69			44
Total current liabilities	1,628			1,239
Long-term Debt	3,929			2,719
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	524			601
Accumulated deferred investment tax credits	1,107			889
Accrued income taxes, non-current	109			109
Asset retirement obligations	28			21
Deferred capacity revenues — affiliated	7			17
Other deferred credits and liabilities	105			3
Total deferred credits and other liabilities	1,880			1,640
Total Liabilities	7,437			5,598
Redeemable Noncontrolling Interests	47			43
Common Stockholder's Equity:
Common stock, par value $.01 per share —
Authorized — 1,000,000 shares
Outstanding — 1,000 shares	—			—
Paid-in capital	2,121			1,822
Retained earnings	661			657
Accumulated other comprehensive income (loss)	(6		)	4
Total common stockholder's equity	2,776			2,483
Noncontrolling interests	822			781
Total stockholders' equity	3,598			3,264
Total Liabilities and Stockholders' Equity	$	11,082		$	8,905

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

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SECOND QUARTER 2016 vs. SECOND QUARTER 2015

AND

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

OVERVIEW

Southern Power constructs, acquires, owns, and manages 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 power plants, and entry into PPAs 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 six months ended June 30, 2016, Southern Power acquired or commenced construction of approximately 333 MWs of additional solar and wind facilities and committed to acquire approximately 656 MWs of solar and wind facilities. Subsequent to June 30, 2016, Southern Power acquired or commenced construction of approximately 278 MWs of solar facilities. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.

At June 30, 2016, Southern Power had an average investment coverage ratio of 91% for the next five years (through 2020) and 90% for the next 10 years (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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$43	93.5	$60	75.9

Net income attributable to Southern Power for the second quarter 2016 was $89 million compared to $46 million for the corresponding period in 2015. Net income attributable to Southern Power for year-to-date 2016 was $139 million compared to $79 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 and operations and maintenance expenses all related to new solar and wind facilities placed in service.

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Operating Revenues

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$36	10.7	$4	0.6

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.

	Second Quarter 2016 vs. Second Quarter 2015				Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)	(change in millions)			(% change)
PPA capacity revenues	$	(2	)	(1.8)	$	(5	)	(1.9)
PPA energy revenues	17			11.6	18			6.7
Total PPA revenues	15			5.2	13			2.5
Revenues not covered by PPA	21			43.7	(9		)	(6.2)
Total operating revenues	$	36		10.7%	$	4		0.6%

In the second quarter 2016, operating revenues were $373 million compared to $337 million for the corresponding period in 2015. The $36 million increase in operating revenues was primarily due to the following:

• PPA capacity revenues decreased $2 million as a result of a $10 million decrease in non-affiliate capacity revenues, partially offset by an $8 million increase in affiliate capacity revenues primarily due to the remarketing of generation capacity.

• PPA energy revenuesincreased $17 million primarily due to a $37 million increase in renewable energy sales, arising from new solar and wind facilities, partially offset by a decrease of $20 million in fuel revenues related to natural gas facility PPAs.

• Revenues not covered by PPA increased $21 million due to a $15 million increase related to short-term sales to non-affiliates and a $6 million increase primarily due to a 30% increase in KWH sales to the power pool driven by lower natural gas prices.

For year-to-date 2016, operating revenues were $688 million compared to $684 million for the corresponding period in 2015. The $4 million increase in operating revenues was primarily due to the following:

• PPA capacity revenues decreased $5 million as a result of a $26 million decrease in non-affiliate capacity revenues, partially offset by a $21 million increase in affiliate capacity revenues primarily due to the remarketing of generation capacity.

• PPA energy revenuesincreased $18 million primarily due to a $58 million increase in renewable energy sales arising from new solar and wind facilities, partially offset by a decrease of $40 million in fuel revenues related to natural gas facility PPAs.

• Revenues not covered by PPA decreased $9 million due to a $25 million decrease primarily related to a 21% decrease in volume of sales into the power pool associated with increased scheduled outages and a reduction in demand driven by milder weather, partially offset by lower natural gas prices. The decrease was partially offset by a $16 million increase related to short-term sales to non-affiliates.

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.

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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.

Capacity revenues are an integral component of Southern Power's natural gas and biomass PPAs. Energy under the 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, but do not have a capacity charge. Instead, the 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.

Fuel and Purchased Power Expenses

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

	Second Quarter 2016	Second Quarter 2015	Year-to-Date 2016	Year-to-Date 2015
Generation (in billions of KWHs)	9.1	7.5	16.7	15.4
Purchased power (in billions of KWHs)	0.9	0.5	1.5	0.9
Total generation and purchased power	10.0	8.0	18.2	16.3
Total generation and purchased power excluding solar, wind, and tolling agreements	5.7	4.8	11.0	10.7

Southern Power's PPAs for natural gas and biomass generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, any increase or decrease in such fuel costs is generally accompanied by an increase or decrease in related fuel revenues under the PPAs and does 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 and the availability and 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, affiliate companies, or external parties.

	Second Quarter 2016 vs. Second Quarter 2015				Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(9	)	(8.6)	$	(56	)	(23.0)
Purchased power	1			4.5	(5		)	(10.4)
Total fuel and purchased power expenses	$	(8	)		$	(61	)

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In the second quarter 2016, total fuel and purchased power expenses were $119 million compared to $127 million for the corresponding period in 2015. The decrease was primarily due to the following:

• Fuel expense decreased $9 million primarily due to a $22 million decrease associated with the average cost of natural gas per KWH generated, partially offset by a $13 million increase associated with the volume of KWHs generated.

• Purchased power expense increased $1 million due to a $13 million increase associated with the volume of KWHs purchased, largely offset by an $8 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 $230 million compared to $291 million for the corresponding period in 2015. The decrease was primarily due to the following:

• Fuel expense decreased $56 million primarily due to a $51 million decrease associated with the average cost of natural gas per KWH generated and a $5 million decrease associated with the volume of KWHs generated.

• Purchased power expense decreased $5 million due to a $21 million decrease in the average cost of purchased power and an $8 million decrease associated with a PPA expiration, largely offset by a $24 million increase associated with the volume of KWHs purchased.

Other Operations and Maintenance Expenses

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$17	24.6	$41	33.9

In the second quarter 2016, other operations and maintenance expenses were $86 million compared to $69 million for the corresponding period in 2015. The increase was primarily due to an $8 million increase in expenses associated with new solar and wind facilities placed in service in 2015 and 2016, a $5 million increase in general business expenses associated with Southern Power's overall growth strategy, and a $4 million increase associated with scheduled outage and maintenance expenses.

For year-to-date 2016, other operations and maintenance expenses were $162 million compared to $121 million for the corresponding period in 2015. The increase was primarily due to an $18 million increase associated with scheduled outage and maintenance expenses, a $13 million increase in expenses associated with new solar and wind facilities placed in service in 2015 and 2016, and a $10 million increase in general business expenses associated with Southern Power's overall growth strategy.

Depreciation and Amortization

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$21	35.0	$36	30.5

In the second quarter 2016, depreciation and amortization was $81 million compared to $60 million for the corresponding period in 2015. For year-to-date 2016, depreciation and amortization was $154 million compared to $118 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.

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Interest Expense, net of Amounts Capitalized

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(4.3)	$(2)	(4.4)

In the second quarter 2016, interest expense, net of amounts capitalized was $22 million compared to $23 million for the corresponding period in 2015. The decrease was primarily due to an $11 million increase in capitalized interest associated with the construction of solar facilities, largely offset by an increase of $10 million in interest expense related to additional debt issued in November 2015 and June 2016 primarily to fund Southern Power's growth strategy and continuous construction program.

For year-to-date 2016, interest expense, net of amounts capitalized was $43 million compared to $45 million for the corresponding period in 2015. The decrease was primarily due to a $20 million increase in capitalized interest associated with the construction of solar facilities, largely offset by an increase of $18 million in interest expense related to additional debt issued in November 2015 and June 2016 primarily to fund Southern Power's growth strategy and continuous construction program.

Income Taxes (Benefit)

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(42)	N/M	$(78)	N/M

N/M - Not meaningful

In the second quarter 2016, income tax benefit was $(41) million compared to an expense of $1 million for the corresponding period in 2015. The change was primarily due to a $46 million increase in federal income tax benefits from solar ITCs and wind PTCs in 2016, partially offset by a $4 million increase in tax expense related to beneficial state apportionment rate changes in 2015.

For year-to-date 2016, income tax benefit was $(65) million compared to an expense of $13 million for the corresponding period in 2015. The change was primarily due to a $75 million increase in federal income tax benefits from solar ITCs and wind PTCs in 2016 and a $7 million decrease in tax expense related to lower pre-tax earnings in 2016, partially offset by a $4 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; and Southern Power's ability to execute its growth strategy, including successful additional investments in renewable and other energy projects, and to construct generating facilities, including 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 issues, see RISK FACTORS in

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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% for the next five years (through 2020) and 70% for the next 10 years (through 2025), with an average remaining contract duration of approximately 10 years.

Southern Power believes an investment coverage ratio better 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 June 30, 2016, the investment coverage ratio was 91% for the next five years (through 2020) and 90% for the next 10 years (through 2025), with an average remaining contract duration of approximately 17 years. At December 31, 2015, the investment coverage ratio would have been 91% for the next five years (through 2020) and 90% for the next 10 years (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 regulatory or legislative changes cannot be determined at this time.

Acquisitions

During 2016, in accordance with its overall growth strategy, Southern Power acquired or contracted to acquire through its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC or Southern Renewable Energy, Inc., 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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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Project Facility	Resource	Approx. Nameplate Capacity	Location	Percentage Ownership	Expected/Actual COD	PPA Contract Period
		(MW)
Acquisitions During the Six Months Ended June 30, 2016
Calipatria	Solar	20	Imperial County, CA	90%	February 2016	20 years
East Pecos	Solar	120	Pecos County, TX	100%	Fourth quarter 2016	15 years
Grant Wind	Wind	151	Grant County, OK	100%	April 2016	20 years
Passadumkeag	Wind	42	Penobscot County, ME	100%	July 2016	15 years
Acquisitions Subsequent to June 30, 2016
Henrietta	Solar	102	Kings County, CA	51%(*)	July 2016	20 years
Lamesa	Solar	102	Dawson County, TX	100%	Second quarter 2017	15 years
Rutherford	Solar	74	Rutherford County, NC	90%	Fourth quarter 2016	15 years

(*) 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.

Acquisitions During the Six Months Ended June 30, 2016

Total construction costs, excluding the acquisition costs, are expected to be approximately $160 million to $180 million for East Pecos, which is currently under construction. The ultimate outcome of this matter cannot be determined at this time.

Acquisitions Subsequent to June 30, 2016

Total aggregate construction costs, excluding the acquisition costs, are expected to be approximately $260 million to $300 million for Lamesa and Rutherford, which are currently under construction. The ultimate outcome of these matters cannot be determined at this time.

Acquisition Agreements Executed but Not Yet Closed

During the six months ended June 30, 2016 and subsequent to that date, Southern Power entered into agreements to acquire the following projects for an aggregate purchase price of $1.1 billion: 100% ownership interests in two wind facilities totaling 299 MWs in Texas, significantly covered with PPAs for the first 12 to 14 years of operation; a 51% ownership interest (through 100% ownership of the Class A membership interests entitling Southern Power to 51% of all cash distributions and significantly all of the federal tax benefits) in a 100-MW solar facility in Nevada with a 20-year PPA; and a 90.1% ownership interest in a 257-MW wind facility in Texas significantly covered with a 12-year PPA. These acquisitions are expected to close in the third and fourth quarters of 2016. 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 six months ended June 30, 2016 included in the consolidated statement of income for year-to-date 2016 is $4 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 six months ended June 30, 2016 included in the consolidated statement 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.

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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 for additional information.

During the six months ended June 30, 2016, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service the Butler Solar Farm and Pawpaw solar facilities. In addition, Southern Power continued construction of the projects set forth in the table below. Through June 30, 2016, total costs of construction incurred for the projects below were $2.7 billion, of which $1.7 billion remains in CWIP. Including the total construction costs incurred to date and the acquisition prices allocated to CWIP, total aggregate construction costs for the projects below are estimated to be approximately $3.0 billion to $3.2 billion. The ultimate outcome of these matters cannot be determined at this time.

Solar Facility	Approx. Nameplate Capacity	Location	Expected/Actual COD	PPA Contract Period
	(MW)
Butler	103	Taylor County, GA	Fourth quarter 2016	30 years
Desert Stateline(a)	299(b)	San Bernardino County, CA	Through third quarter 2016	20 years
Garland and Garland A	205	Kern County, CA	Fourth quarter 2016 and Third quarter 2016	15 years and 20 years
Roserock	160	Pecos County, TX	Fourth quarter 2016	20 years
Sandhills	146	Taylor County, GA	Fourth quarter 2016	25 years
Tranquillity	205	Fresno County, CA	July 2016	18 years

(a) Desert Stateline - 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. Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized.

(b) Desert Stateline - The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 152 MWs were placed in service during the six months ended June 30, 2016. Subsequent to June 30, 2016, 37 MWs were placed in service.

See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.

Other Matters

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

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.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power's financial condition remained stable at June 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 $51 million for the first six months of 2016, compared to $251 million for the first six months of 2015. The decrease in cash provided from operating activities was primarily due to an increase in income taxes paid. Net cash used for investing activities totaled $2.0 billion for the first six months of 2016 primarily due to acquisitions and the construction of renewable facilities. Net cash provided from financing activities totaled $2.1 billion for the first six months of 2016 primarily due to an increase in senior notes and 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 six months of 2016 include a $715 million increase in CWIP due to the acquisition and continued construction of new solar and wind facilities and a $947 million increase in plant in service, primarily due to solar and wind facilities being placed in service. Other significant changes include a $192 million increase in cash and cash equivalents and a $1.9 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" herein for additional information.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, unrecognized tax benefits, and other purchase commitments. Approximately $400 million will be required to repay long-term debt due September 28, 2016. There are no other scheduled maturities of long-term debt through June 30, 2017. In addition, during the six months ended

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June 30, 2016, Southern Power entered into new long-term service agreements (LTSA), which begin in 2020 and result in additional future commitments totaling approximately $784 million.

The construction program is subject to periodic review and revision. These amounts include estimates for potential plant acquisitions and new construction. In addition, the construction program includes capital improvements and work to be performed under LTSAs. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Capital expenditures of Southern Power are currently estimated to total approximately $4.5 billion for 2016, which includes approximately $4.4 billion for acquisitions and/or construction of new generating facilities. Capital expenditures of Southern Power are currently estimated to total approximately $1.0 billion and $1.5 billion for 2017 and 2018, respectively. 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.

As of June 30, 2016, Southern Power's current liabilities exceeded current assets by $51 million due to long-term debt maturing in 2016, the use of short-term debt as a funding source, and construction payables, as well as fluctuations in cash needs, due to both seasonality and the stage of acquisitions and construction projects. In 2016, 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 maturities.

As of June 30, 2016, Southern Power had cash and cash equivalents of approximately $1.0 billion.

Details of short-term borrowings were as follows:

	Short-term Debt at June 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	$	62	0.8	%	$	194	0.8	%	$	310

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

Company Facility

At June 30, 2016, Southern Power had a committed credit facility (Facility) of $600 million expiring in 2020, of which $560 million was unused. Southern Power's subsidiaries are not borrowers under the Facility.

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 Facilities

In connection with the construction of solar facilities by RE Tranquillity LLC, RE Roserock LLC, and RE Garland Holdings 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. Proceeds from the Project Credit Facilities are being used to finance project costs related to the respective solar facilities currently under construction. 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 June 30, 2016.

Project	Maturity Date	Construction Loan Facility		Bridge Loan Facility		Loan Facility Total		Total Loan Facility Undrawn		Letter of Credit Facility		Total Letter of Credit Facility Undrawn
		(in millions)
Tranquillity	Earlier of PPA COD or December 31, 2016	$	86	$	172	$	258	$	19	$	77	$	26
Roserock	Earlier of PPA COD or November 30, 2016	63		180		243		34		23		16
Garland	Earlier of PPA COD or November 30, 2016	86		308		394		73		49		23
Total		$	235	$	660	$	895	$	126	$	149	$	65

The Project Credit Facilities had total amounts outstanding as of June 30, 2016 of $769 million at a weighted average interest rate of 2.02%. For the three-month period ended June 30, 2016, these credit agreements had a maximum amount outstanding of $769 million and an average amount outstanding of $586 million at a weighted average interest rate of 2.03%.

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.

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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	29
At BBB- and/or Baa3	$	377
Below BBB- and/or Baa3	$	1,086

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, if any, resulting from a credit downgrade.

Financing Activities

During the six months ended June 30, 2016, Southern Power's subsidiaries borrowed an additional $632 million pursuant to the Project Credit Facilities at a weighted average interest rate of 2.00%. In addition, Southern Power's subsidiaries issued $16 million in letters of credit. Subsequent to June 30, 2016, Southern Power's subsidiaries borrowed $48 million pursuant to the Project Credit Facilities at a weighted average interest rate of 1.98%.

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 will be 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 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.

138

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	140
B	Contingencies and Regulatory Matters	142
C	Fair Value Measurements	158
D	Stockholders' Equity	162
E	Financing	164
F	Retirement Benefits	167
G	Income Taxes	170
H	Derivatives	172
I	Acquisitions	185
J	Segment and Related Information	191

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

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 June 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.

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 unchangedand 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. 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 Southern Company and the traditional electric operating companies' 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 in 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

140

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 $102 million made by Georgia Power to PowerSecure under the two agreements since inception in 2014 are included in CWIP at June 30, 2016. PowerSecure construction service costs of approximately $13 million are included in accounts payable, affiliated in Georgia Power's balance sheet at June 30, 2016. The facilities will be owned and operated by Georgia Power and are expected to be operational by the end of 2016. The ultimate outcome of this matter cannot be determined at this time.

See Note (I) under "Southern Company– Acquisition of PowerSecure International, Inc." for additional information regarding Southern Company's acquisition of PowerSecure.

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 the EPA's regulation of CCR.

The cost estimates below are based on information as of June 30, 2016 using 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.

As of June 30, 2016, details of the asset retirement obligations (ARO) 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	9			5			—			—			—			4
Liabilities settled	(66		)	(6		)	(52		)	(1		)	(7		)	—
Accretion	77			36			34			1			2			1
Cash flow revisions	699			19			673			3			6			2
Balance at end of period	$	4,478		$	1,502		$	2,571		$	133		$	178		$	28

The traditional electric operating companies' increases in cash flow revisions for the six months ended June 30, 2016 primarily relate to changes in ash pond closure strategy. The increase for Georgia Power was due to 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.

141

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Goodwill and Other Intangible Assets

Goodwill and other intangible assets consisted of the following:

	At June 30, 2016
	Estimated Useful Life	Gross Carrying Amount		Accumulated Amortization			Intangible Assets, Net
		(in millions)
Intangibles subject to amortization:
Southern Company
Customer relationships	14-26 years	$	47	$	—		$	47
Trade names	5-9 years	43		—			43
Patents	3-10 years	4		—			4
Backlog	5 years	5		—			5
Southern Power
PPA fair value adjustments	20 years	330		(14		)	316
Total intangibles subject to amortization		$	429	$	(14	)	$	415
Intangibles not subject to amortization:
Southern Company
Federal Communications Commission licenses		$	75	$	—		$	75
Goodwill:
Southern Company		$	262	$	—		$	262
Southern Power		2		—			2
Total goodwill and other intangible assets		$	768	$	(14	)	$	754

Amortization expense associated with intangible assets during the three and six months ended June 30, 2016 was immaterial.

Intangibles at December 31, 2015 consisted primarily of Southern Power's PPA fair value adjustments with a net carrying amount of $317 million. The increases in goodwill and other intangibles relate to Southern Company's acquisition of PowerSecure on May 9, 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. See Note (I) under "Southern Company– Acquisition of PowerSecure International, Inc." for additional information regarding Southern Company's acquisition of PowerSecure.

(B) CONTINGENCIES AND REGULATORY MATTERS

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

General Litigation Matters

Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, 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

142

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs.

Georgia Power's environmental remediation liability as of June 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 June 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.

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.

143

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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. 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. The increase is primarily due to the Plant Daniel Units 1 and 2 scrubbers, which were placed in service in November 2015. 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 $8 million through the Kemper IGCC's projected in-service date of October 31, 2016.

Fuel Cost Recovery

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At June 30, 2016, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $23 million compared to $24 million at December 31, 2015. 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.

144

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	June 30, 2016		December 31, 2015
		(in millions)
Rate CNP Compliance	Under recovered regulatory clause revenues	$	7	$	43
	Deferred under recovered regulatory clause revenues	21		—
Rate CNP PPA	Deferred under recovered regulatory clause revenues	115		99
Retail Energy Cost Recovery	Other regulatory liabilities, current	75		238
	Deferred over recovered regulatory clause revenues	102		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	72		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 May 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 "Fuel Cost Recovery" 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 – Fuel Cost Recovery" and " – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery and the NCCR tariff, respectively.

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 (I) under "Southern Company – Merger with Southern Company Gas" for additional information regarding the Merger.

145

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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. Georgia Power exercised its contractual option to sell its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc., with an expected closing date in late August 2016.

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 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. 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 2019 general base rate case.

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 June 30, 2016 and December 31, 2015, Georgia Power's over recovered fuel balance totaled $164 million and $116 million, respectively, and is included in current liabilities and other deferred liabilities on Southern Company's and Georgia Power'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.

Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's or Georgia Power's revenues or net income, but will affect cash flow.

Nuclear Construction

See Note 3 to the financial statements of Southern Company and Georgia Power under "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

146

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 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 (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) as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated Vogtle Owner's costs associated with the proposed 18-month Contractor delay and to increase

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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. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service and contemplated in a general base rate case, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.

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 $250 million had been paid as of June 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.

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. The Staff is conducting a review of all costs incurred related to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the Contractor Settlement Agreement, and is authorized to engage in related settlement discussions with Georgia Power and any intervenors.

The order provides that the Staff is required to report to the Georgia PSC by October 19, 2016 with respect to the status of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of Plant Vogtle Units 3 and 4, the Georgia PSC will then conduct a hearing to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing Georgia Power to file a request for an amendment to the certificate for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority.

The Georgia PSC has approved thirteen VCM reports covering the periods through June 30, 2015, including construction capital costs incurred, which through that date totaled $3.1 billion. On February 26, 2016, Georgia Power filed its fourteenth VCM report with the Georgia PSC covering the period from July 1 through December 31,

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2015. The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. Georgia Power is requesting approval of $160 million of construction capital costs incurred during that period. Georgia Power incurred approximately $141 million in total construction capital costs during the period of January 1, 2016 through June 30, 2016. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.7 billion as of June 30, 2016. The in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion, of which $1.1 billion had been incurred through June 30, 2016.

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, assembly, delivery, and installation of plant equipment, the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS 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

Retail Base Rate Case

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 for additional information.

In 2013, the Florida PSC approved a settlement agreement that authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction 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, 2015, and the first six months of 2016, Gulf Power recognized reductions in depreciation of $8.4 million, $20.1 million, and $6.4 million, respectively.

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Cost Recovery Clauses

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

Regulatory Clause	Balance Sheet Location	June 30, 2016		December 31, 2015
		(in millions)
Fuel Cost Recovery	Other regulatory liabilities, current	$	18	$	18
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	4		1
Environmental Cost Recovery	Under recovered regulatory clause revenues	1		19
Energy Conservation Cost Recovery	Other regulatory liabilities, current	—		4

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

Fuel Cost Recovery

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

At June 30, 2016, the amount of over-recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet was $76 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 of February. As required by the order, on February 1, 2016, Mississippi Power submitted updated natural gas price forecasts and resulting fuel factors to the Mississippi PSC. If approved by the Mississippi PSC, the updated forecast would decrease fuel cost recovery rates by an additional $36 million annually. The ultimate outcome of this matter cannot be determined at this time.

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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

Construction of Mississippi Power's Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. 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 in-service date for the remainder of the Kemper IGCC is currently expected to occur by October 31, 2016, which reflects a one-month extension. The initial production of syngas began on July 14, 2016 and testing has continued on gasifier 'B' and the related lignite feed and ash systems. The schedule extension provides for time to complete mechanical equipment modifications to the gasifiers' supporting systems to increase capacity to the levels necessary to complete the remaining start-up activities and achieve sustained operations on both gasifiers. The remaining schedule also reflects the time expected to complete the initial operation and testing of the facility's syngas clean-up systems, as well as the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.

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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 June 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	$	5.43		$	5.15
Lignite Mine and Equipment	0.21		0.23			0.23
CO2 Pipeline Facilities	0.14		0.11			0.12
AFUDC(d)	0.17		0.72			0.66
Combined Cycle and Related Assets Placed in Service – Incremental(e)	—		0.03			0.02
General Exceptions	0.05		0.10			0.09
Deferred Costs(e)	—		0.20			0.19
Additional DOE Grants(f)	—		(0.14		)	(0.14		)
Total Kemper IGCC	$	2.97	$	6.68		$	6.32

(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 reflect estimated costs through October 31, 2016.

(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 June 30, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, are not included in the Current Cost Estimate and the Actual Costs at June 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.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of June 30, 2016, $3.59 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 $2.55 billion), $6 million in other property and investments, $81 million in fossil fuel stock, $46 million in materials and supplies, $35 million in other regulatory assets, current, $180 million in other regulatory assets, deferred, $1 million in other current assets, and $11 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.

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Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $81 million ($50 million after tax) in the second quarter 2016 and a total of $134 million ($83 million after tax) for the six months ended June 30, 2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.55 billion ($1.57 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through June 30, 2016. The increase to the cost estimate in 2016 primarily reflects costs for the extension of the Kemper IGCC's projected in-service date through October 31, 2016 and increased efforts related to operational readiness and challenges in start-up and commissioning activities, which includes the cost of repairs and modifications associated with the lignite feed process and the refractory lining for the gasifiers. Any extension of the in-service date beyond October 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 October 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 $14 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. Significant testing activities, including those for coal feed and gasification systems, as well as the initial operation and testing of the facility's gas clean-up systems and production of clean syngas, and, ultimately the generation of electricity, remain in process. 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, 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 to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's and Mississippi Power's statements of income and these changes could be material.

Rate Recovery of Kemper IGCC Costs

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

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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.

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. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed 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 in September 2015, subject to refund and certain other conditions.

On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full a stipulation 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.

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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.

Pursuant to the In-Service Asset Rate Order, Mississippi Power is required to file a subsequent rate request within 18 months. As part of the filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation.

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.

Mississippi Power expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at June 30, 2016 of $6.68 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, and additional carrying costs. Mississippi Power will seek approval from the Mississippi PSC to defer these costs for future rate recovery to be determined in connection with the final Kemper IGCC cost recovery approach ultimately approved. See "Regulatory Assets and Liabilities" below for additional information.

Regulatory Assets and Liabilities

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

In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015 and 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 June 30, 2016, the balance associated with these regulatory assets was $114 million, of which $35 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $101 million as of June 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 "2013 MPSC Rate Order" herein for information related to the July 7, 2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP. Also see "FERC Matters" herein for information related to the 2016 settlement agreement with wholesale customers.

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.

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The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. At June 30, 2016, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $5 million. See "2015 Rate Case" herein 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, 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. 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.

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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 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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(C) FAIR VALUE MEASUREMENTS

As of June 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 June 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	$	—	$	36	$	—	$	—	$	36
Interest rate derivatives	—		27		—		—		27
Nuclear decommissioning trusts(a)	642		917		—		18		1,577
Cash equivalents	1,014		—		—		—		1,014
Other investments	9		—		1		—		10
Total	$	1,665	$	980	$	1	$	18	$	2,664
Liabilities:
Energy-related derivatives	$	—	$	110	$	—	$	—	$	110
Interest rate derivatives	—		7		—		—		7
Foreign currency derivatives	—		38		—		—		38
Total	$	—	$	155	$	—	$	—	$	155
Alabama Power
Assets:
Energy-related derivatives	$	—	$	10	$	—	$	—	$	10
Nuclear decommissioning trusts(b)
Domestic equity	363		67		—		—		430
Foreign equity	46		47		—		—		93
U.S. Treasury and government agency securities	—		24		—		—		24
Corporate bonds	21		142		—		—		163
Mortgage and asset backed securities	—		22		—		—		22
Private Equity	—		—		—		18		18
Other	—		8		—		—		8
Cash equivalents	210		—		—		—		210
Total	$	640	$	320	$	—	$	18	$	978
Liabilities:
Energy-related derivatives	$	—	$	22	$	—	$	—	$	22

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(UNAUDITED)

	Fair Value Measurements Using
As of June 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	—		14		—		—		14
Nuclear decommissioning trusts(b) (c)
Domestic equity	187		1		—		—		188
Foreign equity	—		116		—		—		116
U.S. Treasury and government agency securities	—		109		—		—		109
Municipal bonds	—		57		—		—		57
Corporate bonds	—		159		—		—		159
Mortgage and asset backed securities	—		159		—		—		159
Other	25		6		—		—		31
Cash equivalents	90		—		—		—		90
Total	$	302	$	636	$	—	$	—	$	938
Liabilities:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Gulf Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	—	$	2
Cash equivalents	20		—		—		—		20
Total	$	20	$	2	$	—	$	—	$	22
Liabilities:
Energy-related derivatives	$	—	$	55	$	—	$	—	$	55
Interest rate derivatives	—		7		—		—		7
Total	$	—	$	62	$	—	$	—	$	62
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	—	$	1
Cash equivalents	102		—		—		—		102
Total	$	102	$	1	$	—	$	—	$	103
Liabilities:
Energy-related derivatives	$	—	$	23	$	—	$	—	$	23

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(UNAUDITED)

	Fair Value Measurements Using
As of June 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	$	—	$	8	$	—	$	—	$	8
Cash equivalents	449		—		—		—		449
Total	$	449	$	8	$	—	$	—	$	457
Liabilities:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Foreign currency derivatives	—		38		—		—		38
Total	$	—	$	43	$	—	$	—	$	43

(a) For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.

(b) Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies.

(c) Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of June 30, 2016, approximately $46 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 $28 million and $48 million, respectively, for the three and six months ended June 30, 2016, and decreased by $1 million and increased by $31 million, respectively, for the three and six months ended June 30, 2015. Alabama Power recorded an increase in fair value of $29 million and $40 million, respectively, for the three and six months ended June 30, 2016 and $5 million and $19 million, respectively, for the three and six months ended June 30, 2015 as a change in regulatory liabilities related to its AROs. Georgia Power recorded a decrease in fair value of $1 million and an increase of $8 million, respectively, for the three and six months ended June 30, 2016 and a decrease in fair value of $6 million and an increase in fair value of $12 million, respectively, for the three and six months ended June 30, 2015 as a change in its regulatory asset related to its AROs.

Valuation Methodologies

The energy-related derivatives primarily consist of 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 reflect 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 reflect the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable

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(UNAUDITED)

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.

"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 June 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 June 30, 2016:	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company	$	18	$	28	Not Applicable	Not Applicable
Alabama Power	$	18	$	28	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.

As of June 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	$	37,953	$	40,992
Alabama Power	$	7,090	$	7,940
Georgia Power	$	10,603	$	11,881
Gulf Power	$	1,182	$	1,275
Mississippi Power	$	2,983	$	2,967
Southern Power	$	4,332	$	4,523

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.

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(D) STOCKHOLDERS' EQUITY

Earnings per Share

For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:

	Three Months Ended June 30, 2016	Three Months Ended June 30, 2015	Six Months Ended June 30, 2016	Six Months Ended June 30, 2015
	(in millions)
As reported shares	934	909	925	910
Effect of options and performance share award units	6	3	6	4
Diluted shares	940	912	931	914

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 andsix months ended June 30, 2016, respectively, and were 15 million and 1 million for the three and six months ended June 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	—	—		1,097			—			—			1,097
Other comprehensive income (loss)	—	—		(117		)	—			—			(117		)
Stock issued	27,297	2,599		1,383			—			—			1,383
Stock-based compensation	—	—		82			—			—			82
Cash dividends on common stock	—	—		(1,023		)	—			—			(1,023		)
Contributions from noncontrolling interests	—	—		—			—			169			169
Distributions to noncontrolling interests	—	—		—			—			(10		)	(10		)
Purchase of membership interests from noncontrolling interests	—	—		—			—			(129		)	(129		)
Net income attributable to noncontrolling interests	—	—		—			—			11			11
Other	—	(19	)	1			—			—			1
Balance at June 30, 2016	942,370	(772	)	$	22,015		$	609		$	822		$	23,446
Balance at December 31, 2014	908,502	(725	)	$	19,949		$	756		$	221		$	20,926
Consolidated net income attributable to Southern Company	—	—		1,138			—			—			1,138
Other comprehensive income (loss)	—	—		7			—			—			7
Stock issued	3,222	—		117			—			—			117
Stock-based compensation	—	—		66			—			—			66
Stock repurchased, at cost	—	(2,599	)	(115		)	—			—			(115		)
Cash dividends on common stock	—	—		(972		)	—			—			(972		)
Preference stock redemption	—	—		—			(150		)	—			(150		)
Contributions from noncontrolling interests	—	—		—			—			135			135
Distributions to noncontrolling interests	—	—		—			—			(5		)	(5		)
Net income attributable to noncontrolling interests	—	—		—			—			4			4
Other	—	25		(8		)	3			—			(5		)
Balance at June 30, 2015	911,724	(3,299	)	$	20,182		$	609		$	355		$	21,146

(*) Primarily related to Southern Power Company.

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(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 June 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 June 30, 2016, the traditional electric operating companies had approximately $320 million (comprised of approximately $87 million at Alabama Power, $212 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 June 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	3		32		500		800		1,335		1,335		—		—		—		35
Georgia Power	—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	75		40		165		—		280		280		45		—		45		70
Mississippi Power	115		60		—		—		175		150		—		15		15		160
Southern Power Company(b)	—		—		—		600		600		560		—		—		—		—
Other	25		45		—		40		110		80		20		—		20		50
Total	$	218	$	177	$	1,665	$	4,440	$	6,500	$	6,387	$	65	$	15	$	80	$	315

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

(b) Excluding its subsidiaries. See "Southern Power Project Credit Facilities" below and Note (I) under "Southern Power" for additional information.

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 Tranquillity LLC, RE Roserock LLC, and RE Garland Holdings 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. Proceeds from the Project Credit Facilities are being used to finance project costs related to the respective solar facilities currently under construction. 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 June 30, 2016.

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(UNAUDITED)

Project	Maturity Date	Construction Loan Facility		Bridge Loan Facility		Loan Facility Total		Total Loan Facility Undrawn		Letter of Credit Facility		Total Letter of Credit Facility Undrawn
		(in millions)
Tranquillity	Earlier of PPA COD or December 31, 2016	$	86	$	172	$	258	$	19	$	77	$	26
Roserock	Earlier of PPA COD or November 30, 2016	63		180		243		34		23		16
Garland	Earlier of PPA COD or November 30, 2016	86		308		394		73		49		23
Total		$	235	$	660	$	895	$	126	$	149	$	65

The Project Credit Facilities had total amounts outstanding as of June 30, 2016 of $769 million at a weighted average interest rate of 2.02%. For the three-month period ended June 30, 2016, these credit agreements had a maximum amount outstanding of $769 million and an average amount outstanding of $586 million at a weighted average interest rate of 2.03%.

Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six 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	$	8,500	$	—	$	—	$	—		$	—
Alabama Power	400		200		—		45			—
Georgia Power	650		500		4		300			3
Gulf Power	—		125		—		—			—
Mississippi Power	—		—		—		1,100			651
Southern Power	1,241		—		—		2			4
Other	—		—		—		—			10
Elimination(b)	—		—		—		(200		)	(225		)
Total	$	10,791	$	825	$	4	$	1,247		$	443

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

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

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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 Merger and related transaction costs and for other general corporate purposes.

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 power generation facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar power or wind generation 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. The interest rate applicable to the $300 million principal amount is 2.571% for an interest period that extends to 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.

166

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Mississippi Power

In January 2016, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $275 million, which matures on December 1, 2017, bearing interest based on one-month LIBOR. As of June 30, 2016, Mississippi Power had borrowed $100 million under this promissory note with a $50 million draw occurring on each of January 29, 2016 and March 14, 2016. In addition, on January 19, 2016, Mississippi Power borrowed $100 million from Southern Company pursuant to a promissory note issued in November 2015. 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 existing promissory note issued in November 2015. As of June 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.

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 to repay existing indebtedness and for other general corporate purposes. Mississippi Power borrowed $900 million under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016, upon satisfaction of certain customary conditions. Mississippi Power used the initial proceeds to repay $900 million in maturing bank notes on March 8, 2016 and expects the remaining $300 million to be used to repay senior notes maturing in October 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR.

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.

Southern Power

During the six months ended June 30, 2016, Southern Power's subsidiaries borrowed an additional $632 million pursuant to the Project Credit Facilities at a weighted average interest rate of 2.00%. In addition, Southern Power's subsidiaries issued $16 million in letters of credit.

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 will be 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.

(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.

167

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Components of the net periodic benefit costs for the three and six months ended June 30, 2016 and 2015 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended June 30, 2016
Service cost	$	62		$	15		$	18		$	3		$	3
Interest cost	101			24			34			4			5
Expected return on plan assets	(187		)	(46		)	(65		)	(8		)	(8		)
Amortization:
Prior service costs	3			—			2			1			—
Net (gain)/loss	37			10			13			1			1
Net cost	$	16		$	3		$	2		$	1		$	1
Six Months Ended June 30, 2016
Service cost	$	124		$	29		$	35		$	6		$	6
Interest cost	201			48			68			9			10
Expected return on plan assets	(374		)	(92		)	(129		)	(17		)	(17		)
Amortization:
Prior service costs	7			1			3			1			—
Net (gain)/loss	75			20			27			3			3
Net cost	$	33		$	6		$	4		$	2		$	2
Three Months Ended June 30, 2015
Service cost	$	64		$	15		$	18		$	3		$	3
Interest cost	111			27			39			5			6
Expected return on plan assets	(181		)	(44		)	(63		)	(8		)	(9		)
Amortization:
Prior service costs	7			1			2			—			1
Net (gain)/loss	54			13			19			2			2
Net cost	$	55		$	12		$	15		$	2		$	3
Six Months Ended June 30, 2015
Service cost	$	128		$	30		$	36		$	6		$	6
Interest cost	222			53			77			10			11
Expected return on plan assets	(362		)	(89		)	(126		)	(16		)	(17		)
Amortization:
Prior service costs	13			3			5			—			1
Net (gain)/loss	108			27			38			5			5
Net cost	$	109		$	24		$	30		$	5		$	6

168

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 June 30, 2016
Service cost	$	6		$	2		$	1		$	1		$	1
Interest cost	17			4			7			—			1
Expected return on plan assets	(14		)	(7		)	(5		)	(1		)	(1		)
Amortization:
Prior service costs	1			1			1			—			—
Net (gain)/loss	4			1			2			—			—
Net cost	$	14		$	1		$	6		$	—		$	1
Six Months Ended June 30, 2016
Service cost	$	11		$	3		$	3		$	1		$	1
Interest cost	35			9			15			1			2
Expected return on plan assets	(28		)	(13		)	(11		)	(1		)	(1		)
Amortization:
Prior service costs	3			2			1			—			—
Net (gain)/loss	7			1			4			—			—
Net cost	$	28		$	2		$	12		$	1		$	2
Three Months Ended June 30, 2015
Service cost	$	5		$	2		$	1		$	—		$	1
Interest cost	20			5			9			1			1
Expected return on plan assets	(14		)	(7		)	(6		)	(1		)	(1		)
Amortization:
Prior service costs	1			—			—			—			—
Net (gain)/loss	4			1			3			—			—
Net cost	$	16		$	1		$	7		$	—		$	1
Six Months Ended June 30, 2015
Service cost	$	11		$	3		$	3		$	—		$	1
Interest cost	39			10			17			2			2
Expected return on plan assets	(29		)	(13		)	(12		)	(1		)	(1		)
Amortization:
Prior service costs	2			1			—			—			—
Net (gain)/loss	9			1			6			—			—
Net cost	$	32		$	2		$	14		$	1		$	2

169

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(G) INCOME TAXES

See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for additional tax information.

Current and Deferred Income Taxes

Tax Credit Carryforwards

Southern Company has federal ITC and PTC carryforwards totaling $801 million and $16 million, respectively, at June 30, 2016 (comprised primarily of $784 million and $16 million of ITC and PTC carryforwards, respectively, at Southern Power). These ITC and PTC carryforwards increased from $554 million and $1 million, respectively, as of December 31, 2015 (comprised primarily of $551 million and $1 million of ITC and PTC carryforwards, respectively, at Southern Power). Additionally, Southern Company has $208 million of state ITC carryforwards for the state of Georgia as of June 30, 2016, compared to $188 million at December 31, 2015.

The federal ITC carryforwards as of June 30, 2016 begin expiring in 2034 but are expected to be utilized by the end of 2021. The PTC carryforwards as of June 30, 2016 begin expiring in 2035 but are expected to be utilized by the end of 2020. The state ITC carryforwards for the state of Georgia as of June 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 30.4% for the six months ended June 30, 2016 compared to 32.9% 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 and increased tax benefits related to the estimated probable losses on Mississippi Power's construction of the Kemper IGCC, partially offset by the impact of additional state income tax benefits recognized in 2015.

Mississippi Power

Mississippi Power's effective tax rate (benefit rate) was (205.6)%for the six months ended June 30,2016 compared to 19.0% for the corresponding period in 2015. The effective tax rate decrease was primarily due to increased tax benefits related to the estimated probable losses on construction of the Kemper IGCC.

Southern Power

Southern Power's effective tax rate (benefit rate) was (74.0)%for the six months ended June 30,2016 compared to 13.7% 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	—		9		10
Balance as of June 30, 2016	$	421	$	17	$	443

The tax positions from current periods primarily relate to federal income tax benefits from ITCs impacting the estimated annual effective tax rate for interim reporting purposes.

The impact on the effective tax rate, if recognized, is as follows:

	As of June 30, 2016							As of December 31, 2015
	Mississippi Power			Southern Power		Southern Company		Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	(2	)	$	17	$	20	$	10
Tax positions not impacting the effective tax rate	423			—		423		423
Balance of unrecognized tax benefits	$	421		$	17	$	443	$	433

The tax positions impacting the effective tax rate primarily relate to federal income tax benefits from ITCs. The tax positions not impacting the effective tax rate relate to 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.

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 and 2014 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.

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

171

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Section 174. The IRS is currently reviewing the underlying support for the deduction, but has not completed its audit of these expenditures. 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 $423 million and associated interest of $15 million as of June 30, 2016. The ultimate outcome of this matter cannot be determined at this time.

(H) DERIVATIVES

Southern Company, the traditional electric operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate 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 gross 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

The traditional electric operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional electric operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, 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) and Southern Power have limited exposure to market volatility in commodity fuel prices and prices of electricity because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity.

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' 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 industry. 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.

172

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At June 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	250	2020	2016
Alabama Power	60	2019	—
Georgia Power	82	2019	—
Gulf Power	66	2020	—
Mississippi Power	29	2019	—
Southern Power	13	2017	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 3 million mmBtu for Southern Company and Georgia Power.

For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending June 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.

173

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At June 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 June 30, 2016
	(in millions)							(in millions)
Cash Flow Hedges of Forecasted Debt
Gulf Power	$	80		3-month LIBOR	2.32%	December 2026		$	(7	)
Cash Flow Hedges of Existing Debt
Southern Company	8		(d)	3-month LIBOR	1.73%	June 2020		—
Southern Company	3		(d)	3-month LIBOR	1.73%	June 2020		—
Georgia Power	200			3-month LIBOR + 0.40%	1.01%	August 2016		—
Fair Value Hedges of Existing Debt
Southern Company	250			1.30%	3-month LIBOR + 0.17%	August 2017		2
Southern Company	300			2.75%	3-month LIBOR + 0.92%	June 2020		11
Georgia Power	250			5.40%	3-month LIBOR + 4.02%	June 2018		3
Georgia Power	200			4.25%	3-month LIBOR + 2.46%	December 2019		6
Georgia Power	500			1.95%	3-month LIBOR + 0.76%	December 2018		5
Derivatives not Designated as Hedges
Southern Power	65		(a,d)	3-month LIBOR	2.50%	October 2016	(e)	—
Southern Power	47		(b,d)	3-month LIBOR	2.21%	October 2016	(e)	—
Southern Power	65		(c,d)	3-month LIBOR	2.21%	November 2016	(f)	—
Total	$	1,968						$	20

(a) 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.

(b) 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.

(c) 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.

(d) Amortizing notional amount.

(e) Represents the mandatory settlement date. Settlement will be based on a 15-year amortizing swap.

(f) Represents the mandatory settlement date. Settlement will be based on a 12-year amortizing swap.

174

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

The estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending June 30, 2017 are immaterial for all registrants. Southern Company and certain subsidiaries have deferred gains and losses that are expected to be amortized into earnings through 2046.

Foreign Currency Derivatives

Southern Company and certain subsidiaries may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time that the hedged transactions affect earnings, including 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 June 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 June 30, 2016
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	(17	)
Southern Power	564		3.78%	500		1.85%	June 2026	(21		)
Total	$	1,241		€	1,100			$	(38	)

The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to earnings for the next 12-month period ending June 30, 2017 are $(24) million for Southern Company and Southern Power.

175

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Derivative Financial Statement Presentation and Amounts

At June 30, 2016, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:

Asset Derivatives at June 30, 2016
	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:
Other current assets	$	12	$	5	$	6	$	1	$	—
Other deferred charges and assets	16		5		9		1		1
Total derivatives designated as hedging instruments for regulatory purposes	$	28	$	10	$	15	$	2	$	1	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets	$	5	$	—	$	—	$	—	$	—	$	5
Other deferred charges and assets	1		—		—		—		—		1
Interest rate derivatives:
Other current assets	11		—		6		—		—		—
Other deferred charges and assets	16		—		8		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	33	$	—	$	14	$	—	$	—	$	6
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets	$	2	$	—	$	—	$	—	$	—	$	2
Total asset derivatives	$	63	$	10	$	29	$	2	$	1	$	8

176

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Liability Derivatives at June 30, 2016
	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(*)	$	61	$	17	$	4	$	25	$	15
Other deferred credits and liabilities	44		5		1		30		8
Total derivatives designated as hedging instruments for regulatory purposes	$	105	$	22	$	5	$	55	$	23	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities(*)	$	3	$	—	$	—	$	—	$	—	$	3
Other deferred credits and liabilities	1		—		—		—		—		1
Interest rate derivatives:
Liabilities from risk management activities(*)	7		—		—		7		—		—
Foreign currency derivatives:
Liabilities from risk management activities(*)	24		—		—		—		—		24
Other deferred credits and liabilities	14		—		—		—		—		14
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	49	$	—	$	—	$	7	$	—	$	42
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current liabilities	$	1	$	—	$	—	$	—	$	—	$	1
Total liability derivatives	$	155	$	22	$	5	$	62	$	23	$	43

(*) Georgia Power, Mississippi Power, and Southern Power include current liabilities related to derivatives in "Other current liabilities."

177

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		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	3	$	1	$	2	$	—	$	—	N/A
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

178

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."

The derivative contracts of Southern Company, the traditional electric operating companies, and Southern Power are not subject to master netting arrangements or similar agreements and 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, interest rate derivative contracts, and foreign currency derivative contracts at June 30, 2016 and December 31, 2015 are presented in the following tables.

179

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Derivative Contracts at June 30, 2016
	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)	$	36		$	10		$	15		$	2		$	1		$	8
Gross amounts not offset in the Balance Sheet (b)	(32		)	(8		)	(4		)	(2		)	(1		)	(3		)
Net energy-related derivative assets	$	4		$	2		$	11		$	—		$	—		$	5
Interest rate and foreign currency derivatives:
Interest rate and foreign currency derivatives presented in the Balance Sheet (a)	$	27		$	—		$	14		$	—		$	—		$	—
Gross amounts not offset in the Balance Sheet (b)	(18		)	—			—			—			—			—
Net interest rate and foreign currency derivative assets	$	9		$	—		$	14		$	—		$	—		$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	110		$	22		$	5		$	55		$	23		$	5
Gross amounts not offset in the Balance Sheet (b)	(32		)	(8		)	(4		)	(2		)	(1		)	(3		)
Net energy-related derivative liabilities	$	78		$	14		$	1		$	53		$	22		$	2
Interest rate and foreign currency derivatives:
Interest rate and foreign currency derivatives presented in the Balance Sheet (a)	$	45		$	—		$	—		$	7		$	—		$	38
Gross amounts not offset in the Balance Sheet (b)	(18		)	—			—			—			—			—
Net interest rate and foreign currency derivative liabilities	$	27		$	—		$	—		$	7		$	—		$	38

(a) None of the registrants offsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.

(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

180

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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) None of the registrants offsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.

(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

181

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At June 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 on the Balance Sheet at June 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	$	(61	)	$	(17	)	$	(4	)	$	(25	)	$	(15	)
Other regulatory assets, deferred	(44		)	(5		)	(1		)	(30		)	(8		)
Other regulatory liabilities, current (a)	12			5			6			1			—
Other regulatory liabilities, deferred (b)	16			5			9			1			1
Total energy-related derivative gains (losses)	$	(77	)	$	(12	)	$	10		$	(53	)	$	(22	)

(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 on 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.

182

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the three months ended June 30, 2016 and 2015, the pre-tax effects of 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
Interest rate derivatives	$	6		$	31	Interest expense, net of amounts capitalized	$	(4	)	$	(2	)
Foreign currency derivatives	(39		)	—		Interest expense, net of amounts capitalized	(1		)	—
						Other income (expense), net	(20		)	—
Total	$	(33	)	$	31		$	(25	)	$	(2	)
Alabama Power
Interest rate derivatives	$	—		$	7	Interest expense, net of amounts capitalized	$	(2	)	$	(1	)
Georgia Power
Interest rate derivatives	$	—		$	24	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Gulf Power
Interest rate derivatives	$	(2	)	$	—	Interest expense, net of amounts capitalized	$	—		$	—
Southern Power
Foreign currency derivatives	$	(39	)	$	—	Interest expense, net of amounts capitalized	$	(1	)	$	—
						Other income (expense), net	(20		)	—
Total	$	(39	)	$	—		$	(21	)	$	—

183

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the six months ended June 30, 2016 and 2015, the pre-tax effects of 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
Interest rate derivatives	$	(184	)	$	2	Interest expense, net of amounts capitalized	$	(7	)	$	(4	)
Foreign currency derivatives	(39		)	—		Interest expense, net of amounts capitalized	(1		)	—
						Other income (expense), net	(20		)	—
Total	$	(223	)	$	2		$	(28	)	$	(4	)
Alabama Power
Interest rate derivatives	$	(4	)	$	1	Interest expense, net of amounts capitalized	$	(3	)	$	(1	)
Georgia Power
Interest rate derivatives	$	—		$	1	Interest expense, net of amounts capitalized	$	(2	)	$	(2	)
Gulf Power
Interest rate derivatives	$	(7	)	$	—	Interest expense, net of amounts capitalized	$	—		$	—
Mississippi Power
Interest rate derivatives	$	—		$	—	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Southern Power
Interest rate derivatives	$	—		$	—	Interest expense, net of amounts capitalized	$	(1	)	$	—
Foreign currency derivatives	(39		)	—		Interest expense, net of amounts capitalized	(1		)	—
						Other income (expense), net	(20		)	—
Total	$	(39	)	$	—		$	(22	)	$	—

For the three and six months ended June 30, 2016 and 2015, the pre-tax effects of energy-related derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were immaterial for all registrants.

For the three months ended June 30, 2016 and 2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were immaterial on a gross basis for all registrants.

For the six months ended June 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)
Derivative Category	Statements of Income Location	2016		2015
		(in millions)
Southern Company
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	24	$	4
Georgia Power
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	15	$	2

184

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the three and six months ended June 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 six months ended June 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

The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At June 30, 2016, the registrants' collateral posted with their derivative counterparties was immaterial.

At June 30, 2016, the fair value of derivative liabilities with contingent features was $24 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 $24 million and include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.

Southern Company, the traditional electric operating companies, and Southern Power are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional electric operating companies, and Southern Power 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, and Southern Power 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', and Southern Power's exposure to counterparty credit risk. 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.

185

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

The Merger will be accounted for using the acquisition method of accounting whereby the assets acquired and liabilities assumed are recognized at fair value as of the acquisition date. The excess of the purchase price over the fair values of Southern Company Gas' assets and liabilities will be recorded as goodwill. The following table presents the preliminary purchase price allocation:

Southern Company Gas Purchase Price	June 30, 2016
	(in millions)
Current assets	$	1,474
Property, plant, and equipment	9,795
Goodwill	6,333
Intangible assets	436
Regulatory assets	846
Other assets	273
Current liabilities	(2,205		)
Other liabilities	(4,529		)
Long-term debt	(4,261		)
Noncontrolling interests	(160		)
Total purchase price	$	8,002

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 may have a material impact on the results of operations and financial position of Southern Company.

During the three and six months ended June 30, 2016, Southern Company recorded in its statements of income external transaction costs for financing, legal, and consulting services associated with the Merger of approximately $43.4 million and $63.3 million, respectively, of which $26.9 million and $32.9 million is included in operating expenses and $16.5 million and $30.4 million is included in other income and (expense), respectively.

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 leading 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.

186

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

The aggregate purchase price was allocated on a preliminary basis to the assets acquired and liabilities assumed based upon the current determination of fair values at the date of acquisition. The preliminary allocation of the purchase price is as follows:

PowerSecure Purchase Price	June 30, 2016
	(in millions)
Current assets	$	174
Property, plant, and equipment	48
Goodwill	262
Intangible assets	99
Other assets	8
Current liabilities	(111		)
Long-term debt, including current portion	(47		)
Deferred credits and other liabilities	(4		)
Total purchase price	$	429

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $262 million was recognized as goodwill, which is primarily attributable to the 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. Assumptions and estimates underlying the fair value adjustments are subject to change pending further review of the assets acquired and liabilities assumed.

The preliminary valuation of identifiable intangible assets included customer relationships, trade names, patents, and backlog with estimated lives of three 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.

Natural Gas Pipeline Venture

On July 10, 2016, Southern Company and Kinder Morgan, Inc. (Kinder Morgan) entered into a definitive agreement under which Southern Company will acquire a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG), which is the owner of a 7,600-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, Alabama, and the Gulf of Mexico to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. Southern Company expects to finance the purchase price of approximately $1.5 billion with a mix of equity and debt in a credit-supportive manner. Southern Company's investment in SNG will be accounted for under the equity method of accounting.

The transaction is subject to the notification and clearance and reporting requirements under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Southern Company and Kinder Morgan expect to complete the transaction in the third quarter or early in the fourth quarter 2016. The ultimate outcome of this matter cannot be determined at this time.

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 six months ended June 30, 2016, the fair values of the assets and liabilities acquired of Garland, Garland A, Lost Hills Blackwell, Morelos, North Star, and Roserock were finalized and there were no changes.

187

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

During 2016, in accordance with its overall growth strategy, Southern Power acquired or contracted to acquire through its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC or Southern Renewable Energy, Inc., 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.

Project Facility	Resource	Seller; Acquisition Date	Approx. Nameplate Capacity	Location	Southern Power Percentage Ownership			Expected/Actual COD	PPA Counterparties for Plant Output	PPA Contract Period
			(MW)
Acquisitions for the Six Months Ended June 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	%		Fourth quarter 2016	Austin Energy	15 years
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
Passadumkeag	Wind	Quantum Utility Generation, LLC June 30, 2016	42	Penobscot County, ME	100	%		July 2016	Western Massachusetts Electric Company	15 years
Acquisitions Subsequent to June 30, 2016
Henrietta	Solar	SunPower Corp. July 1, 2016	102	Kings County, CA	51	%	(*)	July 2016	Pacific Gas and Electric Company	20 years
Lamesa	Solar	RES America Developments Inc. July 1, 2016	102	Dawson County, TX	100	%		Second quarter 2017	City of Garland, Texas	15 years
Rutherford	Solar	Cypress Creek Renewables, LLC July 1, 2016	74	Rutherford County, NC	90	%		Fourth quarter 2016	Duke Energy Carolinas, LLC	15 years

(*) 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.

Acquisitions During the Six Months Ended June 30, 2016

Southern Power's aggregate purchase price for the project facilities acquired during the six months ended June 30, 2016 is approximately $477 million, which includes $6 million of contingent consideration. Including the minority owner Turner Renewable Energy, LLC's (TRE) 10% ownership interest in Calipatria, the total aggregate purchase price is approximately $483 million for the project facilities acquired during the six months ended June 30, 2016. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: $426 million as CWIP, $58 million as property, plant, and equipment, $4 million as other assets, and $7 million as accounts payable; however, the allocations of the purchase price to individual assets have not been finalized. For East Pecos, which is currently under construction, total construction costs, excluding the acquisition costs, are expected to be approximately $160 million to $180 million. The ultimate outcome of this matter cannot be determined at this time.

188

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Acquisitions Subsequent to June 30, 2016

Southern Power's aggregate purchase price for acquisitions subsequent to June 30, 2016 is approximately $275 million. Including the minority owner, SunPower Corp.'s 49% ownership interest in Henrietta, and TRE's 10% ownership interest in Rutherford, the aggregate total purchase price is approximately $447 million for the project facilities acquired subsequent to June 30, 2016. The aggregate purchase price includes the assumption of $217 million in construction debt (non-recourse to Southern Power). For Lamesa and Rutherford, which are currently under construction, total aggregate construction costs, excluding the acquisition costs, are expected to be approximately $260 million to $300 million. The ultimate outcome of these matters cannot be determined at this time.

Acquisition Agreements Executed but Not Yet Closed

During the six months ended June 30, 2016 and subsequent to that date, Southern Power entered into agreements to acquire the following projects for an aggregate purchase price of $1.1 billion: 100% ownership interests in two wind facilities totaling 299 MWs in Texas, significantly covered with PPAs for the first 12 to 14 years of operation; a 51% ownership interest (through 100% ownership of the Class A membership interests entitling Southern Power to 51% of all cash distributions and significantly all of the federal tax benefits) in a 100-MW solar facility in Nevada with a 20-year PPA; and a 90.1% ownership interest in a 257-MW wind facility in Texas significantly covered with a 12-year PPA. These acquisitions are expected to close in the third and fourth quarters of 2016. 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 six months ended June 30, 2016 included in the consolidated statement of income for year-to-date 2016 is $4 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 six months ended June 30, 2016 included in the consolidated statement 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 six months ended June 30, 2016, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service the Butler Solar Farm and Pawpaw solar facilities. In addition, Southern Power continued construction of the projects set forth in the table below. Through June 30, 2016, total costs of construction incurred for the projects below were $2.7 billion, of which $1.7 billion remains in CWIP. Including the total construction costs incurred to date and the acquisition prices allocated to CWIP, total aggregate construction costs for the projects below are estimated to be approximately $3.0 billion to $3.2 billion. The ultimate outcome of these matters cannot be determined at this time.

189

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Solar Facility	Seller	Approx. Nameplate Capacity	Location	Expected/Actual COD	PPA Counterparties for Plant Output	PPA Contract Period
		(MW)
Butler	CERSM, LLC and Community Energy, Inc.	103	Taylor County, GA	Fourth quarter 2016	Georgia Power(a)	30 years
Desert Stateline(b)	First Solar Development, LLC	299(c)	San Bernardino County, CA	Through third quarter 2016	Southern California Edison Company (SCE)	20 years
Garland and Garland A	Recurrent Energy, LLC	205	Kern County, CA	Fourth quarter 2016 and Third quarter 2016	SCE	15 years and 20 years
Roserock	Recurrent Energy, LLC	160	Pecos County, TX	Fourth quarter 2016	Austin Energy	20 years
Sandhills	N/A	146	Taylor County, GA	Fourth quarter 2016	Cobb, Flint, Irwin, Middle Georgia and Sawnee Electric Membership Corporations	25 years
Tranquillity	Recurrent Energy, LLC	205	Fresno County, CA	July 2016	Shell Energy North America (US), LP/SCE	18 years

(a) Butler - Affiliate PPA approved by the FERC.

(b) Desert Stateline - 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. Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized.

(c) Desert Stateline - The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 152 MWs were placed in service during the six months ended June 30, 2016. Subsequent to June 30, 2016, 37 MWs were placed in service.

190

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. 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 generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market.

Southern Company's reportable business segments are the sale of electricity by the four traditional electric operating companies and Southern Power. Revenues from sales by Southern Power to the traditional electric operating companies were $107 million and $204 million for the three and six months ended June 30, 2016, respectively, and $85 million and $199 million for the three and six months ended June 30, 2015, respectively. The "All Other" column includes parent Southern Company, 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.

Financial data for business segments and products and services for the three and six months ended June 30, 2016 and 2015 was as follows:

	Electric Utilities
	Traditional Electric Operating Companies		Southern Power		Eliminations			Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2016:
Operating revenues	$	4,115	$	373	$	(109	)	$	4,379	$	125		$	(45	)	$	4,459
Segment net income (loss)(a)(b)	595		89		—			684		(68		)	(4		)	612
Six Months Ended June 30, 2016:
Operating revenues	$	7,884	$	688	$	(212	)	$	8,360	$	172		$	(81	)	$	8,451
Segment net income (loss)(a)(c)	1,059		139		—			1,198		(94		)	(7		)	1,097
Total assets at June 30, 2016	$	70,706	$	11,082	$	(425	)	$	81,363	$	10,505		$	(995	)	$	90,873
Three Months Ended June 30, 2015:
Operating revenues	$	4,077	$	337	$	(90	)	$	4,324	$	43		$	(30	)	$	4,337
Segment net income (loss)(a)(b)	561		46		—			607		18			4			629
Six Months Ended June 30, 2015:
Operating revenues	$	8,025	$	684	$	(213	)	$	8,496	$	83		$	(59	)	$	8,520
Segment net income (loss)(a)(c)	1,038		79		—			1,117		21			—			1,138
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 $81 million ($50 million after tax) and $23 million ($14 million after tax) for the three months ended June 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 $134 million ($83 million after tax) and $32 million ($20 million after tax) for the six months ended June 30, 2016 and 2015, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.

191

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended June 30, 2016	$	3,748	$	446	$	185	$	4,379
Three Months Ended June 30, 2015	3,714		448		162		4,324
Six Months Ended June 30, 2016	$	7,124	$	842	$	394	$	8,360
Six Months Ended June 30, 2015	7,256		915		325		8,496

192

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: retail operations including the provision of natural gas commodity and related services to customers in competitive markets or markets that provide for customer choice, wholesale services including natural gas storage, gas pipeline arbitrage, and natural gas asset management and/or related logistics services, and 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
Southern Company
(a)1	Certificate of Amendment to the Certificate of Incorporation of the Southern Company effective May 26, 2016. (Designated in Form 8-K dated May 25, 2016, File No. 1-3526, as Exhibit 3.1.)
(a)2	By-Laws of the Southern Company, as amended effective May 25, 2016. (Designated in Form 8-K dated May 25, 2016, File No. 1-3526, as Exhibit 3.2.)

193

		(4) Instruments Describing Rights of Security Holders, Including Indentures
		Southern Company
		(a)1	-	Twelfth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 1.55% Senior Notes due 2018. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(a).)
		(a)2	-	Thirteenth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 1.85% Senior Notes due 2019. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(b).)
		(a)3	-	Fourteenth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 2.35% Senior Notes due 2021. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(c).)
		(a)4	-	Fifteenth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 2.95% Senior Notes due 2023. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(d).)
		(a)5	-	Sixteenth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 3.25% Senior Notes due 2026. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(e).)
		(a)6	-	Seventeenth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 4.25% Senior Notes due 2036. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(f).)
		(a)7	-	Eighteenth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 4.40% Senior Notes due 2046. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(g).)
		Southern Power
		(f)1	-	Tenth Supplemental Indenture to Senior Note Indenture, dated as of June 20, 2016, providing for the issuance of the Series 2016A 1.000% Senior Notes due June 20, 2022. (Designated in Form 8-K dated June 13, 2016, File No. 001-37803, as Exhibit 4.4(a).)
		(f)2	-	Eleventh Supplemental Indenture to Senior Note Indenture, dated as of June 20, 2016, providing for the issuance of the Series 2016B 1.850% Senior Notes due June 20, 2026. (Designated in Form 8-K dated June 13, 2016, File No. 001-37803, as Exhibit 4.4(b).)
		(10) Material Contracts
		Southern Company
#	*	(a)1	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective June 30, 2016.
#	*	(a)2	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective June 30, 2016.
		Alabama Power
#		(b)1	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective June 30, 2016. See Exhibit 10(a)1 herein.
#		(b)2	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective June 30, 2016. See Exhibit 10(a)2 herein.
		Georgia Power
#		(c)1	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective June 30, 2016. See Exhibit 10(a)1 herein.

194

#		(c)2	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective June 30, 2016. See Exhibit 10(a)2 herein.
	*	(c)3	-	Amendment No. 8 dated as of April 20, 2016, to Engineering, Procurement and Construction Agreement, dated as of April 8, 2008, between Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and Dalton Utilities, as owners, and a consortium consisting of Westinghouse Electric Company LLC and CB&I Stone & Webster, Inc., as contractor, for Units 3&4 at the Vogtle Electric Generating Plant Site. (Georgia Power has requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the SEC. Georgia Power omitted such portions from the filing and filed them separately with the SEC.)
		Gulf Power
#		(d)1	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective June 30, 2016. See Exhibit 10(a)1 herein.
#		(d)2	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective June 30, 2016. See Exhibit 10(a)2 herein.
		Mississippi Power
#		(e)1	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective June 30, 2016. See Exhibit 10(a)1 herein.
#		(e)2	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective June 30, 2016. See Exhibit 10(a)2 herein.
		(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.)

195

	(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.
*	(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.

196

	(32) Section 906 Certifications
	Southern Company
*	(a)	-	Certificate of Southern Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Alabama Power
*	(b)	-	Certificate of Alabama Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Georgia Power
*	(c)	-	Certificate of Georgia Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Gulf Power
*	(d)	-	Certificate of Gulf Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Mississippi Power
*	(e)	-	Certificate of Mississippi Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Southern Power
*	(f)	-	Certificate of Southern Power Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	(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

197

THE SOUTHERN COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.

	THE SOUTHERN COMPANY
By	Thomas A. Fanning
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Art P. Beattie
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)
By	/s/Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: August 8, 2016

198

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: August 8, 2016

199

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, Treasurer, and Corporate Secretary
	(Principal Financial Officer)
By	/s/Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: August 8, 2016

200

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: August 8, 2016

201

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: August 8, 2016

202

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: August 8, 2016

203

EX-10.A1

Exhibit 10(a)1

THE SOUTHERN COMPANY

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

Amended and Restated Effective June 30, 2016

TABLE OF CONTENTS

			Page
ARTICLE I -		PURPOSE AND ADOPTION OF PLAN	1
	1.1	Adoption	1
	1.2	Purpose	1
ARTICLE II -		DEFINITIONS	1
ARTICLE III -		ADMINISTRATION OF PLAN	4
	3.1	Administrator	4
	3.2	Powers	4
	3.3	Duties of the Administrative Committee	5
	3.4	Indemnification	6
ARTICLE IV -		ELIGIBILITY	6
	4.1	Eligibility Requirements	6
	4.2	Determination of Eligibility	6
ARTICLE V -		BENEFITS	7
	5.1	SERP Benefit	7
	5.2	Distribution of Benefits	8
	5.3	Code Section 409A Transition Election and Other Related Rules	10
	5.4	Allocation of SERP Benefit Liability	15
	5.5	Funding of Benefits	16
	5.6	Withholding	16
	5.7	Recourse Against Deferred Compensation Trust	16
	5.8	Change in Control	16
ARTICLE VI -		MISCELLANEOUS	16
	6.1	Assignment	16
	6.2	Amendment and Termination	16
	6.3	No Guarantee of Employment	17
	6.4	Construction	17

- i -

THE SOUTHERN COMPANY
SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

ARTICLE 1 -   PURPOSE AND ADOPTION OF PLAN

1.1Adoption. The Southern Company Supplemental Executive Retirement Plan, effective as of July 1, 2016 and hereinafter set forth (the “Plan”), is a modification and continuation of The Southern Company Supplemental Executive Retirement Plan which originally became effective January 1, 1997, and was last amended and restated effective January 1, 2009. The purpose of this amendment and restatement is to incorporate the First and Second Amendments and to set forth changes to implement new design features. The January 1, 2009 amendment and restatement and the January 1, 2005 amendment and restatement are intended to bring the Plan into compliance with Code Section 409A. The Plan should be construed to satisfy this intent. The Plan shall be an unfunded deferred compensation arrangement as contemplated by the Employee Retirement Income Security Act, as amended, under which benefits shall be paid solely from the general assets of the Company. At a time and in a manner determined by the Administrative Committee, Participants shall make timely elections to conform to the Plan’s terms effective as of the January 1, 2005 amendment and restatement. Such elections are intended to meet the transition requirements of Code Section 409A, including proposed, temporary, or final regulations, or other guidance issued by the Secretary of Treasury and the Internal Revenue Service with respect thereto (collectively “409A Guidance”).

1.2Purpose. The Plan provides deferred compensation primarily to a select group of management or highly compensated employees to supplement such employees’ accrued benefits under The Southern Company Pension Plan (“Pension Plan”). The supplement under this Plan is generally intended to make up the difference, if any, between each such employee’s actual accrued benefit under the Pension Plan and the benefit he would have accrued under such plan if certain incentive pay were included in Earnings when determining Average Monthly Earnings for all methods of calculating Retirement Income under the Pension Plan.

ARTICLE II -   DEFINITIONS

2.1“Actuarial Basis” shall mean an actuarial adjustment to SERP Benefits that must be made as required by Code Section 409A when there is a change made by a Participant to a previously elected or deemed-elected form of payment paid over a lifetime. Reasonable actuarial assumptions to make such adjustment shall be established in writing from time to time by the Administrative Committee.

2.2“Administrative Committee” shall mean the committee referred to in Section 3.1 hereof.

2.3“Affiliated Employer” shall mean any corporation which is a member of the controlled group of corporations of which Southern Company is the common parent corporation which the Board of Directors may from time to time determine to bring under the Plan and which shall adopt the Plan, and any successor of any of them. The Affiliated Employers are set forth in Appendix A to the Plan, as amended from time to time.

2.4“Board of Directors” shall mean the Board of Directors of the Company.

2.5“Change in Control Benefits Protection Plan” shall mean the Change in Control Benefits Protection Plan, as approved by the Southern Board, as it may be amended from time to time in accordance with the provisions therein.

2.6“Code” shall mean the Internal Revenue Code of 1986, as amended from time to time.

2.7“Company” shall mean Southern Company Services, Inc.

2.8“Designated Beneficiary” shall have the same meaning set forth under the Supplemental Benefit Plan with respect to the Pension Benefit provided thereunder. For the avoidance of doubt, the Designated Beneficiary(ies) under this Plan may be different than the persons(s) or entity(ies) who is the Designated Beneficiary under the Supplemental Benefit Plan.

2.9 “Discount Rate” shall mean the thirty (30) year Treasury yield as published by the Department of Treasury for purposes of compliance with Code Section 417(e) determined for September of the calendar year prior to the calendar year in which a Participant Separates from Service provided that the maximum rate shall not exceed six percent (6%).

2.10“Earnings” shall mean the total accumulated interest on a Participant’s Single-Sum Amount. Unless otherwise stated, Earnings accrue from the date as of which a Participant’s first installment is payable (ignoring for this purpose any Key-Employee Delay) until all of the Participant’s Single-Sum Amount (and monthly interest accretion thereon) has been paid. Interest shall compound monthly based on the rate of interest accretion for each month and the unpaid portion of a Participant’s Single-Sum Amount (including any unpaid portion of any prior month’s interest accretion). The rate of such interest accretion for a month shall be the monthly equivalent of the per annum prime rate of interest published in the Wall Street Journal as the base rate on the corporate loans posted as of the last business day of each month by at least seventy-five percent (75%) of the United States largest banks as of the last business day of the month (or such other day of a month as the Administrative Committee may determine).

2.11“Effective Date” of this amendment and restatement shall mean June 30, 2016.

2.12“Employee” shall mean any person who is employed by an Affiliated Employer excluding any persons represented by a collective bargaining agent.

2.13“Expected Average Lifetime” shall mean the life expectancy of a Participant in months using the Table of Unisex Mortality Rates promulgated by the Internal Revenue Service for use to determine lump-sum payments from qualified pension plans in accordance with Code Section 417(e) as of the 2007 calendar year.

2.14“Incentive Pay” shall mean all awards earned while an Employee under any annual group incentive plans, as defined in Section 5.1 of the Pension Plan, provided such incentive award was earned on or after January 1, 1994. Alternatively, if it produces a greater benefit to the Participant, Incentive Pay shall mean all awards paid or that would have been paid but for an election to defer such incentive award under The Southern Company Deferred Compensation Plan, under any annual group incentive plan, as defined in Section 5.1 of the Pension Plan, provided such incentive award was paid or deferred on or after January 1, 1995. If

2

a person was formerly represented by a collective bargaining agent with respect to any corporation which is a member of the controlled group of corporations of which Southern Company is the common parent and such person subsequently becomes an Employee, incentive awards described in the preceding sentence shall include awards earned on and after January 1, 1994 while represented by such collective bargaining agent.

2.15“Key Employee” shall have the meaning ascribed to the term “specified employee” under Code Section 409A(a)(2)(B)(i) and the regulations promulgated thereunder as it applies to a Participant. The Administrative Committee shall establish the time period required to determine key-employee status.

2.16“Key-Employee Delay” shall mean the six (6) month delay in the commencement of benefits applicable to Key Employees pursuant to the requirements of Code Section 409A(a)(2)(B)(i) and the regulations promulgated thereunder.

2.17“Participant” shall mean an Employee or former Employee of an Affiliated Employer who is eligible and participates in the Plan pursuant to Sections 4.1 and 4.2.

2.18“Pension Plan” shall mean The Southern Company Pension Plan, as amended from time to time.

2.19“Plan” shall mean The Southern Company Supplemental Executive Retirement Plan, as amended and restated as of June 30, 2016 and as may be amended from time to time thereafter.

2.20“Plan Year” shall mean the calendar year.

2.21“Provisional Payee” shall have the same meaning ascribed to this term in the Pension Plan.

2.22“Separation from Service” shall have the meaning ascribed to this term under Code Section 409A(a)(2)(A)(i) and the regulations promulgated thereunder. For this purpose, Separation from Service shall include a permanent decrease in the level of bona fide services performed by the Participant after a certain date to a level that is twenty percent (20%) or less of the average level of bona fide services performed by the Participant over the immediately preceding thirty-six (36) month period.

2.23“SERP Benefit” shall mean the benefit described in Section 5.1.

2.24“Single-Sum Amount” shall mean the discounted value of the SERP Benefit based on a single life annuity form of benefit payable for an Expected Average Lifetime calculated using the Discount Rate. This Single-Sum Amount calculation shall be determined effective as of the first installment to be made under Section 5.2 (ignoring for this purposes any Key-Employee Delay) taking into account the following: (a) reductions for charges related to any Qualified Pre-retirement Survivor Annuity form of benefit under the Pension Plan shall not apply; and (b) the SERP Benefit and Expected Average Lifetime shall be based on the Participant’s age as of such first installment date.

3

2.25“Southern Board” shall mean the board of directors of Southern Company.

2.26“Supplemental Benefit Plan” shall mean The Southern Company Supplemental Benefit Plan, as amended from time to time.

2.27“Supplemental Pension Benefit” shall mean the “Pension Benefit”, if any, that is payable to a Participant under the Supplemental Benefit Plan.

2.28“Trust” shall mean the Southern Company Deferred Compensation Trust.

Where the context requires, the definitions of all terms set forth in the Pension Plan shall apply with equal force and effect for purposes of interpretation and administration of the Plan, unless said terms are otherwise specifically defined in the Plan. The masculine pronoun shall be construed to include the feminine pronoun and the singular shall include the plural, where the context so requires.

ARTICLE III -   ADMINISTRATION OF PLAN

3.1Administrator. Effective May 31, 2007, the general administration of the Plan shall be placed in the “Committee” which shall consist of the Benefits Administration Committee, the members of which shall be appointed from time to time by the Fiduciary Oversight Committee of the Board of Directors. The Committee shall govern itself in accordance with the terms of the Charter for the Benefits Administration Committee approved by the Fiduciary Oversight Committee of the Board of Directors.

3.2Powers.

(a)The Administrative Committee shall administer the Plan in accordance with its terms and shall have all powers necessary to carry out the provisions of the Plan more particularly set forth herein. It shall have the discretion to interpret the Plan and shall determine all questions arising in the administration, interpretation, and application of the Plan. Any such determination by it shall be conclusive and binding on all persons. The Administrative Committee shall be the agent for the service of process.

(b)If a claim for benefits under the Plan is denied, in whole or in part, the Administrative Committee will provide a written notice of the denial within a reasonable period of time, but not later than 90 days after the claim is received. If special circumstances require more time to process the claim, the Administrative Committee will issue a written explanation of the special circumstances prior to the end of the 90-day period and a decision will be made as soon as possible, but not later than 180 days after the claim is received.

The written notice of claim denial will include:

• Specific reasons why the claim was denied;

• Specific references to applicable provisions of the Plan document or other relevant records or papers on which the denial is based, and information about where a Participant or his or her Designated Beneficiary may see them;

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• A description of any additional material or information needed to process the claim and an explanation of why such material or information is necessary;

• An explanation of the claims review procedure, including the time limits applicable to such procedure, as well as a statement notifying the Participant or his or her Designated Beneficiary of their right to file suit if the claim for benefits is denied, in whole or in part, on review.

Upon request, a Participant or his or her Designated Beneficiary will be provided without charge, reasonable access to, and copies of, all non-confidential documents that are relevant to any denial of benefits. A claimant has 60 days from the day he or she receives the original denial to request a review. Such request must be made in writing and sent to the Administrative Committee. The request should state the reasons why the claim should be reviewed and may also include evidence or documentation to support the claimant’s position.

The Administrative Committee will reconsider the claimant’s claim, taking into account all evidence, documentation, and other information related to the claim and submitted on the claimant’s behalf, regardless of whether such information was submitted or considered in the initial denial of the claim. The Administrative Committee will make a decision within 60 days. If special circumstances require more time for this process, the claimant will receive written explanation of the special circumstances prior to the end of the initial 60-day period and a decision will be sent as soon as possible, but not later than 120 days after the Administrative Committee receives the request.

No legal action to receiver benefits or enforce or clarify rights under a Plan can be commenced until the Participant or his or her Designated Beneficiary has first exhausted the claims and review procedures provided under the Plan.

(c)The Administrative Committee may adopt such regulations as it deems desirable for the conduct of its affairs. It may appoint such accountants, counsel, actuaries, specialists, and other persons as it deems necessary or desirable in connection with the administration of this Plan.

3.3Duties of the Administrative Committee.

(a)The Administrative Committee is responsible for the daily administration of the Plan. It may appoint other persons or entities to perform any of its fiduciary functions. The Administrative Committee and any such appointee may employ advisors and other persons necessary or convenient to help it carry out its duties, including its fiduciary duties. The Administrative Committee shall have the right to remove any such appointee from his position. Any person, group of persons, or entity may serve in more than one fiduciary capacity.

(b)The Administrative Committee shall maintain accurate and detailed records and accounts of Participants and of their rights under the Plan and of all receipts, disbursements, transfers, and other transactions concerning the Plan. Such accounts, books, and records relating thereto shall be open at all reasonable times to inspection and audit by persons designated by the Administrative Committee.

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(c)The Administrative Committee shall take all steps necessary to ensure that the Plan complies with the law at all times. These steps shall include such items as the preparation and filing of all documents and forms required by any governmental agency; maintaining of adequate Participants’ records; recording and transmission of all notices required to be given to Participants and their Designated Beneficiaries; the receipt and dissemination, if required, of all reports and information received from an Affiliated Employer; securing of such fidelity bonds as may be required by law; and doing such other acts necessary for the proper administration of the Plan. The Administrative Committee shall keep a record of all of its proceedings and acts, and shall keep all such books of account, records, and other data as may be necessary for proper administration of the Plan.

3.4Indemnification. The Affiliated Employers shall indemnify the Administrative Committee against any and all claims, losses, damages, expenses, and liability arising from an action or failure to act, except when the same is finally judicially determined to be due to gross negligence or willful misconduct. The Affiliated Employers may purchase at its own expense sufficient liability insurance for the Administrative Committee to cover any and all claims, losses, damages, and expenses arising from any action or failure to act in connection with the execution of the duties as Administrative Committee. No member of the Administrative Committee who is also an Employee of an Affiliated Employer shall receive any compensation from the Plan for his services in administering the Plan.

ARTICLE IV -   ELIGIBILITY

4.1Eligibility Requirements. All Employees who are determined to be eligible to participate in the Plan in accordance with Section 4.2 shall be eligible to receive benefits under the Plan provided such Employees are (a) participating in the Plan at the time they terminate from an Affiliated Employer and are retirement eligible or (b) die while in active service while with an Affiliated Employer provided each such Employee’s beneficiary(ies) is eligible to receive a survivor benefit under Article V of the Pension Plan at such eligible Employee’s death.

4.2Determination of Eligibility. The Administrative Committee shall determine which Employees are eligible to participate. Upon becoming a Participant, an Employee shall be deemed to have assented to the Plan and to any amendments hereafter adopted. The Administrative Committee shall be authorized to rescind the eligibility of any Participant if necessary to ensure that the Plan is maintained primarily for the purpose of providing deferred compensation to a select group of management or highly compensated employees under the Employee Retirement Income Security Act of 1974, as amended. A Participant whose eligibility is rescinded or who loses eligibility for any reason shall not be eligible thereafter until eligibility is restored in accordance with guidelines established by the Administrative Committee.

If an Employee who was employed by Mirant Corporation (f/k/a Southern Energy, Inc.) (“Mirant”) or an affiliate thereof on or after April 2, 2001 is employed by an Affiliated Employer, he shall be treated as a new hire and none of his service with Mirant shall be considered as Accredited Service under Article III.

Notwithstanding the preceding terms in this Section 4.2, effective January 2, 2016, no new Participants may participate in the Plan including, but not limited to, former Employees

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who incurred a Separation from Service prior to January 2, 2016 with a vested SERP Benefit and who are rehired on or after January 2, 2016. For the avoidance of doubt, an Employee who first becomes eligible to participate in the Plan on January 1, 2016 shall become a Participant as of such date and shall remain a Participant for as long as such Employee continues to satisfy eligibility requirements under Article IV of the Plan.

ARTICLE V -   BENEFITS

5.1SERP Benefit.

(a)Subject to the terms of the Pension Plan, a Participant shall be entitled to a monthly SERP Benefit equal to:

(1) the greater of (A) or (B) below, if applicable:

(A) 1.70% of the Participant’s Average Monthly Earnings multiplied by his years (and fraction of a year) of Accredited Service to his Retirement Date, death, or other termination of service, including a Social Security Offset.

(B) 1.25% of the Participant’s Average Monthly Earnings multiplied by his years (and fraction of a year) of Accredited Service to his Retirement Date, death, or other termination of service.

reduced by such Participant’s Supplemental Pension Benefit before any offset attributable to the Pension Plan benefit as provided under the terms of the Supplemental Benefit Plan.

The benefit determined in this subsection (1) shall be adjusted, if necessary, under the terms of the Pension Plan for commencement prior to the Participant’s Normal Retirement Date. This adjustment shall be made before the reduction described above is subtracted from such benefit. For the avoidance of doubt, the SERP Benefit shall be determined at the time the Participant commences such SERP Benefit under Section 5.2 or 5.3, as the case may be, regardless of whether such Participant commences his Retirement Income at that time under the Pension Plan.

(b)Effective January 1, 2010, for purposes of Section 5.1(a)(1), the Participant’s Average Monthly Earnings shall be those considered under the Pension Plan in calculating his Retirement Income, but without regard to the limitation of Section 401(a)(17) of the Code, and including for purposes of Section 5.1(a)(1)(A) any Incentive Pay as of the applicable Plan Year in excess of 15% of the Participant’s corresponding base pay for the applicable Plan Year determined under this Section 5.1(b). The Plan in effect on and before December 31, 2009 sets forth the applicable version of this Section 5.2(b) utilized to determine a Participant’s SERP Benefit.

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(c)For purposes of Section 5.1(b) above, to determine the Plan Years which produce the highest monthly average to calculate Average Monthly Earnings under the Plan, a Participant’s Average Monthly Earnings should include those additional amounts provided therein.

5.2Distribution of Benefits.

(a)General Rule.

Subject to the transition rules set forth in Section 5.3, effective for Participants who have not commenced their SERP Benefit on or before March 1, 2007, the SERP Benefit, as determined in accordance with Section 5.1, shall be converted to a Single-Sum Amount and paid in ten (10) annual installments commencing in all events on or after January 1, 2008. The first installment shall be derived from the Single-Sum Amount plus Earnings, if any, divided by ten (10). Subsequent annual installments shall be an amount equal to the Participant’s unpaid Single-Sum Amount plus Earnings divided by the number of remaining annual payments.

(b)Payment of Installments after Retirement.

(1) Commencement of Installment Payments. With respect to a Participant who retires under the terms of the Pension Plan, the first annual installment shall be paid as of the first day of the second full calendar month following the Participant’s Separation from Service but not sooner than January 1, 2008. Notwithstanding the foregoing, if a Participant is a Key-Employee, such Participant shall be subject to the Key-Employee Delay and the first installment payment shall be as of the first day of the seventh full calendar month following the Participant’s Separation from Service.

(2) Subsequent Nine Installment Payments. One additional installment, until ten (10) are paid in total, shall be paid as of each anniversary of the date the initial payment was made. For a Participant who is a Key Employee, the anniversary date of the initial payment will be deemed to be the date the first payment would have been made had the Key-Employee Delay not applied. The second through the tenth installments will be paid on the anniversary of this deemed initial payment date.

(c)Death of Participant.

(1) Death After Retirement. If a retirement-eligible Participant dies after Separation from Service but before receiving all ten (10) installments, the remaining installment payments shall be paid to the Designated Beneficiary of the Participant at the same times and in the same amounts that the Participant would have received if the

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Participant had not died. Notwithstanding the foregoing, if a retired Key Employee dies during the Key-Employee Delay and before receiving the first installment, then the first installment shall be paid to the Designated Beneficiary as of the beginning of the second full calendar month following the death of the Participant or as soon as practical thereafter.

(2) Death Before Retirement. If a Participant dies on or after March 1, 2007 and prior to July 1, 2017, while actively employed and has a vested benefit in the Pension Plan, one-hundred percent (100%) of the Single-Sum Amount determined in accordance with Section 5.2(a) above shall be paid to the Participant’s Provisional Payee, if any, in ten (10) annual installments commencing in all events on or after January 1, 2008. Such installments shall be determined and payable as if the Participant survived to his fiftieth (50^th) birthday, or actual date of death if later, and Separated from Service. If such a Provisional Payee dies simultaneously with or after the Participant but before receipt of all installments, the remaining payments shall be paid to the Participant’s Designated Beneficiary.

If a Participant dies on or after July 1, 2017, while actively employed with a vested benefit in the Pension Plan, Section 5.2(e) shall apply to the payment of the SERP Benefit.

(d)FICA Tax Adjustment. A payment in addition to the ten (10) installments described in Section 5.2(a) shall be made from the remaining Single-Sum Amount which payment shall be based on the following adjustments as permitted under Code Section 409A and the regulations promulgated thereunder: (1) the amount necessary to pay the tax due under the Federal Insurance Contributions Act (“FICA”) with respect to the accrued SERP Benefit determined upon retirement (or such other appropriate “resolution date” as defined under Treasury Regulation Section 31.3121(v)(2)); and (2) the amount estimated to pay the Federal and State income tax withholding liability due on the amount paid in subsection (1) plus the Federal and State income tax withholding liability due on the amount paid in this subsection (2).

(e)Designated Beneficiary Death Benefit on and after July 1, 2017.

(1) If a Participant dies on or after July 1, 2017, while in active service and (i) he has elected his Spouse as his sole Designated Beneficiary, such Spouse shall receive 100% of the Single-Sum Amount, or (ii) he has elected a Designated Beneficiary(ies) which is not his Spouse, such Designated Beneficiary(ies) shall receive 50% of the Single-Sum Amount with an equal portion of such Single-Sum Amount payable to each such living Designated Beneficiary.

(2) The Single-Sum Amount described in Section 5.2(e)(1) above is payable to the Designated Beneficiary(ies) on the first of the month

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following the date of the Participant’s death. The benefit will be payable as soon as administratively feasible after the Designated Beneficiary(ies) have been confirmed and located.

(3) If a Participant dies while in active service and prior to age 50, the Single-Sum Amount described in Section 5.2(e)(1) above is calculated as (A) divided by (B) below:

(A) The Single-Sum Amount determined as if the Participant survived to his fiftieth (50^th) birthday and Separated from Service.

(B) The sum of one (1) plus the Discount Rate raised to a power equal to the number of years and months between the first of the second month following the Participant’s 50^th birthday and the first of the month following the Participant’s date of death.

With respect to Section 5.2(e)(1) above, for the avoidance of doubt, the Participant may either elect his Spouse as his sole Designated Beneficiary or may elect Designated Beneficiary(ies) none of which is the Spouse.

(4) A Participant that has Separated from Service, is retirement eligible and has at least one annual installment payment as provided in Section 5.2(b) of the Plan left to be paid, unpaid annual installments otherwise payable to the Participant (not to exceed on a collective basis a total of 10) shall be paid to the Participant’s Designated Beneficiary(ies) (which for the avoidance of doubt may be the Spouse and/or any other Beneficiary(ies)). If a Participant fails to elect a Designated Beneficiary(ies) on a form acceptable to the Retirement Board, the SERP Benefit under this Section 5.2(f) shall be paid to the default [Designated] Beneficiaries.

5.3Code Section 409A Transition Election and Other Related Rules.

(a)Election General Rules

At a time and in a manner prescribed by the Administrative Committee, Participants who are actively employed on March 1, 2007, shall be eligible to make an election to receive SERP Benefits in the form described in Section 5.2(a) or in the form described in Section 5.3(c) below. In the event a Participant designated in accordance with the preceding sentence fails to make such election for any reason, including but not limited to death, such Participant’s SERP Benefit shall be in the form described in Section 5.2(a).

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(b)Transitioning Participants Electing Installments.

The following provisions apply to Participants described in Section 5.3(a) who have elected the form of payment described in Section 5.2(a) or are deemed to have made such election.

(1) General Rules. The first installment payment shall commence as of January 1, 2008 or later and shall otherwise be paid in accordance with Section 5.2(b). If a Participant commences payment of SERP Benefits in conjunction with his benefit under the Pension Plan prior to January 1, 2008, such SERP Benefit shall be payable for the remainder of 2007 in monthly increments starting at the same time and payable in the same form elected by the Participant under the Pension Plan. With respect to a Participant subject to the preceding sentence, the Participant’s Single-Sum Amount shall be computed as of the first day of the second full calendar month following the Participant’s Separation from Service and shall be decreased by any monthly benefits actually paid to the Participant or a Provisional Payee and increased by Earnings. For the avoidance of doubt, a Participant subject to this Section 5.3(b)(1) whose SERP Benefit payments start prior to January 1, 2008 will receive his first installment on January 1, 2008, and subsequent installments will be paid as of the next nine anniversaries of that payment.

(2) Installment Payment Commencement for Key Employees. If a Participant to which Section 5.3(b) applies is a Key Employee, such Participant shall be subject to the Key-Employee Delay and the first installment payment made in accordance with Section 5.3(b)(1) shall be as of the first day of the seventh full calendar month following the Participant’s Separation from Service but in no event earlier than as of January 1, 2008. If such a Key Employee retires in 2007 and commences his SERP Benefit in conjunction with his benefit under the Pension Plan before 2008, such Key Employee’s SERP Benefit shall be paid in monthly increments starting at the same time and payable in the same form elected by the Participant under the Pension Plan until his first installment is paid in accordance with the preceding sentence. Under no circumstances are payments of SERP Benefits made in conjunction with the Pension Plan commencing in 2007 subject to the Key-Employee Delay. For the avoidance of doubt, a Participant subject to this Section 5.3(b)(2) whose SERP Benefit payments start prior to 2008 shall receive his first installment as of the later of January 1, 2008 or the first day of the calendar month following the applicable Key-Employee Delay; subsequent installments will be paid as of the first day of the next nine calendar years.

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(3) Death of Participant

(A) Death Before Retirement. The provisions of Section 5.2(c)(2) apply to a Participant described in this Section 5.3(b) who dies while actively employed. The Provisional Payee of such a Participant who dies prior to December 1, 2007 and could have commenced payments in 2007 shall receive prior to the first installment a survivor benefit in accordance with the form of benefit elected by the Participant or deemed elected under the Pension Plan as applicable. Thereafter, the Provisional Payee shall receive the installment payments the Participant would have received under Section 5.3(b)(1).

(B) Death After Retirement. The provisions of Section 5.2(c)(1) apply to a Participant described in this Section 5.3(b) who is retirement eligible and dies after Separation from Service. However, the Provisional Payee of any Participant who commences SERP Benefits in 2007 in conjunction with his benefit under the Pension Plan and who dies during 2007 prior to payment of his first installment shall receive prior to such first installment a survivor benefit in accordance with the form of benefit elected by the Participant or deemed elected under the Pension Plan as applicable. Thereafter, installment payments that the Participant would have received shall be paid to the Participant’s Designated Beneficiary.

(c)Transitioning Participants Electing Annuity Forms.

The following rules apply to Participants described in Section 5.3(a) who have elected the annuity form of payment. The election provided for in subparagraph (1) below shall be subject to the provisions of subparagraphs (2)-(5), as applicable.

(1) General Rule. If determined eligible to do so by the Administrative Committee at a time and in a manner determined by the Administrative Committee during 2007, such a Participant may elect to receive his SERP Benefit in the form of a single life annuity, 50% joint and survivor annuity, 100% joint and survivor annuity, 50% joint and survivor annuity with pop-up, or 100% joint and survivor annuity with pop-up (and with respect to SEPCO Employees those other forms available under the Pension Plan except any form coordinated with payment of Social Security benefits). In the event that such a Participant elects an annuity but fails to designate a form, such Participant shall be deemed to have designated a single life annuity. These annuity forms shall be as

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described in the Pension Plan and if a form other than a single life annuity is selected, the SERP Benefit payable will be adjusted as described in the Pension Plan. Payments shall commence as of the first day of the first full calendar month following the Participant’s Separation from Service.

The Participants who have elected the form of payment described in this Section 5.3(c) shall receive an additional payment equal to (A) and (B) below. Subsequent payments shall be adjusted as provided in subsection (C) below as permitted under Code Section 409A and the regulations promulgated thereunder.

(A) The amount necessary to pay the tax due under the Federal Insurance Contributions Act (FICA) with respect to the accrued SERP Benefit determined in accordance with the requirements under Treasury Regulation Section 31.3121(v)(2) upon retirement (or such other appropriate “resolution date” as defined under Treasury Regulation Section 31.3121(v)(2)) calculated in accordance with Section 5.1;

(B) The amount estimated to pay the Federal and State income tax withholding liability due on the amount paid under subsection (A) above plus the amount of Federal and State income tax withholding liability due on the amount paid under this subsection (B); and

(C) An adjusted monthly benefit determined in a manner and on an actuarially equivalent basis in accordance with the methodology and assumptions used to calculate the tax due under subsection (A) above which takes into account the amounts paid under subsections (A) and (B) above and the form of benefit elected by the Participant.

(2) Form of Annuity

(A) Pre-2008 Commencement. Notwithstanding Section 5.3(c)(1), if a Participant to which this Section 5.3(c) applies retires in 2007 and commences receipt of his SERP Benefit in conjunction with his benefit under the Pension Plan before January 1, 2008, the Participant’s SERP Benefit shall be payable only in the form elected under the Pension Plan and shall be calculated using the same annuity form of payment factors as provided for under the terms of the Pension Plan as in effect during 2007.

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(B) Post-2007 Commencement. A Participant described in the first full paragraph of Section 5.3(c)(1) who has not commenced payment of his SERP Benefit prior to 2008 may change the form of payment previously elected in Section 5.3(c)(1) to another permitted form described in that Section (plus may instead elect a 75% joint and survivor annuity or a 75% joint and survivor annuity with pop-up) at a time and in a manner prescribed by the Administrative Committee. If the form of payment is changed, the SERP Benefit payable pursuant to the original election will be actuarially adjusted using the Actuarial Basis to reflect the new form selected.

(3) Key Employee Rules. If a Participant to which this Section 5.3(c) applies is a Key Employee and the commencement date of his SERP Benefit is on or after January 1, 2008, such Participant will be subject to the Key-Employee Delay and shall receive a lump-sum payment as of the first day of the seventh full month following the Participant’s Separation from Service in an amount equal to six (6) monthly payments due to the Participant under the Plan, plus the monthly payment then due to the Participant for the seventh month. Thereafter, the appropriate monthly benefit shall be paid to the Key Employee and his Provisional Payee, if any. If such a Participant is a Key Employee and the commencement date of his SERP Benefit is before January 1, 2008, the SERP Benefit shall be paid in accordance with Section 5.3(c)(2)(A); the Key-Employee Delay will not apply. If a Key Employee dies during the Key-Employee Delay, the Designated Beneficiary shall receive any benefits that would have been paid if there were no Key-Employee Delay up to the date of death as of the first of the month following the Participant’s death or as soon as practicable thereafter. Interest shall not be added to such benefits. In addition, if such deceased Key Employee elected a form of payment providing for payment to continue to a Provisional Payee pursuant to Section 5.3(c)(1), subject to Section 5.3(c)(2), those payments will begin as of the first of the month following such Key Employee’s death or as soon as practicable thereafter.

(4) Death of Participant

(A) Death After Retirement. If a retirement-eligible Participant to which Section 5.3(c)(1) applies dies after Separation from Service, such Participant’s Provisional Payee, if any, shall receive monthly payments for the remainder of the Provisional Payee’s life based on the annuity form of payment the Participant elected or is deemed to have elected pursuant to Section 5.3(c)(1), subject to Section

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5.3(c)(2). Such Payments will commence as of the first of the month following such Participant’s death or as soon as practicable thereafter.

(B) Death Before Retirement. If a Participant to which Section 5.3(c) applies dies while actively employed and has a vested benefit in the Pension Plan, then Section 5.2(c)(2) shall apply.

(5) QPSA Charges Waived. Any benefit paid in accordance with this Section 5.3(c) shall be calculated without regard to the charge associated with any Qualified Pre-retirement Survivor Annuity form elected.

(d)Inactive Employee Transition Election

In the event a Participant has Separated from Service and is eligible to receive a SERP Benefit on or before March 1, 2007, but has deferred commencement until after March 1, 2007, and is eligible to receive a benefit under the Pension Plan on or before January 1, 2008, such Participant must make an election in accordance with Section 5.3(a) at a time and in a manner prescribed by the Administrative Committee and must commence payment by no later than January 1, 2008. The requirements of Section 5.3(b) or Section 5.3(c) (ignoring the fact that the Participant previously incurred a Separation from Service) apply as the case may be based on the Participant’s ultimate election under Section 5.3(a). If a Participant dies before making an election under this Section 5.3(a), SERP Benefit payments shall be made consistent with Section 5.3(b)(3)(B) if the Participant dies prior to making his election to commence his SERP Benefit in conjunction with the commencement of his benefit under the Pension Plan or shall be made consistent with Section 5.3(c)(4)(A) if made after making his election to commence his SERP Benefit in conjunction with the commencement of his benefit under the Pension Plan.

(e) Survivor Benefits in the case ofPre-effective Date Deaths. If a Participant died prior to March 1, 2007 while actively employed and had a vested benefit in the Pension Plan, the Provisional Payee, if any, shall receive the form of benefit provided under the Pension Plan commencing the first of the month following the date the Participant would have attained age 50.

5.4Allocation of SERP Benefit Liability. In the event that a Participant eligible to receive a SERP Benefit has been employed at more than one Affiliated Employer, the SERP Benefit liability shall be apportioned so that each such Affiliated Employer is obligated in accordance with Section this 5.4 to cover the percentage of the total SERP Benefit as determined below. Each Affiliated Employer’s share of the SERP Benefit liability shall be calculated by multiplying the SERP Benefit by a fraction where the numerator of such fraction is the base rate

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of pay, as defined by the Administrative Committee, received by the Participant at the respective Affiliated Employer on his date of termination of employment or transfer, as applicable, multiplied by the Accredited Service earned by the Participant at the respective Affiliated Employer and where the denominator of such fraction is the sum of all numerators calculated for each respective Affiliated Employer by which the Participant has been employed.

5.5Funding of Benefits. Except as expressly limited under the terms of the Trust, neither the Company nor any Affiliated Employer hereunder shall reserve or otherwise set aside funds for the payment of its obligations under the Plan. In any event, such obligations shall be paid or deemed to be paid solely from the general assets of the Affiliated Employers. Participants shall only have the status of general, unsecured creditors of the Affiliated Employers. Notwithstanding that a Participant shall be entitled to receive the balance of his SERP Benefit under the Plan, the assets from which such amount shall be paid shall at all times remain subject to the claims of the creditors of the Participant’s Affiliated Employer.

5.6Withholding. There shall be deducted as permitted under Code Section 409A and the regulations promulgated thereunder from Plan payments and, if necessary, from the payment of any SERP Benefit due under the Plan the amount of any tax required by any governmental authority to be withheld and paid over by the Company to such governmental authority for the account of the Participant or Designated Beneficiary entitled to such payment.

5.7Recourse Against Deferred Compensation Trust. In the event a Participant who is employed on or after January 1, 1999 with an “Employing Company” (as such term is defined in the Change in Control Benefits Protection Plan) disputes the calculation of his SERP Benefit, the Participant has recourse against the Company, the Affiliated Employer by which the Participant is or was employed, if different, the Plan, and the Trust for payment of benefits to the extent the Trust so provides.

5.8Change in Control. The provisions of the Change in Control Benefits Protection Plan are incorporated herein by reference to determine the occurrence of a change in control or preliminary change in control of Southern Company or an Employing Company, the benefits to be provided hereunder, and the funding of the Trust in the event of such a change in control. Any modifications to the Change in Control Benefits Protection Plan are likewise incorporated herein and are otherwise intended to comply with 409A of the Code.

ARTICLE VI -   MISCELLANEOUS

6.1Assignment. Neither the Participant, his Designated Beneficiary, nor his legal representative shall have any rights to sell, assign, transfer, or otherwise convey the right to receive the payment of any SERP Benefit due hereunder, which payment and the right thereto are expressly declared to be nonassignable and nontransferable. Any attempt to assign or transfer the right to payment under the Plan shall be null and void and of no effect.

6.2Amendment and Termination. Except for the provisions of Section 5.8 hereof, which may not be amended following a “Southern Change in Control” or “Subsidiary Change in Control” (as defined in the Change in Control Benefits Protection Plan), the Plan may be amended or terminated at any time by the Board of Directors, provided that no amendment or

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termination shall cause a forfeiture or reduction in any benefits accrued as of the date of such amendment or termination. The Plan may also be amended by the Administrative Committee (a) if such amendment does not involve a substantial increase in cost to any Affiliated Employer, or (b) as may be necessary, proper, or desirable in order to comply with laws or regulations enacted or promulgated by any federal or state governmental authority. During the compliance transition period provided for by the 409A Guidance, the Administrative Committee may enter into transition elections as to time and form of payment under this Plan and, subject to the preceding authority, shall be treated as amendments to the Plan.

6.3No Guarantee of Employment. Participation hereunder shall not be construed as creating any contract of employment between an Affiliated Employer and a Participant, nor shall it limit the right of an Affiliated Employer to suspend, terminate, alter, or modify, whether or not for cause, the employment relationship between the Affiliated Employer and a Participant.

6.4Construction. This Plan shall be construed in accordance with and governed by the laws of the State of Georgia, to the extent such laws are not otherwise superseded by the laws of the United States.

IN WITNESS WHEREOF, the amended and restated Plan has been executed by a duly authorized officer of Southern Company Services, Inc. pursuant to resolutions of the Board of Directors of Southern Company Services, Inc. this 29th day of June, 2016.

		SOUTHERN COMPANY SERVICES, INC.
		By:	/s/Stacy Kilcoyne
		Its:	Human Resources Vice President
Attest:
By:	/s/ Laura Oleck Hewett
Its:	Assistant Secretary

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APPENDIX ATHE SOUTHERN COMPANY SUPPLEMENTAL
EXECUTIVE RETIREMENT PLAN
AFFILIATED EMPLOYERS AS OF JANUARY 1, 2009

Alabama Power Company

Georgia Power Company

Gulf Power Company

Mississippi Power Company

Southern Communications Services, Inc.

Southern Company Energy Solutions, LLC

Southern Company Services, Inc.

Southern Nuclear Operating Company, Inc.

EX-10.A2

Exhibit 10(a)2

THE SOUTHERN COMPANY

SUPPLEMENTAL BENEFIT PLAN

Amended and Restated Effective as of June 30, 2016

THE SOUTHERN COMPANY

SUPPLEMENTAL BENEFIT PLAN

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ARTICLE I -		PURPOSE AND ADOPTION OF PLAN	1
	1.1	Adoption	1
	1.2	Purpose	2
	1.3	Schedule of Provisions for Pre-2005 Non-Pension Benefits	2
	1.4	409A Transition Elections	2
ARTICLE II -		DEFINITIONS	2
	2.1	Account	2
	2.2	Actuarial Basis	2
	2.3	Administrative Committee	2
	2.4	Board of Directors	2
	2.5	Change in Control Benefits Protection Plan	2
	2.6	Code	2
	2.7	Common Stock	3
	2.8	Company	3
	2.9	Deferred Compensation Plan	3
	2.10	Designated Beneficiary	3
	2.11	“Discount Rate	3
	2.12	Earnings	3
	2.13	Effective Date	4
	2.14	Employee	4
	2.15	Employing Company	4
	2.16	ESOP	4
	2.17	Expected Average Lifetime	4
	2.18	Fresh Start Method	4
	2.19	Fresh Start SCPP Offset	4
	2.20	Key Employee	4

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THE SOUTHERN COMPANY

SUPPLEMENTAL BENEFIT PLAN

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	2.21	Key-Employee Delay	4
	2.22	Modification Delay	4
	2.23	Non-Pension Benefit	4
	2.24	Participant	5
	2.25	Pension Benefit	5
	2.26	Pension Plan	5
	2.27	Phantom Common Stock	5
	2.28	Plan	5
	2.29	Plan Year	5
	2.30	Purchase Price	5
	2.31	Sales Price	5
	2.32	Savings Plan	5
	2.33	Separation from Service	5
	2.34	Single-Sum Amount	5
	2.35	Southern Board	6
	2.36	Southern Company	6
	2.37	Total Disability	6
	2.38	Trust	6
	2.39	Valuation Date	6
	2.40	Pre-2016 Benefit Formulas	6
	2.41	2016 Benefit Formula	6
	2.42	Pre-2016 Participant	6
	2.43	2016 Participant	6
ARTICLE III -		ADMINISTRATION OF PLAN	6
	3.1	Administrator	6
	3.2	Powers	7

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THE SOUTHERN COMPANY

SUPPLEMENTAL BENEFIT PLAN

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	3.3	Duties of the Administrative Committee	8
	3.4	Indemnification	8
ARTICLE IV -		ELIGIBILITY	9
	4.1	Eligibility Requirements	9
	4.2	Determination of Eligibility	10
ARTICLE V -		BENEFITS	10
	5.1	Pension Benefit	10
	5.2	Distribution of Pension Benefits	11
	5.3	Code Section 409A Transition Election and Other Related Rules Applicable to Pension Benefit	14
	5.4	Non-Pension Benefit	19
	5.5	Distribution of Non-Pension Benefits	20
	5.6	Allocation of Pension Benefit Liability	21
	5.7	Funding of Benefits	22
	5.8	Withholding	22
	5.9	Recourse Against Deferred Compensation Trust	22
	5.10	Change in Control	22
ARTICLE VI -		MISCELLANEOUS	22
	6.1	Assignment	22
	6.2	Amendment and Termination	23
	6.3	No Guarantee of Employment	23
	6.4	Mirant	23
	6.5	Construction	23
APPENDIX A		THE SOUTHERN COMPANY SUPPLEMENTAL BENEFIT PLAN     EMPLOYING COMPANIES AS OF JANUARY 1, 2009	1
APPENDIX B		November 16, 2009	1

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THE SOUTHERN COMPANY

SUPPLEMENTAL BENEFIT PLAN

ARTICLE 1 -   PURPOSE AND ADOPTION OF PLAN

1.1Adoption. The Southern Company Supplemental Benefit Plan, effective as of July 1, 2016 and hereinafter set forth (the “Plan”), is a modification and continuation of the Supplemental Benefit Plan for Southern Company Services, Inc. which originally became effective January 1, 1983, and was last amended and restated effective January 1, 2009. The purpose of this amendment and restatement is to incorporate the First and Second Amendments and to set forth changes to implement new design features. The January 1, 2009 amendment and restatement and the January 1, 2005 amendment and restatement are intended to bring the Plan into compliance with Code Section 409A. The Plan should be construed to satisfy this intent.

Effective January 1, 1998, the following other plans were merged into the Plan:

• Supplemental Benefit Plan for Alabama Power Company

• Supplemental Benefit Plan for Georgia Power Company

• Supplemental Benefit Plan for Gulf Power Company

• Supplemental Benefit Plan for Mississippi Power Company

• Supplemental Benefit Plan for Southern Company Services, Inc. and Southern Electric International, Inc., as adopted by Southern Communications Services, Inc.

• Supplemental Benefit Plan for Southern Company Services, Inc. and Southern Electric International, Inc., as adopted by Southern Development and Investment Group, Inc.

• Supplemental Benefit Plan for Southern Nuclear Operating Company, Inc.

Employees participating in the merged plans and employed by an Employing Company on January 1, 1998 became immediately covered under the Plan; provided, however, that the terms of the prior plans govern an Employee’s circumstances with regard to actions taken or occurring before January 1, 1998.

The Plan shall be an unfunded deferred compensation arrangement as contemplated by the Employee Retirement Income Security Act, as amended, under which benefits shall be paid solely from the general assets of the Employing Companies. At a time and in a manner determined by the Administrative Committee, Participants shall make timely elections to conform to the Plan’s terms effective as of the January 1, 2005 amendment and restatement. Such elections are intended to meet the transition requirements of Code Section 409A, including proposed, temporary, or final regulations, or other guidance issued by the Secretary of Treasury and the Internal Revenue Service with respect thereto (collectively “409A Guidance”).

1.2Purpose. The Plan is designed to provide certain retirement and other deferred compensation benefits primarily for a select group of management or highly compensated employees which are not otherwise payable or cannot otherwise be provided through contributions by the Employing Companies (1) under The Southern Company Pension Plan, The Southern Company Employee Savings Plan (“ESP”), and The Southern Company Employee Stock Ownership Plan (until its merger into the Savings Plan effective December 20, 2006), as a result of the limitations set forth under Sections 401(a)(17), 401(k), 401(m), 402(g), or 415 of the Internal Revenue Code of 1986, as amended from time to time.

1.3Schedule of Provisions for Pre-2005 Non-Pension Benefits. Attached to this Plan is a Schedule that sets forth the operative provisions of the Plan applicable to “grandfathered” Non-Pension Benefits which are treated by the Employing Companies as not subject to Section 409A of the Code. The Account balance (plus earnings thereon) of the grandfathered Non-Pension Benefits shall only be subject to the provisions set forth in the Schedule. In accordance with the 409A Guidance, these provisions are only intended to preserve the rights and features of the “grandfathered” Non-Pension Benefits and are, therefore, not intended to “materially modify” any aspect of such rights and features. Provisions of the Schedule should be so construed whenever necessary or appropriate. Provisions in the Schedule shall only be amended in accordance with the Schedule’s terms.

1.4409A Transition Elections. At a time and in a manner determined by the Administrative Committee, Participants shall make timely elections to conform to the Plan’s terms effective on and after January 1, 2005. Such elections are intended to meet the requirements of the 409A Guidance.

ARTICLE II -   DEFINITIONS

2.1“Account” shall mean the total amount credited to the account of a Participant to reflect the interest of a Participant in the Plan resulting from a Participant’s Non-Pension Benefit calculated in accordance with Section 5.4.

2.2“Actuarial Basis” shall mean an actuarial adjustment to Pension Benefits that must be made as required by Code Section 409A when there is a change made by a Participant to a previously elected or deemed-elected form of payment paid over a lifetime. Reasonable actuarial assumptions to make such adjustment shall be established in writing from time to time by the Administrative Committee.

2.3“Administrative Committee” shall mean the committee referred to in Section 3.1 hereof.

2.4“Board of Directors” shall mean the Board of Directors of the Company.

2.5“Change in Control Benefits Protection Plan” shall mean the Change in Control Benefits Protection Plan, as approved by the Southern Board, as it may be amended from time to time in accordance with the provisions therein.

2.6“Code” shall mean the Internal Revenue Code of 1986, as amended from time to time.

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2.7“Common Stock” shall mean common stock of Southern Company.

2.8“Company” shall mean Southern Company Services, Inc.

2.9“Deferred Compensation Plan” shall mean The Southern Company Deferred Compensation Plan, as amended from time to time.

2.10“Designated Beneficiary” shall mean the person(s) or entity(ies) identified by the Participant in a manner prescribed by the Administrative Committee as eligible to receive the Pension Benefit, the Non-Pension Benefit, or both. In the event no such designation is made by a Participant either as to the Pension Benefit, the Non-Pension Benefit, or both, or if such beneficiary shall not be living or in existence at the time for commencement or continuance of such payment under the Plan following the Participant’s death, such payment, solely as to the benefit for which no beneficiary was designated or living, shall be made to the person or persons in the first of the following classes of successive preference, if then living:

(a)the Participant’s spouse on the date of his death;

(b)the Participant’s legally recognized children, equally;

(c)the Participant’s parents, equally;

(d)the Participant’s brothers and sisters, equally; or

(e)the Participant’s executors or administrators.

Payment to such one or more persons shall completely discharge the Plan with respect to the amount so paid.

With respect to the Pension Benefit, for the period before a Participant commences payment under the Plan, the Participant may elect Designated Beneficiary(ies) but such election will expire upon the Participant’s election to commence payment of his Pension Benefit. In addition, during this pre-commencement period, if a Participant elects his Spouse as the Designated Beneficiary, then the Spouse must be the sole Designated Beneficiary. Upon a Participant’s election to commence payment of his Pension Benefit, the Participant must re-elect a Designated Beneficiary(ies) as part of such election. At this commencement election, if the Participant elects his Spouse as a Designated Beneficiary, in addition to such Spouse, other persons may also be elected as Designated Beneficiary(ies).

2.11 “Discount Rate” shall mean the thirty (30) year Treasury yield as published by the Department of Treasury for purposes of compliance with Code Section 417(e) determined for September of the calendar year prior to the calendar year in which a Participant Separates from Service provided that the maximum rate shall not exceed six percent (6%).

2.12“Earnings” shall mean the total accumulated interest on a Participant’s Single-Sum Amount. Unless otherwise stated, Earnings accrue from the date as of which a Participant’s first installment is payable (ignoring for this purpose any Key-Employee Delay) until all of the Participant’s Single-Sum Amount (and monthly interest accretion thereon) has been paid.

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Interest shall compound monthly based on the rate of interest accretion for each month and the unpaid portion of a Participant’s Single-Sum Amount (including any unpaid portion of any prior month’s interest accretion). The rate of such interest accretion for a month shall be the monthly equivalent of the per annum prime rate of interest published in the Wall Street Journal as the base rate on the corporate loans posted as of the last business day of each month by at least seventy-five percent (75%) of the United States largest banks as of the last business day of the month (or such other day of a month as the Administrative Committee may determine).

2.13“Effective Date” of this amendment and restatement shall mean June 30, 2016.

2.14“Employee” shall mean any person who is currently employed by an Employing Company.

2.15“Employing Company” shall mean the Company and any affiliate or subsidiary of Southern Company which the Board of Directors may from time to time determine to bring under the Plan and any successor to them. The Employing Companies are set forth in Appendix A to the Plan, as amended from time to time.

2.16“ESOP” shall mean The Southern Company Employee Stock Ownership Plan, as amended from time to time until it merged into the Savings Plan effective December 20, 2006.

2.17“Expected Average Lifetime” shall mean the life expectancy of a Participant in months using the Table of Unisex Mortality Rates promulgated by the Internal Revenue Service for use to determine lump-sum payments from qualified pension plans in accordance with Code Section 417(e) as of the 2007 calendar year.

2.18“Fresh Start Method” shall have the meaning set forth in Section 4.1(b)(2)(B)(i) of the Plan and is based on the Participant’s status as either a Pre-2016 Participant or a 2016 Participant.

2.19“Fresh Start SCPP Offset” shall have the meaning set forth in Section 4.1(b)(2)(B)(iii) of the Plan and is based on the Participant’s status as either a Pre-2016 Participant or a 2016 Participant.

2.20“Key Employee” shall have the meaning ascribed to the term “specified employee” under Code Section 409A(a)(2)(B)(i) and the regulations promulgated thereunder as it applies to a Participant. The Administrative Committee shall establish the time period required to determine key-employee status.

2.21“Key-Employee Delay” shall mean the six (6) month delay in the commencement of benefits applicable to Key Employees pursuant to the requirements of Code Section 409A(a)(2)(B)(i) and the regulations promulgated thereunder.

2.22“Modification Delay” shall mean the requirements permitting a change in time or form of payment as allowed under Code Section 409A(a)(4)(C) and the regulations promulgated thereunder.

2.23“Non-Pension Benefit” shall mean the benefit described in Section 5.4.

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2.24“Participant” shall mean an Employee or former Employee of an Employing Company who is eligible and participates in the Plan pursuant to Sections 4.1 and 4.2 and is either a Pre-2016 Participant or a 2016 Participant..

2.25“Pension Benefit” shall mean the benefit described in Section 5.1 for a given Participant and as the context requires is based on either the Pre-2016 Benefit Formulas or the 2016 Benefit Formula.

2.26“Pension Plan” shall mean The Southern Company Pension Plan, as amended from time to time.

2.27“Phantom Common Stock” shall mean the Common Stock in which a Participant is deemed to invest his Non-Pension Benefit as if such Common Stock had been purchased upon contribution to the Savings Plan and/or the ESOP, as the case may be.

2.28“Plan” shall mean The Southern Company Supplemental Benefit Plan, as amended and restated as of June 30, 2016 and as may be amended from time to time thereafter.

2.29“Plan Year” shall mean the calendar year.

2.30“Purchase Price” shall mean for purposes of deemed purchases of Phantom Common Stock the following: (a) with respect to the Savings Plan, the purchase price of a share of the Common Stock under the Savings Plan as of the applicable Valuation Date; (b) with respect to any investment of dividends attributable to Phantom Common Stock in either the Savings Plan or the ESOP, the dividend reinvestment price of a share of the Common Stock under the Savings Plan as of the applicable Valuation Date; and (c) with respect to the ESOP, the price at which a share of Common Stock is purchased with regard to a contribution made for each applicable Plan Year.

2.31“Sales Price” shall mean the closing price on any trading day of a share of Common Stock based on consolidated trading as defined by the Consolidated Tape Association and reported as part of the consolidated trading prices of New York Stock Exchange listed securities.

2.32“Savings Plan” shall mean The Southern Company Employee Savings Plan, as amended from time to time.

2.33“Separation from Service” shall have the meaning ascribed to this term under Code Section 409A(a)(2)(A)(i) and the regulations promulgated thereunder. For this purpose, Separation from Service shall include a permanent decrease in the level of bona fide services performed by the Participant after a certain date to a level that is twenty percent (20%) or less of the average level of bona fide services performed by the Participant over the immediately preceding thirty-six (36) month period.

2.34“Single-Sum Amount” shall mean the discounted value of the Pension Benefit based on a single life annuity form of benefit payable for an Expected Average Lifetime calculated using the Discount Rate. This Single-Sum Amount calculation shall be determined effective as of the first installment to be made under Section 5.2 (ignoring for this purposes any

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Key-Employee Delay) taking into account the following: (a) reductions for charges related to any Qualified Pre-retirement Survivor Annuity form of benefit under the Pension Plan shall not apply; and (b) the Pension Benefit and Expected Average Lifetime shall be based on the Participant’s age as of such first installment date.

2.35“Southern Board” shall mean the board of directors of Southern Company.

2.36“Southern Company” shall mean Southern Company, its successors and assigns.

2.37“Total Disability” shall mean a total disability as determined by the Social Security Administration and meeting the requirements of Code Section 409A(a)(2) and the regulations promulgated thereunder.

2.38“Trust” shall mean the Southern Company Deferred Compensation Trust.

2.39“Valuation Date” shall mean each trading day of the New York Stock Exchange, or any successor national exchange on which the Common Stock is traded and with respect to which a Sales Price may be determined.

2.40“Pre-2016 Benefit Formulas” shall have the meaning in effect under the Pension Plan prior to January 1, 2016.

2.41“2016 Benefit Formula” shall have the meaning in effect under the Pension Plan on and after January 1, 2016.

2.42“Pre-2016 Participant” shall mean a Participant accruing a Pension Benefit under this Plan and Retirement Income under the Pension Plan under the Pre-2016 Benefit Formulas.

2.43“2016 Participant” shall mean a Participant accruing a Pension Benefit under this Plan and Retirement Income under the Pension Plan under the 2016 Benefit Formula

Where the context requires, the definitions of all terms set forth in the Pension Plan, the ESOP, the Savings Plan, and the Deferred Compensation Plan shall apply with equal force and effect for purposes of interpretation and administration of the Plan, unless said terms are otherwise specifically defined in the Plan. The masculine pronoun shall be construed to include the feminine pronoun and the singular shall include the plural, where the context so requires.

ARTICLE III -   ADMINISTRATION OF PLAN

3.1Administrator. Effective May 31, 2007, the general administration of the Plan shall be placed in the “Committee” which shall consist of the Benefits Administration Committee, the members of which shall be appointed from time to time by the Fiduciary Oversight Committee of the Board of Directors. The Committee shall govern itself in accordance with the terms of the Charter for the Benefits Administration Committee approved by the Fiduciary Oversight Committee of the Board of Directors.

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3.2Powers.

(a)The Administrative Committee shall administer the Plan in accordance with its terms and shall have all powers necessary to carry out the provisions of the Plan more particularly set forth herein. It shall have the discretion to interpret the Plan and shall determine all questions arising in the administration, interpretation, and application of the Plan. Any such determination by it shall be conclusive and binding on all persons. The Administrative Committee shall be the agent for the service of process.

(b)If a claim for benefits under the Plan is denied, in whole or in part, the Administrative Committee will provide a written notice of the denial within a reasonable period of time, but not later than 90 days after the claim is received. If special circumstances require more time to process the claim, the Administrative Committee will issue a written explanation of the special circumstances prior to the end of the 90-day period and a decision will be made as soon as possible, but not later than 180 days after the claim is received.

The written notice of claim denial will include:

• Specific reasons why the claim was denied;

• Specific references to applicable provisions of the Plan document or other relevant records or papers on which the denial is based, and information about where a Participant or his or her Designated Beneficiary may see them;

• A description of any additional material or information needed to process the claim and an explanation of why such material or information is necessary;

• An explanation of the claims review procedure, including the time limits applicable to such procedure, as well as a statement notifying the Participant or his or her Designated Beneficiary of their right to file suit if the claim for benefits is denied, in whole or in part, on review.

Upon request, a Participant or his or her Designated Beneficiary will be provided without charge, reasonable access to, and copies of, all non-confidential documents that are relevant to any denial of benefits. A claimant has 60 days from the day he or she receives the original denial to request a review. Such request must be made in writing and sent to the Administrative Committee. The request should state the reasons why the claim should be reviewed and may also include evidence or documentation to support the claimant’s position.

The Administrative Committee will reconsider the claimant’s claim, taking into account all evidence, documentation, and other information related to the claim and submitted on the claimant’s behalf, regardless of whether such information was submitted or considered in the initial denial of the claim. The Administrative Committee will make a decision within 60 days. If special circumstances require more time for this process, the claimant will receive written explanation of the special circumstances prior to the end of the initial 60-day period and a

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decision will be sent as soon as possible, but not later than 120 days after the Administrative Committee receives the request.

No legal action to receiver benefits or enforce or clarify rights under a Plan can be commenced until the Participant or his or her Designated Beneficiary has first exhausted the claims and review procedures provided under the Plan.

(c)The Administrative Committee may adopt such regulations as it deems desirable for the conduct of its affairs. It may appoint such accountants, counsel, actuaries, specialists, and other persons as it deems necessary or desirable in connection with the administration of this Plan.

3.3Duties of the Administrative Committee.

(a)The Administrative Committee is responsible for the daily administration of the Plan. It may appoint other persons or entities to perform any of its fiduciary functions. The Administrative Committee and any such appointee may employ advisors and other persons necessary or convenient to help it carry out its duties, including its fiduciary duties. The Administrative Committee shall have the right to remove any such appointee from his position. Any person, group of persons, or entity may serve in more than one fiduciary capacity.

(b)The Administrative Committee shall maintain accurate and detailed records and accounts of Participants and of their rights under the Plan and of all receipts, disbursements, transfers, and other transactions concerning the Plan. Such accounts, books, and records relating thereto shall be open at all reasonable times to inspection and audit by persons designated by the Administrative Committee.

(c)The Administrative Committee shall take all steps necessary to ensure that the Plan complies with the law at all times. These steps shall include such items as the preparation and filing of all documents and forms required by any governmental agency; maintaining of adequate Participants’ records; recording and transmission of all notices required to be given to Participants and their Designated Beneficiaries; the receipt and dissemination, if required, of all reports and information received from an Employing Company; securing of such fidelity bonds as may be required by law; and doing such other acts necessary for the proper administration of the Plan. The Administrative Committee shall keep a record of all of its proceedings and acts, and shall keep all such books of account, records, and other data as may be necessary for proper administration of the Plan.

3.4Indemnification. The Employing Companies shall indemnify the Administrative Committee against any and all claims, losses, damages, expenses, and liability arising from an action or failure to act, except when the same is finally judicially determined to be due to gross negligence or willful misconduct. The Employing Companies may purchase at their own expense sufficient liability insurance for the Administrative Committee to cover any and all claims, losses, damages, and expenses arising from any action or failure to act in connection with the execution of the duties as Administrative Committee. No member of the Administrative Committee who is also an Employee of the Employing Companies shall receive any compensation from the Plan for his services in administering the Plan.

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ARTICLE IV -   ELIGIBILITY

4.1Eligibility Requirements.

(a)All Employees who are determined eligible to participate in accordance with Section 4.2 and who meet one or more of the following criteria shall be eligible to receive benefits under the Plan: (1) subject to Section 4.1(b) below, those whose benefits under the Pension Plan are limited by the limitations set forth in Code Sections 401(a)(17), 415 or 401(a)(4), (2) those whose matching contribution by their Employing Company to the Savings Plan are limited by limitations set forth in Code Sections 401(a)(17), 401(k), 401(m), 402(g) or 415, or (3) those whose contributions by their Employing Company to the ESOP (until its merger into the Savings Plan effective December 20, 2006) are limited by the limitations set forth in code Sections 401(a)(17) or 415.

(b)(1) Effective January 2, 2017, Employees who are 2016 Participants and become eligible to participate in the Plan pursuant to Section 4.2 shall be eligible to receive a Pension Benefit solely based on the 2016 Benefit Formula. Subject to Section 4.1(b)(2) below, all other Employees who are Pre-2016 Participants and become eligible to participate in the Plan pursuant to Section 4.2 shall receive a Pension Benefit based on the Pre-2016 Benefit Formulas including certain Participants who first enter the Plan as of January 1, 2017.

(2)Notwithstanding Section 4.1(b)(1) above, re-hired former Employees shall have the following rights to a Pension Benefit under the Plan:

(A)If a current or former Employee waives participation in the Pension Plan, such waiver will also preclude participation in this Plan.

(B)Subject to Section 5.2(g), a former Employee who is re-hired and becomes a Participant in the Plan shall be eligible to accrue a new and separate Pension Benefit whether or not such Employee previously had a vested right to a Pension Benefit based on the following terms:

(i)only “earnings” as defined in Section 5.1(b) and Accredited Service earned after the Employee is re-hired shall be taken into account when calculating such re-hired Employee’s new and separate Pension Benefit (“Fresh Start Method”).

(ii)the Pension Benefit accrued under Subsection (B)(i) above shall be payable in the form required by the Plan irrespective of how any prior accrued Pension Benefit is being or will be paid to the Participant; and

(iii)with respect to the Retirement Income that is paid or is payable under the terms of the Pension Plan which is taken into account as an offset to the Pension Benefit payable under Article V of this Plan, only the “earnings” as defined in Section 5.1(b) and Accredited Service earned pursuant to Subsection (B)(i) above shall be used to calculate the Retirement Income offset amount to be factored in when such re-hired

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Employee subsequently Separates from Service with a new and separate accrued Pension Benefit (“Fresh Start SCPP Offset”).

(c)Notwithstanding Subsection (b)(2)(B) above, a former Employee who received a cash out of his/her vested Pension Benefit upon a previous Separation from Service and who was subsequently re-hired and became a Participant prior to January 1, 2016 and also became a participant in the Southern Company Supplemental Executive Retirement Plan (“SERP”) prior to January 1, 2016, and who is eligible for a benefit from the SERP upon subsequent Separation from Service, shall have his/her new and separate accrued Pension Benefit determined by the “Aggregate Method with Offset” which is defined to mean the greater of (i) the Pension Benefit based on Accredited Service and “earnings” as defined in Section 5.1(b) of the Plan earned before the initial Separation from Service, plus the Pension Benefit based on Accredited Service and “earnings” as defined in Section 5.1(b) of the Plan earned pursuant to Subsection (B)(i) above, minus the Pension Benefit already received in the cash out payment, or (ii) the Pension Benefit based on all Accredited Service and “earnings” as defined in Section 5.1(b) under the Pension Plan, minus the Pension Benefit already received in the cash out payment.

4.2Determination of Eligibility. The Administrative Committee shall determine which Employees are eligible to participate. Upon becoming a Participant, an Employee shall be deemed to have assented to the Plan and to any amendments hereafter adopted. The Administrative Committee shall be authorized to rescind the eligibility of any Participant if necessary to ensure that the Plan is maintained primarily for the purpose of providing deferred compensation to a select group of management or highly compensated employees under the Employee Retirement Income Security Act of 1974, as amended. In addition, a Participant shall not be eligible for a Pension Benefit under the Plan unless such Participant shall be entitled to a vested benefit under the Pension Plan. If an Employee who was employed by Mirant Corporation (f/k/a Southern Energy, Inc.) (“Mirant”) or an affiliate thereof on or after April 2, 2001 is thereafter employed by an Employing Company, he shall be treated the same as a new hire and none of his service with Mirant shall be considered as Accredited Service under Section 5.1.

ARTICLE V -   BENEFITS

5.1Pension Benefit.

(a)Each Pre-2016 Participant and 2016 Participant shall be entitled to a Pension Benefit calculated under either the Pre-2016 Benefit Formulas or the 2016 Benefit Formula, as applicable, equal to that portion of the Retirement Income under the Pension Plan which is not payable under the Pension Plan as a result of the limitations imposed by Code Sections 401(a)(17) and 415(b). The Pension Benefit shall be determined when the Participant commences such Pension Benefit in accordance with Section 5.2 or 5.3, as the case may be, taking into account the Retirement Income then payable under the Pension Plan regardless of whether the Participant commences his Retirement Income at that time under the Pension Plan. For a rehire on or after January 2, 2017, the Retirement Income used to calculate the Pension Benefit should be determined in accordance with Section 5.2(g).

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(b)For purposes of this Section 5.1, the Pension Benefit of a Participant shall be calculated based on the Participant’s “earnings” that are defined under the Pension Plan, as modified below, without regard to the limitations of Section 401(a)(17) of the Code. For purposes of determining such “earnings,” all incentive pay earned while he is an Employee under any annual group incentive plans, as defined in Section 4.2 of the Pension Plan, shall be considered, provided such incentive award was earned on or after January 1, 1994. However, incentive pay shall only be included in a Pre-2016 Participant’s “earnings” for purposes of calculating such Pre-2016 Participant’s Pension Benefit using the 1.25% formula described in Section 4.2 of the Pension Plan.

5.2Distribution of Pension Benefits.

(a)General Rule.

Subject to the transition rules set forth in Section 5.3, effective for Participants who have not commenced their Pension Benefit on or before March 1, 2007, the Pension Benefit, as determined in accordance with Section 5.1, shall be converted to a Single-Sum Amount and paid in ten (10) annual installments commencing in all events on or after January 1, 2008. The first installment shall be derived from the Single-Sum Amount plus Earnings, if any, divided by ten (10). Subsequent annual installments shall be an amount equal to the Participant’s unpaid Single-Sum Amount plus Earnings divided by the number of remaining annual payments.

(b)Payment of Installments after Retirement.

(1)Commencement of Installment Payments. With respect to a Participant who retires under the terms of the Pension Plan, the first annual installment shall be paid as of the first day of the second full calendar month following the Participant’s Separation from Service but not sooner than January 1, 2008. Notwithstanding the foregoing, if a Participant is a Key-Employee, such Participant shall be subject to the Key-Employee Delay and the first installment payment shall be as of the first day of the seventh full calendar month following the Participant’s Separation from Service.

(2)Subsequent Nine Installment Payments. One additional installment, until ten (10) are paid in total, shall be paid as of each anniversary of the date the initial payment was made. For a Participant who is a Key Employee, the anniversary date of the initial payment will be deemed to be the date the first payment would have been made had the Key-Employee Delay not applied. The second through the tenth installments will be paid on the anniversary of this deemed initial payment date.

(c)Death of Participant.

(1)Death After Retirement. If a retirement-eligible Participant dies after Separation from Service but before receiving all ten (10) installments, the remaining installment payments shall be paid to the Designated Beneficiary of the Participant at the same times and in the same amounts that the Participant would have received if the Participant had not died. Notwithstanding the foregoing, if a retired Key Employee dies during the Key-Employee Delay and before receiving the first installment, then the first

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installment shall be paid to the Designated Beneficiary as of the beginning of the second full calendar month following the death of the Participant or as soon as practical thereafter.

(2)Death Before Retirement. If a Participant dies on or after March 1, 2007 and prior to July 1, 2017, while actively employed and has a vested benefit in the Pension Plan, one-hundred percent (100%) of the Single-Sum Amount determined in accordance with Section 5.2(a) above shall be paid to the Participant’s Provisional Payee, if any, in ten (10) annual installments commencing in all events on or after January 1, 2008. Such installments shall be determined and payable as if the Participant survived to his fiftieth (50^th) birthday, or actual date of death if later, and Separated from Service. If such a Provisional Payee dies simultaneously with or after the Participant but before receipt of all installments, the remaining payments shall be paid to the Participant’s Designated Beneficiary.

If a Participant dies on or after July 1, 2017, with a vested benefit in the Pension Plan, refer to Section 5.2(f).

(d)FICA Tax Adjustment. A payment in addition to the ten (10) installments described in Section 5.2(a) shall be made from the remaining Single-Sum Amount which payment shall be based on the following adjustments as permitted under Code Section 409A and the regulations promulgated thereunder: (1) the amount necessary to pay the tax due under the Federal Insurance Contributions Act (“FICA”) with respect to the accrued Pension Benefit determined upon retirement (or such other appropriate “resolution date” as defined under Treasury Regulation Section 31.3121(v)(2)); and (2) the amount estimated to pay the Federal and State income tax withholding liability due on the amount paid in subsection (1) plus the Federal and State income tax withholding liability due on the amount paid in this subsection (2).

(e)Participants Who Terminate with Vested Benefits.

(1)General Rule. With respect to a Participant who Separates from Service on or after March 1, 2007, who is not eligible to retire under Article III of the Pension Plan, but who is vested in his Retirement Income under Section 8.1 of the Pension Plan, notwithstanding anything to the contrary, such Participant shall receive a Pension Benefit in the form of a single payment made as of September 1 of the calendar year following the calendar year of termination from employment equal to (A) divided by (B) below:

(A)The Single-Sum Amount determined as if the Participant’s first installment date was to be coincident with his Normal Retirement Date.

(B)The sum of one (1) plus the Discount Rate raised to a power equal to the number of years and months between the Participant’s Normal Retirement Date and the September 1 of the calendar year following the calendar year of termination from employment.

For the avoidance of doubt, the Discount Rate used for this calculation is to be the Discount Rate applicable for the calendar year the Participant Separates from Service.

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(2)Death Benefits. With respect to a Participant to which this Section 5.2(e) applies, if such a Participant dies after Separation from Service but prior to payment in accordance with Section 5.2(e)(1) above and prior to July 1, 2017, the Provisional Payee, if any, shall receive the single payment provided in Section 5.2(e)(1) above at the same time the Participant would have received such payment if he had not died.

If such a Participant dies on or after July 1, 2017, refer to Section 5.2(f).

(f)Designated Beneficiary Death Benefit on and after July 1, 2017.

(1)If a Participant dies on or after July 1, 2017, while in active service or after Separation from Service with a vested Pension Benefit in this Plan, and

(A)if such Participant is a Pre-2016 Participant, and (i) he has elected his Spouse as his sole Designated Beneficiary, such Spouse shall receive 100% of the Single-Sum Amount, or (ii) he has elected a Designated Beneficiary(ies) which is not his Spouse, such Designated Beneficiary(ies) shall receive 50% of the Single-Sum Amount with an equal portion of such Single-Sum Amount payable to each such living Designated Beneficiary, or

(B)if such Participant is a 2016 Participant, the Designated Beneficiary(ies) (whether or not the Spouse) shall receive 50% of the Single-Sum Amount with an equal portion of such Single-Sum Amount payable to each such living Designated Beneficiary.

(2)The Single-Sum Amount described in Section 5.2(f)(1) above is payable to the Designated Beneficiary(ies) on the first of the month following the date of the Pre-2016 Participant’s or the 2016 Participant’s death. The benefit will be payable as soon as administratively feasible after the Designated Beneficiary(ies) have been confirmed and located.

(3)If a Pre-2016 Participant or a 2016 Participant dies while in active service and prior to age 50, the Single-Sum Amount described in Section 5.2(f)(1) above is calculated as (A) divided by (B) below:

(A)The Single-Sum Amount determined as if the Participant survived to his fiftieth (50^th) birthday and Separated from Service.

(B)The sum of one (1) plus the Discount Rate raised to a power equal to the number of years and months between the first of the second month following the Participant’s 50^th birthday and the first of the month following the Participant’s date of death.

(4)If a Pre-2016 Participant or a 2016 Participant dies after Separation from Service but prior to payment in accordance with Section 5.2(e)(1) above, the Single-Sum Amount described in Section 5.2(f)(1) above is calculated as (A) divided by (B) below:

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(A)The Single-Sum Amount determined as if the Participant’s first installment date was to be coincident with his Normal Retirement Date

(B)The sum of one (1) plus the Discount Rate raised to a power equal to the number of years and months between the Participant’s Normal Retirement Date and the first of the month following the Participant’s date of death.

With respect to Section 5.2(f)(1) above, for the avoidance of doubt, the Participant may either elect his Spouse as his sole Designated Beneficiary or may elect Designated Beneficiary(ies) none of which is the Spouse.

(5)A Participant that has Separated from Service, is retirement eligible and has at least one annual installment payment as provided in Section 5.2(b) of the Plan left to be paid, unpaid annual installments otherwise payable to the Participant (not to exceed on a collective basis a total of 10) shall be paid to the Participant’s Designated Beneficiary(ies) (which for the avoidance of doubt may be the Spouse and/or any other Beneficiary(ies)). If a Participant fails to elect a Designated Beneficiary(ies) on a form acceptable to the Retirement Board, the Pension Benefit under this Section 5.2(f) shall be paid to the default Beneficiaries described in Section 2.10.

(g)Treatment of Re-hired Employees on and after January 2, 2017.

(1)A Participant that is rehired and whose benefit is either suspended under the Pension Plan or has not commenced being paid his Retirement Income under the Pension Plan will have his Pension Benefit calculated (A) using the “Fresh Start Method” with “Fresh Start SCPP Offset” and (B) in accordance with the Participant’s status as either a Pre-2016 Participant or a 2016 Participant.

(2)A Participant that is rehired by an Employing Company and previously received his entire Retirement Income in the Pension Plan in the form of a lump sum distribution shall have his Pension Benefit calculated (A) using the “Fresh Start Method” and (B) in accordance with the Participant’s status as either a Pre-2016 Participant or a 2016 Participant.

5.3Code Section 409A Transition Election and Other Related Rules Applicable to Pension Benefit.

(a)Election General Rules.

At a time and in a manner prescribed by the Administrative Committee, Participants who are actively employed on March 1, 2007, shall be eligible to make an election to receive Pension Benefits in the form described in Section 5.2(a) or in the form described in Section 5.3(c) below. In the event a Participant designated in accordance with the preceding sentence fails to make such election for any reason, including but not limited to death, such Participant’s Pension Benefit shall be in the form described in Section 5.2(a).

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(b)Transitioning Participants Electing Installments. The following provisions apply to Participants described in Section 5.3(a) who have elected the form of payment described in Section 5.2(a) or are deemed to have made such election.

(1)General Rules. The first installment payment shall commence as of January 1, 2008 or later and shall otherwise be paid in accordance with Section 5.2(b). If a Participant commences payment of Pension Benefits in conjunction with his benefit under the Pension Plan prior to January 1, 2008, such Pension Benefit shall be payable for the remainder of 2007 in monthly increments starting at the same time and payable in the same form elected by the Participant under the Pension Plan. With respect to a Participant subject to the preceding sentence, the Participant’s Single-Sum Amount shall be computed as of the first day of the second full calendar month following the Participant’s Separation from Service and shall be decreased by any monthly benefits actually paid to the Participant or a Provisional Payee and increased by Earnings. For the avoidance of doubt, a Participant subject to this Section 5.3(b)(1) whose Pension Benefit payments start prior to January 1, 2008, will receive his first installment on January 1, 2008 and subsequent installments will be paid as of the next nine anniversaries of that payment.

(2)Installment Payment Commencement for Key Employees. If a Participant to which Section 5.3(b) applies is a Key Employee, such Participant shall be subject to the Key-Employee Delay and the first installment payment made in accordance with Section 5.3(b)(1) shall be as of the first day of the seventh full calendar month following the Participant’s Separation from Service but in no event earlier than as of January 1, 2008. If such a Key Employee retires in 2007 and commences his Pension Benefit in conjunction with his benefit under the Pension Plan before 2008, such Key Employee’s Pension Benefit shall be paid in monthly increments starting at the same time and payable in the same form elected by the Participant under the Pension Plan until his first installment is paid in accordance with the preceding sentence. Under no circumstances are payments of Pension Benefits made in conjunction with the Pension Plan commencing in 2007 subject to the Key-Employee Delay. For the avoidance of doubt, a Participant subject to this Section 5.3(b)(2) whose Pension Benefit payments start prior to 2008 shall receive his first installment as of the later of January 1, 2008 or the first day of the calendar month following the applicable Key-Employee Delay; subsequent installments will be paid as of the first day of the next nine calendar years.

(3)Death of Participant.

(A)Death Before Retirement. The provisions of Section 5.2(c)(2) apply to a Participant described in this Section 5.3(b) who dies while actively employed. The Provisional Payee of such a Participant who dies prior to December 1, 2007 and could have commenced payments in 2007 shall receive prior to the first installment a survivor benefit in accordance with the form of benefit elected by the Participant or deemed elected under the Pension Plan as applicable. Thereafter, the Provisional Payee shall receive the installment payments the Participant would have received under Section 5.3(b)(1).

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(B)Death After Retirement. The provisions of Section 5.2(c)(1) apply to a Participant described in this Section 5.3(b) who is retirement eligible and dies after Separation from Service. However, the Provisional Payee of any Participant who commences Pension Benefits in 2007 in conjunction with his benefit under the Pension Plan and who dies during 2007 prior to payment of his first installment shall receive prior to such first installment a survivor benefit in accordance with the form of benefit elected by the Participant or deemed elected under the Pension Plan as applicable. Thereafter, installment payments that the Participant would have received shall be paid to the Participant’s Designated Beneficiary.

(c)Transitioning Participants Electing Annuity Forms. The following rules apply to Participants described in Section 5.3(a) who have elected the annuity form of payment. The election provided for in subparagraph (1) below shall be subject to the provisions of subparagraphs (2)-(5), as applicable.

(1)General Rule. If determined eligible to do so by the Administrative Committee, at a time and in a manner determined by the Administrative Committee during 2007, such a Participant may elect to receive his Pension Benefit in the form of a single life annuity, 50% joint and survivor annuity, 100% joint and survivor annuity, 50% joint and survivor annuity with pop-up, or 100% joint and survivor annuity with pop-up (and with respect to SEPCO Employees those other forms available under the Pension Plan except any form coordinated with payment of Social Security benefits). In the event that such a Participant elects an annuity but fails to designate a form, such Participant shall be deemed to have designated a single life annuity. These annuity forms shall be as described in the Pension Plan and if a form other than a single life annuity is selected, the Pension Benefit payable will be adjusted as described in the Pension Plan. Payments shall commence as of the first day of the first full calendar month following the Participant’s Separation from Service.

The Participants who have elected the form of payment described in this Section 5.3(c) shall receive an additional payment equal to (A) and (B) below. Subsequent payments shall be adjusted as provided in subsection (C) below as permitted under Code Section 409A and the regulations promulgated thereunder.

(A)The amount necessary to pay the tax due under the Federal Insurance Contributions Act (FICA) with respect to the accrued Pension Benefit determined in accordance with the requirements under Treasury Regulation Section 31.3121(v)(2) upon retirement (or such other appropriate “resolution date” as defined under Treasury Regulation Section 31.3121(v)(2)) calculated in accordance with Section 5.1;

(B)The amount estimated to pay the Federal and State income tax withholding liability due on the amount paid under subsection (A) above plus the amount of Federal and State income tax withholding liability due on the amount paid under this subsection (B); and

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(C)An adjusted monthly benefit determined in a manner and on an actuarially equivalent basis in accordance with the methodology and assumptions used to calculate the tax due under subsection (A) above which takes into account the amounts paid under subsections (A) and (B) above and the form of benefit elected by the Participant.

(2)Form of Annuity.

(A)Pre-2008 Commencement. Notwithstanding Section 5.3(c)(1), if a Participant to which this Section 5.3(c) applies retires in 2007 and commences receipt of his Pension Benefit in conjunction with his benefit under the Pension Plan before January 1, 2008, the Participant’s Pension Benefit shall be payable only in the form elected under the Pension Plan and shall be calculated using the same annuity form of payment factors as provided for under the terms of the Pension Plan as in effect during 2007.

(B)Post-2007 Commencement. A Participant described in the first full paragraph of Section 5.3(c)(1) who has not commenced payment of his Pension Benefit prior to 2008 may change the form of payment previously elected to another permitted form described in that paragraph (plus may instead elect a 75% joint and survivor annuity or a 75% joint and survivor annuity with pop-up) at a time and in a manner prescribed by the Administrative Committee. If the form of payment is changed, the Pension Benefit payable pursuant to the original election will be actuarially adjusted using the Actuarial Basis to reflect the new form selected.

(3)Key Employee Rules. If a Participant to which this Section 5.3(c) applies is a Key Employee and the commencement date of his Pension Benefit is on or after January 1, 2008, such Participant will be subject to the Key-Employee Delay and shall receive a lump-sum payment as of the first day of the seventh full month following the Participant’s Separation from Service in an amount equal to six (6) monthly payments due to the Participant under the Plan, plus the monthly payment then due to the Participant for the seventh month. Thereafter, the appropriate monthly benefit shall be paid to the Key Employee and his Provisional Payee, if any. If such a Participant is a Key Employee and the commencement date of his Pension Benefit is before January 1, 2008, the Pension Benefit shall be paid in accordance with Section 5.3(c)(2)(A); the Key-Employee Delay will not apply. If a Key Employee dies during the Key-Employee Delay, the Designated Beneficiary shall receive any benefits that would have been paid if there were no Key-Employee Delay up to the date of death as of the first of the month following the Participant’s death or as soon as practicable thereafter. Interest shall not be added to such benefits. In addition, if such deceased Key Employee elected a form of payment providing for payment to continue to a Provisional Payee pursuant to Section 5.3(c)(1), subject to Section 5.3(c)(2), those payments will begin as of the first of the month following such Key Employee’s death or as soon as practicable thereafter.

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(4)Death of Participant.

(A)Death After Retirement. If a retirement-eligible Participant to which Section 5.3(c)(1) applies dies after Separation from Service, such Participant’s Provisional Payee, if any, shall receive monthly payments for the remainder of the Provisional Payee’s life based on the annuity form of payment the Participant elected or is deemed to have elected pursuant to Section 5.3(c)(1), subject to Section 5.3(c)(2). Such Payments will commence as of the first of the month following such Participant’s death or as soon as practicable thereafter.

(B)Death Before Retirement. If a Participant to which Section 5.3(c) applies dies while actively employed and has a vested benefit in the Pension Plan, then Section 5.2(c)(2) shall apply.

(5)QPSA Charges Waived. Any benefit paid in accordance with this Section 5.3(c) shall be calculated without regard to the charge associated with any Qualified Pre-retirement Survivor Annuity form elected.

(d)Inactive Employee Transition Election. In the event a Participant has Separated from Service prior to March 1, 2007, has deferred commencement until after March 1, 2007, and is eligible to receive a benefit under the Pension Plan on or before January 1, 2008, such Participant must make an election in accordance with Section 5.3(a) at a time and in a manner prescribed by the Administrative Committee and must commence payment by no later than January 1, 2008. The requirements of Section 5.3(b) or Section 5.3(c) (ignoring the fact that the Participant previously incurred a Separation from Service) apply as the case may be based on the Participant’s ultimate election under Section 5.3(a). If a Participant dies before making an election under this Section 5.3(a), Pension Benefit payments shall be made consistent with Section 5.3(b)(3)(B) if the Participant dies prior to making his election to commence his Pension Benefit in conjunction with the commencement of his benefit under the Pension Plan or shall be made consistent with Section 5.3(c)(4)(A) if made after making his election to commence his Pension Benefit in conjunction with the commencement of his benefit under the Pension Plan.

(e)Survivor Benefits in the case of Pre-effective Date Deaths. If a Participant died prior to March 1, 2007 while actively employed and had a vested benefit in the Pension Plan, the Provisional Payee, if any, shall receive the form of benefit provided under the Pension Plan commencing the first of the month following the date the Participant would have attained age 50.

(f)Participants Who Terminate with Vested Benefits.

(1)General Rule. With respect to a Participant who Separated from Service before March 1, 2007, who was not eligible to retire under Article III of the Pension Plan before January 1, 2008, but who was vested in his Retirement Income under Section 8.1 of the Pension Plan, notwithstanding anything to the contrary, such Participant shall receive a Pension Benefit in the form described in Section 5.2(e)(1) paid as of September 1, 2008 based on a Discount Rate determined as of September 2006.

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(2)Death Benefits. With respect to a Participant to which this Section 5.3(f) applies, if such a Participant dies prior to payment in accordance with Section 5.3 (f)(1) above, the Provisional Payee, if any, shall receive the single payment provided in Section 5.3(f)(1) the first of the month following the date the Participant would have attained age 50.

5.4Non-Pension Benefit.

(a)A Participant shall be entitled to a Non-Pension Benefit which is determined under this Section 5.4. An Account shall be established for the Participant as of his initial Plan Year of participation in the Plan. Each Plan Year, such Account shall be credited with an amount equal to the matching contribution amount that his Employing Company is prohibited from contributing to the Savings Plan on behalf of the Participant as a result of the limitations imposed by Sections 401(a)(17), 401(k), 401(m), 402(g), or 415(c) of the Code.

(b)(1) For purposes of this Section 5.4, for the period prior to January 1, 2009, the Non-Pension Benefit of a Participant shall be calculated based on the Participant’s compensation that would have been considered in calculating contributions to his accounts under the Savings Plan and ESOP without regard to the limitations of Section 401(a)(17) or Section 402(g) of the Code including any portion of his compensation he may have elected to defer under the Deferred Compensation Plan, but with respect to only the Savings Plan excluding incentive pay he deferred under the Deferred Compensation Plan.

(2)For purposes of this Section 5.4, for the period on and after January 1, 2009 and prior to January 1, 2010, the Non-Pension Benefit of a Participant shall be calculated based on the Participant’s compensation including base compensation deferred into the Deferred Compensation Plan that would have been considered in calculating contributions to his accounts under the Savings Plan; provided that with respect to deferred base compensation, such deferrals shall only be taken into account once the Code Section 401(a)(17) limit is reached in the Savings Plan and only such deferred base compensation which is deferred after the Code Section 401(a)(17) limit is reached shall be taken into account for this purpose. All other deferred base compensation shall be disregarded. In addition, incentive pay a Participant defers into the Deferred Compensation Plan shall not be taken into account.

(3)For purposes of this Section 5.4, for the period on and after January 1, 2010, the Non-Pension Benefit of a Participant shall be calculated based on the Participant’s compensation that would have been considered in calculating contributions to his accounts under the Savings Plan without regard to the limitation of Section 401(a)(17) of the Code.

(c)The Non-Pension Benefit of the Participant shall be deemed to be invested in Phantom Common Stock. On each such date of investment, a Participant’s Account shall be credited with the number of shares (including fractional shares) of Phantom Common Stock which could have been purchased on such date, based upon the Common Stock’s Purchase Price. As of the date upon which occurs the payment of dividends on the Common Stock, if any, there shall be credited with respect to shares of Phantom Common Stock in the Participant’s Account

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on the applicable dividend record date, such additional shares (including fractional shares) of Phantom Common Stock as follows:

(1)In the case of cash dividends, such additional shares as could be purchased at the Purchase Price with the dividends which would have been payable if the credited shares had been outstanding;

(2)In the case of dividends payable in property other than cash or Common Stock, such additional shares as could be purchased at the Purchase Price with the fair market value of the property which would have been payable if the credited shares had been outstanding; or

(3)In the case of dividends payable in Common Stock, such additional shares as would have been payable on the credited shares if they had been outstanding.

(d)As soon as practicable (but within the period required by Code Section 409A taking into account the period allowed for excess plans under Treasury Regulation Section 1.409A-2(a)(7)(iii)) following the first day of his eligibility to have benefits credited to his Account, a Participant shall designate in a form to be prescribed by the Administrative Committee the method of payment of his Account, which shall be the payment of a single lump sum or a series of annual installments not to exceed twenty (20). If the Participant fails to designate a method of payment, the form shall be a single lump sum. The method of distribution initially designated by a Participant (or the deemed form as the case may be) shall not be revoked and shall govern the distribution of a Participant’s Account, except that such method of distribution may be modified by the Participant but only if such modification meets the requirements of a Modification Delay. Each Participant, his Designated Beneficiary, and legal representative shall be bound as to any action taken pursuant to the method of distribution elected by a Participant and the terms of the Plan.

(e)Effective November 16, 2009, the Participants set forth on Appendix B shall be entitled to the Non-Pension Benefit amount listed therein for such Participants.

5.5Distribution of Non-Pension Benefits.

(a)In the event a Participant elects to receive the distribution of his Account in a lump sum, such payment shall be made as soon as reasonably practicable but not later than seventy-five (75) days after Separation from Service. As permitted under Code Section 409A and the regulations promulgated thereunder the tax due under the Federal Insurance Contributions Act under Treasury Regulation Section 31.312(v)(2) shall be withheld from this payment or from the Participant’s Account, as necessary. Notwithstanding the foregoing, if a Participant is a Key Employee, such Participant shall be subject to the Key-Employee Delay and the payment of the lump sum following Separation from Service shall be as of the beginning of the seventh full calendar month.

(b)In the event a Participant elects to receive the distribution of his Account in annual installments, the first payment shall be made as soon as practicable but not later than seventy-five (75) days following his Separation from Service. The first installment shall equal the market value of any shares of Phantom Common Stock (and fractions thereof) credited to

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said Participant’s Account based on the Sales Price first deducting as permitted under Code Section 409A and the regulations promulgated thereunder the amount calculated as the tax due under the Federal Insurance Contributions Act under Treasury Regulation Section 31.3121(v)(2), second dividing the resulting number by the number of annual installment payments, and finally summing such tax calculated and the quotient of such division. Each subsequent annual payment shall be an amount equal to the market value of any shares of Phantom Common Stock (and fractions thereof) credited to said Participant’s Account based on the Sales Price, divided by the number of the remaining annual payments and shall be paid as soon as practicable following each anniversary of the initial payment date (or what would have been the initial payment date but for the Key-Employee Delay) until the balance of the Participant’s Account is paid in full. For purposes of Section 409A of the Code, installments shall be treated as a single payment. Notwithstanding the foregoing, if a Participant is a Key Employee, such Participant shall be subject to the Key-Employee Delay and the first installment payment following Separation from Service shall be as of the beginning of the seventh full calendar month.

(c)The transfer by a Participant between companies within The Southern Company shall not be deemed to be a Separation from Service with an Employing Company. With regard to any distribution made under this Article, the market value of any shares of Phantom Common Stock credited to a Participant’s Account shall be based on the Sales Price. No portion of a Participant’s Account shall be distributed in Common Stock.

(d)Upon the death of a Participant or a former Participant prior to the payment of his entire Account balance, the unpaid balance of the market value of any shares of Phantom Common Stock (and fractions thereof) credited to said Participant’s Account based on the Sales Price shall be paid to the Designated Beneficiary in a lump sum within seventy-five (75) days of Participant’s date of death. The Designated Beneficiary selection may be changed in a manner prescribed by the Administrative Committee by the Participant or former Participant at any time without the consent of the prior Beneficiary.

(e)Upon the Total Disability of a Participant or former Participant prior to the payment of his entire Account balance, the unpaid balance of the market value of any shares of Phantom Common Stock (and fractions thereof) credited to said Participant’s Account based on the Sales Price of his Account shall be paid in accordance with the distribution method elected by such Participant or former Participant commencing as of such Participant’s Separation from Service.

(f)Solely with respect to the Non-Pension Benefit described in Section 5.4(e), the specified Non-Pension Benefit amounts shall be paid at the same time and in the same manner as the election in effect for an Account under this Section 5.5 as applicable to a particular Participant. Such time and manner may be modified as provided in Section 5.4(d). If a Participant has commenced receipt of payment of his Account, the benefit amount provided under this Section 5.5(f) shall be paid as part of the remaining installment payments, or if none, paid in a single lump sum prior to March 15, 2010.

5.6Allocation of Pension Benefit Liability. In the event that a Participant eligible to receive a Pension Benefit has been employed at more than one Employing Company, the Pension Benefit liability shall be apportioned so that each such Employing Company is obligated

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in accordance with this Section 5.6 to cover the percentage of the total Pension Benefit as determined below. Each Employing Company’s share of the Pension Benefit liability shall be calculated by multiplying the Pension Benefit by a fraction where the numerator of such fraction is the base rate of pay, as defined by the Administrative Committee, received by the Participant at the respective Employing Company on his date of termination of employment or transfer, as applicable, multiplied by the Accredited Service earned by the Participant at the respective Employing Company and where the denominator of such fraction is the sum of all numerators calculated for each respective Employing Company by which the Participant has been employed.

5.7Funding of Benefits. Except as expressly limited under the terms of the Trust, neither the Company nor any Employing Company hereunder shall reserve or otherwise set aside funds for the payment of its obligations under the Plan. In any event, such obligations shall be paid or deemed to be paid solely from the general assets of the Employing Companies. Participants shall only have the status of general, unsecured creditors of the Company and their respective Employing Companies. Notwithstanding that a Participant shall be entitled to receive the balance of his Account under the Plan, the assets from which such amount shall be paid shall at all times remain subject to the claims of the creditors of the Participant’s Employing Company.

5.8Withholding. There shall be deducted as permitted under Code Section 409A and the regulations promulgated thereunder from Plan payments and, if necessary, from the Non-Pension Account under the Plan the amount of any tax required by any governmental authority to be withheld and paid over by an Employing Company to such governmental authority for the account of the Participant or Designated Beneficiary entitled to such payment.

5.9Recourse Against Deferred Compensation Trust. In the event a Participant who is employed on or after January 1, 1999 with an “Employing Company” (as such term is defined in the Change in Control Benefits Protection Plan) disputes the calculation of his Pension Benefit or Non-Pension Benefit, or payment of amounts due under the terms of the Plan, the Participant has recourse against the Company, the Employing Company by which the Participant is or was employed, if different, the Plan, and the Trust for payment of benefits to the extent the Trust so provides.

5.10Change in Control. The provisions of the Change in Control Benefits Protection Plan are incorporated herein by reference to determine the occurrence of a change in control or preliminary change in control of Southern Company or an Employing Company, the benefits to be provided hereunder, and the funding of the Trust in the event of such a change in control. Any modifications to the Change in Control Benefits Protection Plan are likewise incorporated herein and are otherwise intended to comply with 409A of the Code.

ARTICLE VI -   MISCELLANEOUS

6.1Assignment. Neither the Participant, his Designated Beneficiary, nor his legal representative shall have any rights to sell, assign, transfer, or otherwise convey the right to receive the payment of any Pension Benefit or Non-Pension Benefit due hereunder, which payment and the right thereto are expressly declared to be nonassignable and nontransferable.

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Any attempt to assign or transfer the right to payment under the Plan shall be null and void and of no effect.

6.2Amendment and Termination. Except for the provisions of Section 5.10 hereof, which may not be amended following a “Southern Change in Control” or “Subsidiary Change in Control”, as defined in the Change in Control Benefits Protection Plan, the Plan may be amended or terminated at any time by the Board of Directors, provided, however, that no amendment or termination shall cause a forfeiture or reduction in any benefits accrued as of the date of such amendment or termination. The Plan may also be amended by the Administrative Committee (a) if such amendment does not involve a substantial increase in cost to any Employing Company, or (b) as may be necessary, proper, or desirable in order to comply with laws or regulations enacted or promulgated by any federal or state governmental authority. During the compliance transition period provided for by the 409A Guidance, the Administrative Committee may enter into transition elections as to time and form of payment under this Plan and, subject to the preceding authority, shall be treated as amendments to the Plan.

6.3No Guarantee of Employment. Participation hereunder shall not be construed as creating any contract of employment between any Employing Company and a Participant, nor shall it limit the right of an Employing Company to suspend, terminate, alter, or modify, whether or not for cause, the employment relationship between such Employing Company and a Participant.

6.4Mirant. For the avoidance of doubt, the provisions of the Plan effective in the Plan’s amendment and restatement dated May 1, 2000 (“2000 Plan”) concerning Mirant Shares were applied through the liquidation of Mirant Shares as a form of investment in the Plan as of June 30, 2006. Although these provisions concerning Mirant Shares are not restated in this amendment and restatement, a Participant’s rights concerning Mirant Shares are as set forth in such 2000 Plan. To this limited extent, the provisions in the 2000 Plan concerning Mirant Shares are incorporated herein.

6.5Construction. This Plan shall be construed in accordance with and governed by the laws of the State of Georgia, to the extent such laws are not otherwise superseded by the laws of the United States.

23

IN WITNESS WHEREOF, the amended and restated Plan has been executed by a duly authorized officer of Southern Company Services, Inc., pursuant to resolutions of the Board of Directors of the Company, this 29th day of June, 2016.

SOUTHERN COMPANY SERVICES, INC.
By:	/s/Stacy Kilcoyne
Its:	Human Resources Vice President

Attest:
By:	/s/Laura Oleck Hewett
Its:	Assistant Secretary

24

APPENDIX A
THE SOUTHERN COMPANY SUPPLEMENTAL BENEFIT PLAN
EMPLOYING COMPANIES AS OF JANUARY 1, 2009

Alabama Power Company

Georgia Power Company

Gulf Power Company

Mississippi Power Company

Southern Communications Services, Inc.

Southern Company Energy Solutions, LLC

Southern Company Services, Inc.

Southern Nuclear Operating Company, Inc.

APPENDIX B November 16, 2009

Name and Southern Company I.D.                    Benefit Amount

SCHEDULE OF PROVISIONS
FOR PRE-2005 NON-PENSION BENEFITS

ARTICLE I ‑ PURPOSE

1.1    Schedule of Provisions for Pre-2005 Non-Pension Benefits. This Schedule sets forth the operative provisions of the Plan applicable to “grandfathered” Non-Pension Benefits which are treated by the Employing Companies as not subject to Section 409A of the Code. The Account balance (plus earnings thereon) of the grandfathered Non-Pension Benefits shall only be subject to the provisions set forth in this Schedule. In accordance with transition rules under the 409A Guidance, these provisions are only intended to preserve the rights and features of the “grandfathered” Non-Pension Benefits and are, therefore, not intended to “materially modify” any aspect of such rights and features. Provisions of this Schedule should be so construed whenever necessary or appropriate. Provisions in this Schedule shall only be amended in accordance with this Schedule’s terms.

ARTICLE II - DEFINITIONS

2.1    “Account” shall mean for purposes of this Schedule the amount credited to the account of a Participant to reflect the interest of a Participant in the Plan solely pursuant to the terms of this Schedule resulting from a Participant’s Non-Pension Benefit calculated in accordance with Section 5.2. This Account amount is attributable to those deferrals which are not subject to Section 409A of the Code.

2.2    “Administrative Committee” shall mean the committee referred to in Section 3.1 of this Schedule.

2.3    “Beneficiary shall have the same meaning as set forth for “Designated Beneficiary” in the main body of the Plan.

2.4    “Board of Directors shall mean the Board of Directors of the Company.

2.5    “Change in Control Benefits Protection Plan shall mean the Change in Control Benefits Protection Plan, as approved by the Southern Board, as it may be amended from time to time in accordance with the provisions therein.

2.6    “Code” shall mean the Internal Revenue Code of 1986, as amended from time to time.

2.7    “Common Stock shall mean common stock of Southern Company.

2.8    “Company” shall mean Southern Company Services, Inc.

2.9    “Deferred Compensation Plan” shall mean The Southern Company Deferred Compensation Plan, as amended from time to time.

2.10    “Employee” shall mean any person who is currently employed by an Employing Company.

2.11    “Employing Company” shall mean the Company and any affiliate or subsidiary of Southern Company which the Board of Directors may from time to time determine to bring under the Plan and any successor to them. The Employing Companies are set forth in Appendix A to the Plan, as amended from time to time.

2.12    “ESOP” shall mean The Southern Company Employee Stock Ownership Plan, as amended from time to time.

2.13    “Non-Pension Benefit” shall mean the benefit described in Section 5.2 of this Schedule.

2.14    “Participant” shall mean an Employee or former Employee of an Employing Company who is eligible and participates in the Plan pursuant to Article IV of this Schedule.

2.15    “Pension Benefit” shall mean the benefit described in Section 5.1 of this Schedule.

2.16    “Pension Plan” shall mean The Southern Company Pension Plan, as amended from time to time.

2.17    “Phantom Common Stock” shall mean the Common Stock in which a Participant is deemed to invest his Non-Pension Benefit as if such Common Stock had been purchased upon contribution to the Savings Plan, the ESOP, and/or the Performance Sharing Plan, as the case may be.

2.18    “Plan” shall mean The Southern Company Supplemental Benefit Plan, as amended and restated effective January 1, 2009, which includes this Schedule, as may be further amended from time to time.

2.19    “Performance Sharing Plan” shall mean The Southern Company Performance Sharing Plan, as amended from time to time prior to its merger into the Savings Plan.

2.20    “Plan Year” shall mean the calendar year.

2.21    “Purchase Price” shall mean for purposes of deemed purchases of Phantom Common Stock the following: (a) with respect to the Savings Plan and the Performance Sharing Plan, the purchase price of a share of the Common Stock under the Savings Plan as of the applicable Valuation Date; (b) with respect to any investment of dividends attributable to Phantom Common Stock, the dividend reinvestment price of a share of the Common Stock under the Savings Plan as of the applicable Valuation Date; and (c) with respect to the ESOP, the price at which a share of Common Stock is purchased with regard to a contribution made for each applicable Plan Year.

2.22    “Sales Price” shall mean the closing price on any trading day of a share of Common Stock based on consolidated trading as defined by the Consolidated Tape Association

2

and reported as part of the consolidated trading prices of New York Stock Exchange listed securities.

2.23    “Savings Plan” shall mean The Southern Company Employee Savings Plan, as amended from time to time.

2.24    “Southern Board” shall mean the board of directors of Southern Company.

2.25    “Southern Company” shall mean Southern Company, its successors and assigns.

2.26    “Trust” shall mean the Southern Company Deferred Compensation Trust.

2.27    “Valuation Date” shall mean each trading day of the New York Stock Exchange, or any successor national exchange on which the Common Stock is traded and with respect to which a Sales Price may be determined.

Where the context requires, the definitions of all terms set forth in the Pension Plan, the ESOP, the Performance Sharing Plan, the Savings Plan, and the Deferred Compensation Plan shall apply with equal force and effect for purposes of interpretation and administration of the Plan, unless said terms are otherwise specifically defined in the Plan. The masculine pronoun shall be construed to include the feminine pronoun and the singular shall include the plural, where the context so requires.

ARTICLE III - ADMINISTRATION OF SCHEDULE

3.1    Article III of the main body of the Plan is herein incorporated into this Schedule by reference. Any amendment to Article III of the main body of the Plan shall operate as amendment to this Article III of the Schedule.

ARTICLE IV - ELIGIBILITY

4.1    For so long as an Employee has an Account balance governed by this Schedule, he shall be a Participant in the Plan for purposes of this Schedule, and such Account balance shall be maintained and administered solely in accordance with the terms of this Schedule.

ARTICLE V - BENEFITS

5.1    Pension Benefit.

Pension Benefits are not subject to grandfather provisions set forth in this Schedule. Plan provisions concerning Pension Benefits are set forth in the main body of the Plan.

5.2    Non-Pension Benefit.

(a)    No Non-Pension Benefits which are subject to Section 409A of the Code shall be credited to the Account of a participant for purposes of the provisions of this Schedule. The Non-Pension Benefit Account of the Participant governed by this Schedule shall be deemed to be invested in Phantom Common Stock. On each such date of investment, a Participant’s

3

Account shall be credited with the number of shares (including fractional shares) of Phantom Common Stock which could have been purchased on such date, based upon the Common Stock’s Purchase Price. As of the date upon which occurs the payment of dividends on the Common Stock, there shall be credited with respect to shares of Phantom Common Stock in the Participant’s Account on the applicable dividend record date, such additional shares (including fractional shares) of Phantom Common Stock as follows:

(1)    In the case of cash dividends, such additional shares as could be purchased at the Purchase Price with the dividends which would have been payable if the credited shares had been outstanding;

(2)    In the case of dividends payable in property other than cash or Common Stock, such additional shares as could be purchased at the Purchase Price with the fair market value of the property which would have been payable if the credited shares had been outstanding; or

(3)    In the case of dividends payable in Common Stock, such additional shares as would have been payable on the credited shares if they had been outstanding.

(b)    As soon as practicable following the first day of his eligibility to have benefits credited to his Account, a Participant shall designate in a form to be prescribed by the Administrative Committee the method of payment of his Account, which shall be the payment of a single lump sum or a series of annual installments not to exceed twenty (20). The method of distribution initially designated by a Participant shall not be revoked and shall govern the distribution of a Participant’s Account. Notwithstanding the foregoing, in the sole discretion of the Administrative Committee, upon application by the Participant, the method of distribution designated by such Participant may be modified, provided the Participant requests such modification not later than the 366th day prior to a distribution of such Participant’s Account in accordance with the terms of the Plan, provided, however, that any Participant who is required to file reports pursuant to Section 16(a) of the Securities and Exchange Act of 1934, as amended, with respect to equity securities of The Southern Company shall not be permitted to amend his distribution election during any time period for which such Participant is required to file any such reports with respect to his Non-Pension Benefit unless such amendment is specifically approved by the Administrative Committee in its sole discretion. Each Participant, his Beneficiary, and legal representative shall be bound as to any action taken pursuant to the method of distribution elected by a Participant and the terms of the Plan. Notwithstanding any provision of the Plan to the contrary, if a Participant has elected to receive his Plan distribution in annual installment payments and such Participant’s Plan Account does not exceed five thousand dollars ($5,000) (as adjusted from time to time by Treasury regulations applicable to tax-qualified retirement plans) at the time such benefit is valued for distribution, such payment shall be made as a single, lump-sum payment to the Participant.

5.3    Distribution of Non-Pension Benefits.

(a)    When a Participant terminates his employment with an Employing Company, such Participant shall be entitled to receive the market value of any shares of Phantom Common Stock (and fractions thereof) reflected in his Account in a single, lump sum distribution

4

or annual installments not to exceed twenty (20). Such distribution shall be made not later than seventy-five (75) days following the date on which his termination of employment occurs, or as soon as reasonably practicable thereafter. The transfer by a Participant between companies within The Southern Company shall not be deemed to be a termination of employment with an Employing Company. With regard to any distribution made under this Article of the Schedule, the market value of any shares of Phantom Common Stock credited to a Participant’s Account shall be based on the Sales Price. No portion of a Participant’s Account shall be distributed in Common Stock.

(b)    In the event a Participant elects to receive the distribution of his Account in annual installments, the first payment shall be made not later than seventy-five (75) days following the date on which his termination of employment occurs, or as soon as reasonably practicable thereafter, subject however to the cash-out provisions of Section 5.2(d) of this Schedule. Installments shall equal the balance in the Participant’s Account taking into account the tax due under the Federal Insurance Contributions Act divided by the number of annual installment payments. Each subsequent annual payment shall be an amount equal to the balance in the Participant’s Account as of the Valuation Date, divided by the number of the remaining annual payments and shall be due on the anniversary of the preceding payment date.

(c)    Upon the death of a Participant or a former Participant prior to the payment of the market value of any shares of Phantom Common Stock (and fractions thereof) credited to said Participant’s Account based on the Sales Price, the unpaid balance shall be paid in the sole discretion of the Administrative Committee (1) in a lump sum to the designated Beneficiary of a Participant or former Participant within seventy-five (75) days following the date on which the Administrative Committee is provided evidence of the Participant’s death (or as soon as reasonably practicable thereafter) or (2) in accordance with the distribution method chosen by such Participant or former Participant. The Beneficiary designation may be changed by the Participant or former Participant at any time without the consent of the prior Beneficiary.

(d)    Upon the total disability of a Participant or former Participant, as determined by the Social Security Administration, prior to the payment of the market value of any shares of Phantom Common Stock (and fractions thereof) credited to such Participant’s Account based on the Sales Price, the unpaid balance of his Account shall be paid in the sole discretion of the Administrative Committee (1) in a lump sum to the Participant or former Participant, or his legal representative within seventy-five (75) days following the date on which the Administrative Committee receives notification of the determination of a disability by the Social Security Administration (or as soon as reasonably practicable thereafter) or (2) in accordance with the distribution method elected by such Participant or former Participant.

(e)    The Administrative Committee, in its sole discretion upon application made by the Participant, a designated Beneficiary, or their legal representative, may determine to accelerate payments or, in the event of death or total disability (as determined by Social Security Administration), to extend or otherwise make payments in a manner different from the manner in which such payment would be made under the method of distribution elected by the Participant in the absence of such determination. Notwithstanding any provision of the Plan to the contrary, if a Participant has elected to receive his Plan distribution in annual installment payments and such Participant’s Plan Account does not exceed five thousand dollars ($5,000) (as adjusted from

5

time to time by Treasury regulations applicable to tax-qualified retirement plans) at the time such benefit is valued for distribution, such payment shall be made as a single, lump-sum payment to the Participant.

5.4    Recourse Against Deferred Compensation Trust. In the event a Participant who is employed on or after January 1, 1999 with an “Employing Company” (as such term is defined in the Change in Control Benefits Protection Plan) disputes the calculation of his Non-Pension Benefit under this Schedule, or payment of amounts due under the terms of the Plan, the Participant has recourse against the Company, the Employing Company by which the Participant is or was employed, if different, the Plan, and the Trust for payment of benefits to the extent the Trust so provides.

5.5    Change in Control. The provisions of the Change in Control Benefits Protection Plan are incorporated herein by reference to determine the occurrence of a change in control or preliminary change in control of Southern Company or an Employing Company, the benefits to be provided hereunder and the funding of the Trust in the event of such a change in control. Any modifications to the Change in Control Benefits Protection Plan are likewise incorporated herein.

ARTICLE VI - MISCELLANEOUS

6.1    Except for Section 6.2 of the main body of the Plan, Article VI is hereby incorporated by reference into this Schedule. Any amendment to Article VI of the main body of the Plan shall operate as an amendment to this Article VI of the Schedule except that Section 6.2 below shall set forth the sole method for amending and/or terminating this Schedule.

6.2    This Schedule may be amended, modified, or terminated by the Board of Directors in its sole discretion at any time and from time to time by resolution expressly modifying this Schedule; provided, however, that (a) Section 5.5 of this Schedule may not be amended following a “Southern Change in Control” or “Subsidiary Change in Control” (as defined in the Change in Control Benefits Protection Plan), (b) no such amendment, modification, or termination shall cause a forfeiture or reduction in any benefits accrued as of the date of such amendment, modification, or termination and/or (c) Article III and Section 6.1 of this Schedule may be amended in accordance with their terms. It is the Company’s intent that any modification to this Schedule shall not constitute nor shall it be interpreted to be a “material modification” of any right or feature of this Schedule as such term is defined under the Section 409A Guidance.

6

EX-10.C3

Confidential Trade Secret Information — Subject to Restricted Procedures

Exhibit 10(c)(3)

Georgia Power Company has requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the Securities and Exchange Commission. Georgia Power Company has omitted such portions from this filing and filed them separately with the Securities and Exchange Commission. Such omissions are designated as “[***].”

AMENDMENT NO. 8

TO

ENGINEERING, PROCUREMENT AND CONSTRUCTION
AGREEMENT

BETWEEN

GEORGIA POWER COMPANY, FOR ITSELF AND AS AGENT
FOR OGLETHORPE POWER CORPORATION (AN ELECTRIC
MEMBERSHIP CORPORATION), MUNICIPAL ELECTRIC
AUTHORITY OF GEORGIA, AND THE CITY OF DALTON,
GEORGIA, ACTING BY AND THROUGH ITS BOARD OF WATER,
LIGHT AND SINKING FUND COMMISSIONERS, AS OWNERS

AND

A CONSORTIUM CONSISTING OF WESTINGHOUSE ELECTRIC
COMPANY LLC AND STONE & WEBSTER, INC., AS
CONTRACTOR

FOR
UNITS 3 & 4 AT THE VOGTLE ELECTRIC GENERATING PLANT
SITE

IN WAYNESBORO, GEORGIA

DATED AS OF APRIL 8, 2008

Confidential Trade Secret Information — Subject to Restricted Procedures

AMENDMENT NO. 8 TO

ENGINEERING, PROCUREMENT AND CONSTRUCTION AGREEMENT

This AMENDMENT NO. 8 (this “Amendment”) TO THE ENGINEERING, PROCUREMENT AND CONSTRUCTION AGREEMENT, dated April 8, 2008 (together with the Exhibits thereto, as amended, the “EPC Agreement”), by and between GEORGIA POWER COMPANY, a Georgia corporation (“GPC”), acting for itself and as agent for OGLETHORPE POWER CORPORATION (AN ELECTRIC MEMBERSHIP CORPORATION), an electric membership corporation formed under the laws of the State of Georgia, MUNICIPAL ELECTRIC AUTHORITY OF GEORGIA, a public body corporate and politic and an instrumentality of the State of Georgia, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, each a Georgia limited liability company, 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 (hereinafter referred to individually and collectively as “Owners”), and a consortium consisting of WESTINGHOUSE ELECTRIC COMPANY LLC, a Delaware limited liability company having a place of business in Cranberry, Pennsylvania (“Westinghouse”), and WECTEC GLOBAL PROJECT SERVICES INC. (formerly known as CB&I Stone & Webster, Inc. formerly known as Stone & Webster, Inc.), a Louisiana corporation (“WECTEC”) (hereinafter referred to collectively as a “Contractor”), is entered into as of the 20th day of April, 2016. Owners and Contractor are individually referred to herein as a “Party” and collectively referred to herein as the “Parties.”

RECITALS

WHEREAS, Owners and Contractor entered into the EPC Agreement, as of April 8, 2008, to provide for, among other things, the design, engineering, procurement, installation, construction and technical support of start-up and testing of equipment, materials and structures comprising the Facility;

WHEREAS, Owners and Contractor have agreed to revise the Milestone Payment Schedule set forth in Table F.2.1 and Table F.2.3 of Exhibit F of the EPC Agreement;

WHEREAS, CB&I Stone & Webster, Inc. has changed its name to WECTEC Global Project Services Inc.; and

WHEREAS, the Parties agree that, with the exception of the changes expressly stated herein, this Amendment will not change the terms and conditions of the EPC Agreement.

NOW, THEREFORE, in consideration of the recitals, the mutual promises herein and other good and valuable consideration, the receipt and sufficiency of which the Parties acknowledge, the Parties, intending to be legally bound, stipulate and agree as follows:

1

Confidential Trade Secret Information — Subject to Restricted Procedures

ARTICLE 1

AMENDMENTS TO EPC AGREEMENT

Section 1.1(a)    The Table F.2.1 – [***] – of Exhibit F of the EPC Agreement shall be and hereby is deleted in its entirety and replaced with the new Table F.2.1 set forth as Attachment A hereto [***].

(b)    The Table F.2.3 – [***] – of Exhibit F of the EPC Agreement shall be and hereby is deleted in its entirety and replaced with the new Table F.2.3 set forth as Attachment B hereto [***].

(c)    Exhibit J of the EPC Agreement shall be and hereby is amended by inserting the following new sentence at the end thereof:

[***]

Section 1.2The cover page of the EPC Agreement shall be and hereby is amended by (i) inserting the phrase “, MEAG POWER SPVJ, LLC, MEAG POWER SPVM, LLC, MEAG POWER SPVP, LLC,” after the phrase “MUNICIPAL ELECTRIC AUTHORITY OF GEORGIA” and (ii) deleting the phrase “Stone & Webster, Inc.” and replacing it with the phrase “WECTEC Global Project Services Inc.”

Section 1.3The first paragraph on page one of the EPC Agreement shall be and hereby is amended by inserting the phrase “MEAG POWER SPVJ, LLC, MEAG POWER SPVM, LLC, MEAG POWER SPVP, LLC, each a Georgia limited liability company,” after the phrase “MUNICIPAL ELECTRIC AUTHORITY OF GEORGIA, a public body corporate and politic and an instrumentality of the State of Georgia,”.

Section 1.4The definition of “Owners” in Article 1 of the EPC Agreement shall be and hereby is amended by (i) inserting the phrase “(An Electric Membership Corporation)” after the phrase “Oglethorpe Power Corporation” both places it appears and (ii) inserting the phrase “, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC,” after the phrase “the Municipal Electric Authority of Georgia” both places it appears.

Section 1.5The definitions of “DRB Member Agreement” and “DRB Procedures” in Article 1 of the EPC Agreement shall be and hereby are deleted in their entirety and replaced with the following:

“DRB Member Agreement” means an agreement, in the form attached to the DRB Procedures (with such changes thereto as are agreed to by the Parties and the DRB Members), to which the individual DRB Members, the Owners, and the Contractor are Parties, which establishes the DRB consistent with the requirements of the DRB Procedures.

“DRB Procedures” means the Dispute Resolution Board Procedures attached hereto as Exhibit CC (with such changes thereto as contained in the version attached to the DRB Member Agreement).

2

Confidential Trade Secret Information — Subject to Restricted Procedures

Section 1.6Section 7.1 of the EPC Agreement shall be and hereby is amended by inserting the following new sentence at the end thereof:

[***]

Section 1.7Section 28.1 of the EPC Agreement shall be and hereby is amended by deleting the notice information for Stone & Webster and replacing it with the following:

If to WECTEC:	WECTEC Global Project Services Inc. Attn: David Durham, President 128 S Tryon Street Charlotte, NC    28202 Facsimile No.: see project correspondence routine E-mail address: see project correspondence routine
With a copy to:	Mike Sweeney, General Counsel 1000 Westinghouse Drive Cranberry, PA16066 Facsimile No.: see project correspondence routine E-mail address: see project correspondence routine

Section 1.8The phrases “Stone & Webster, Inc.”, “Shaw Stone and Webster (SSW)”, “Shaw Stone &Webster, Inc.”, “Stone and Webster Construction, Inc.” and “CB&I Stone & Webster, Inc.” wherever they appear in the EPC Agreement shall be and hereby are deleted and replaced with the phrase “WECTEC Global Project Services Inc.”.

Section 1.9The phrases “Stone & Webster”, “S&W”, “SS&W”, “SHAW – STONE & WEBSTER”, “Shaw S&W”, “Stone and Webster” and “CB&I/S&W” wherever they appear in the EPC Agreement shall be and hereby are deleted and replaced with “WECTEC”.

Section 1.10The word “Monroeville” wherever it appears in the EPC Agreement shall be and hereby is deleted and replaced with the word “Cranberry”.

ARTICLE II
MISCELLANEOUS

Section 2.1Capitalized terms used herein and not defined herein have the meanings assigned in the EPC Agreement.

Section 2.2This Amendment shall be construed in connection with and as part of the EPC Agreement, and all terms, conditions, and covenants contained in the EPC Agreement, except as herein modified, shall be and shall remain in full force and effect. The Parties hereto agree that they are bound by the terms, conditions, and covenants of the EPC Agreement as amended hereby.

Section 2.3This Amendment may be executed simultaneously in two or more counterparts, each of which shall be deemed an original but all of which together shall constitute one and the same instrument.

3

Confidential Trade Secret Information — Subject to Restricted Procedures

Section 2.4The validity, interpretation, and performance of this Amendment and each of its provisions shall be governed by the internal Laws of the State of Georgia.

Section 2.5Except as expressly provided for in this Amendment, all other Articles, Sections and Exhibits of and to the EPC Agreement remain unchanged.

[Remainder of page left blank intentionally.]

4

Confidential Trade Secret Information — Subject to Restricted Procedures

IN WITNESS WHEREOF, the Parties have duly executed this Amendment as of the date first above written.

WESTINGHOUSE ELECTRIC COMPANY LLC
By:	/s/ Jeffrey A. Benjamin
Name:	Jeffrey A. Benjamin
Title:	SVP NP & MP
WECTEC GLOBAL PROJECT SERVICES INC. (f/k/a CB&I Stone & Webster, Inc. f/k/a Stone & Webster, Inc.)
By:	/s/ David C. Durham
Name:	David C. Durham
Title:	President
GEORGIA POWER COMPANY, as an Owner and as agent for the other Owners
By:	/s/ David L. McKinney
Name:	David L. McKinney
Title:	VP, Nuclear Development

Attachment A

Confidential Trade Secret Information — Subject to Restricted Procedures

Table F.2.1

F.2.1    [***]

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

* [***]

Attachment A

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

A-2

* [***]

Attachment A

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

A-3

* [***]

Attachment A

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

A-4

* [***]

Attachment A

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

A-5

* [***]

Attachment B

Confidential Trade Secret Information — Subject to Restricted Procedures

Table F.2.3

F.2.3    [***]

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

* [***]

Attachment B

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

B-2

* [***]

Attachment B

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

B-3

* [***]

Attachment B

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

B-4

* [***]

Attachment B

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

B-5

* [***]

Attachment B

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

B-6

* [***]

Attachment B

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

B-7

* [***]

Attachment B

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

B-8

* [***]

Attachment B

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

B-9

* [***]

Attachment B

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

B-10

* [***]

Attachment B

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

B-11

* [***]

Attachment B

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

B-12

* [***]

Attachment B

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

B-13

* [***]

Attachment B

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

B-14

* [***]

Attachment B

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

B-15

* [***]

Attachment B

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

B-16

* [***]

Attachment B

Confidential Trade Secret Information — Subject to Restricted Procedures

Activity ID	Unit	Activity Name	Area/ Component	Milestone Complete Date	Unit 3*	Unit 3 CLO	Unit 4*	Unit 4 CLO
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]
[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]	[***]

B-17

* [***]

EX-31.A1

Exhibit 31(a)1

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Thomas A. Fanning, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 8, 2016

/s/Thomas A. Fanning

Thomas A. Fanning

Chairman, President and

Chief Executive Officer

EX-31.A2

Exhibit 31(a)2

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Art P. Beattie, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 8, 2016

/s/Art P. Beattie

Art P. Beattie

Executive Vice President and Chief Financial Officer

EX-31.B1

Exhibit 31(b)1

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Mark A. Crosswhite, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 8, 2016

/s/Mark A. Crosswhite

Mark A. Crosswhite

Chairman, President and Chief Executive Officer

EX-31.B2

Exhibit 31(b)2

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Philip C. Raymond, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 8, 2016

/s/Philip C. Raymond

Philip C. Raymond

Executive Vice President, Chief Financial Officer

and Treasurer

EX-31.C1

Exhibit 31(c)1

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, W. Paul Bowers, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 8, 2016

/s/W. Paul Bowers

W. Paul Bowers

Chairman, President and Chief Executive Officer

EX-31.C2

Exhibit 31(c)2

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, W. Ron Hinson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 8, 2016

/s/W. Ron Hinson

W. Ron Hinson

Executive Vice President, Chief Financial Officer, Treasurer and Corporate Secretary

EX-31.D1

Exhibit 31(d)1

GULF POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, S. W. Connally, Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q of Gulf Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 8, 2016

/s/S. W. Connally, Jr.

S. W. Connally, Jr.

Chairman, President and Chief Executive Officer

EX-31.D2

Exhibit 31(d)2

GULF POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Xia Liu, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Gulf Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 8, 2016

/s/Xia Liu

Xia Liu

Vice President and Chief Financial Officer

EX-31.E1

Exhibit 31(e)1

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Anthony L. Wilson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 8, 2016

/s/Anthony L. Wilson

Anthony L. Wilson

President and

 Chief Executive Officer

EX-31.E2

Exhibit 31(e)2

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Moses H. Feagin, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 8, 2016

/s/Moses H. Feagin

Moses H. Feagin

Vice President, Treasurer and

Chief Financial Officer

EX-31.F1

Exhibit 31(f)1

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Joseph A. Miller, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Southern Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   August 8, 2016

/s/Joseph A. Miller

Joseph A. Miller

Chairman, President and Chief Executive Officer

EX-31.F2

Exhibit 31(f)2

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, William C. Grantham, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Southern Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 8, 2016

/s/William C. Grantham

William C. Grantham

Senior Vice President, Treasurer and Chief

Financial Officer

EX-32.A

Exhibit 32(a)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of The Southern Company for the quarter ended June 30, 2016, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of The Southern Company for the quarter ended June 30, 2016, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of The Southern Company for the quarter ended June 30, 2016, fairly presents, in all material respects, the financial condition and results of operations of The Southern Company.

/s/Thomas A. Fanning

Thomas A. Fanning

Chairman, President and

Chief Executive Officer

/s/Art P. Beattie

Art P. Beattie

Executive Vice President and

Chief Financial Officer

August 8, 2016

EX-32.B

Exhibit 32(b)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended June 30, 2016, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended June 30, 2016, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended June 30, 2016, fairly presents, in all material respects, the financial condition and results of operations of Alabama Power Company.

/s/Mark A. Crosswhite

Mark A. Crosswhite

Chairman, President and Chief Executive Officer

/s/Philip C. Raymond

Philip C. Raymond

Executive Vice President,

Chief Financial Officer and Treasurer

August 8, 2016

EX-32.C

Exhibit 32(c)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended June 30, 2016, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended June 30, 2016, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended June 30, 2016, fairly presents, in all material respects, the financial condition and results of operations of Georgia Power Company.

/s/W. Paul Bowers

W. Paul Bowers

Chairman, President and Chief Executive Officer

/s/W. Ron Hinson

W. Ron Hinson

Executive Vice President, Chief Financial Officer, Treasurer and Corporate Secretary

August 8, 2016

EX-32.D

Exhibit 32(d)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Gulf Power Company for the quarter ended June 30, 2016, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Gulf Power Company for the quarter ended June 30, 2016, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Gulf Power Company for the quarter ended June 30, 2016, fairly presents, in all material respects, the financial condition and results of operations of Gulf Power Company.

/s/S. W. Connally, Jr.

S. W. Connally, Jr.

Chairman, President and Chief Executive Officer

/s/Xia Liu

Xia Liu

Vice President and Chief Financial Officer

August 8, 2016

EX-32.E

Exhibit 32(e)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended June 30, 2016, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended June 30, 2016, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended June 30, 2016, fairly presents, in all material respects, the financial condition and results of operations of Mississippi Power Company.

/s/Anthony L. Wilson

Anthony L. Wilson

President and Chief Executive Officer

/s/Moses H. Feagin

Moses H. Feagin

Vice President, Treasurer and

Chief Financial Officer

August 8, 2016

EX-32.F

Exhibit 32(f)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended June 30, 2016, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended June 30, 2016, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended June 30, 2016, fairly presents, in all material respects, the financial condition and results of operations of Southern Power Company.

/s/Joseph A. Miller

Joseph A. Miller

Chairman, President and Chief Executive Officer

/s/William C. Grantham

William C. Grantham

Senior Vice President, Treasurer and

Chief Financial Officer

August 8, 2016

XML

Document and Entity Information	6 Months Ended
	Jun. 30, 2016 shares
Document Information [Line Items]
Entity Registrant Name	SOUTHERN CO
Entity Central Index Key	0000092122
Document Type	10-Q
Document Period End Date	Jun. 30, 2016
Amendment Flag	false
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	941,598,673
Alabama Power [Member]
Document Information [Line Items]
Entity Registrant Name	ALABAMA POWER CO
Entity Central Index Key	0000003153
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	30,537,500
Georgia Power [Member]
Document Information [Line Items]
Entity Registrant Name	GEORGIA POWER CO
Entity Central Index Key	0000041091
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	9,261,500
Gulf Power [Member]
Document Information [Line Items]
Entity Registrant Name	GULF POWER CO
Entity Central Index Key	0000044545
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	5,642,717
Mississippi Power [Member]
Document Information [Line Items]
Entity Registrant Name	MISSISSIPPI POWER CO
Entity Central Index Key	0000066904
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	1,121,000
Southern Power [Member]
Document Information [Line Items]
Entity Registrant Name	SOUTHERN POWER CO
Entity Central Index Key	0001160661
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	1,000

XML

Condensed Consolidated Statements of Income (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Operating Revenues:
Retail revenues	$ 3,748	$ 3,714	$ 7,124	$ 7,256
Wholesale revenues	446	448	842	915
Other electric revenues	166	162	348	325
Other revenues	99	13	137	24
Total operating revenues	4,459	4,337	8,451	8,520
Operating Expenses:
Fuel	1,023	1,200	1,934	2,412
Purchased power	189	171	354	315
Cost of sales	58	0	77	0
Other operations and maintenance	1,099	1,100	2,206	2,222
Depreciation and amortization	569	500	1,110	987
Taxes other than income taxes	255	245	511	497
Estimated loss on Kemper IGCC	81	23	134	32
Total operating expenses	3,274	3,239	6,326	6,465
Operating Income (Loss)	1,185	1,098	2,125	2,055
Other Income and (Expense):
Allowance for equity funds used during construction	45	39	98	102
Interest expense, net of amounts capitalized	(293)	(180)	(539)	(393)
Other income (expense), net	(29)	(12)	(57)	(19)
Total other income and (expense)	(277)	(153)	(498)	(310)
Earnings (Loss) Before Income Taxes	908	945	1,627	1,745
Income taxes (benefit)	272	302	494	576
Net Income (Loss)	636	643	1,133	1,169
Dividends on preferred and preference stock of subsidiaries	12	14	23	31
Less: Net income attributable to noncontrolling interests	12	0	13	0
Net Income (Loss) After Dividends on Preferred and Preference Stock of Subsidiaries	$ 612	$ 629	$ 1,097	$ 1,138
Earnings per share (EPS) -
Basic EPS (in dollars per share)	$ 0.65	$ 0.69	$ 1.19	$ 1.25
Diluted EPS (in dollars per share)	$ 0.65	$ 0.69	$ 1.18	$ 1.25
Average number of shares of common stock outstanding (in millions)
Basic (in shares)	934	909	925	910
Diluted (in shares)	940	912	931	914
Cash dividends paid per share of common stock (in dollars per share)	$ 0.56	$ 0.5425	$ 1.1025	$ 1.0675
Alabama Power [Member]
Operating Revenues:
Retail revenues	$ 1,316	$ 1,326	$ 2,510	$ 2,594
Wholesale revenues, non-affiliates	67	57	130	123
Wholesale revenues, affiliates	9	20	31	35
Other revenues	52	52	105	104
Total operating revenues	1,444	1,455	2,776	2,856
Operating Expenses:
Fuel	295	343	564	653
Purchased power, non-affiliates	40	45	76	86
Purchased power, affiliates	55	49	88	103
Other operations and maintenance	355	370	747	768
Depreciation and amortization	175	160	347	318
Taxes other than income taxes	94	90	191	184
Total operating expenses	1,014	1,057	2,013	2,112
Operating Income (Loss)	430	398	763	744
Other Income and (Expense):
Allowance for equity funds used during construction	6	14	16	29
Interest expense, net of amounts capitalized	(74)	(69)	(147)	(134)
Other income (expense), net	(4)	(14)	(11)	(18)
Total other income and (expense)	(72)	(69)	(142)	(123)
Earnings (Loss) Before Income Taxes	358	329	621	621
Income taxes (benefit)	142	122	245	235
Net Income (Loss)	216	207	376	386
Dividends on preferred and preference stock of subsidiaries	5	7	9	17
Net Income (Loss) After Dividends on Preferred and Preference Stock of Subsidiaries	211	200	367	369
Georgia Power [Member]
Operating Revenues:
Retail revenues	1,907	1,872	3,624	3,686
Wholesale revenues, non-affiliates	40	50	82	118
Wholesale revenues, affiliates	10	4	15	12
Other revenues	94	90	202	178
Total operating revenues	2,051	2,016	3,923	3,994
Operating Expenses:
Fuel	439	503	815	1,029
Purchased power, non-affiliates	92	78	175	138
Purchased power, affiliates	111	115	250	263
Other operations and maintenance	439	467	896	943
Depreciation and amortization	214	202	425	418
Taxes other than income taxes	100	97	197	195
Total operating expenses	1,395	1,462	2,758	2,986
Operating Income (Loss)	656	554	1,165	1,008
Other Income and (Expense):
Allowance for equity funds used during construction			24	10
Interest expense, net of amounts capitalized	(99)	(93)	(193)	(182)
Other income (expense), net	8	1	26	16
Total other income and (expense)	(91)	(92)	(167)	(166)
Earnings (Loss) Before Income Taxes	565	462	998	842
Income taxes (benefit)	213	180	373	320
Net Income (Loss)	352	282	625	522
Dividends on preferred and preference stock of subsidiaries	5	5	9	9
Net Income (Loss) After Dividends on Preferred and Preference Stock of Subsidiaries	347	277	616	513
Gulf Power [Member]
Operating Revenues:
Retail revenues	319	327	602	620
Wholesale revenues, non-affiliates	15	27	31	52
Wholesale revenues, affiliates	15	13	36	35
Other revenues	16	17	31	34
Total operating revenues	365	384	700	741
Operating Expenses:
Fuel	107	122	201	232
Purchased power, non-affiliates	32	25	62	50
Purchased power, affiliates	4	9	5	17
Other operations and maintenance	77	91	155	185
Depreciation and amortization	42	40	80	60
Taxes other than income taxes	29	28	58	56
Total operating expenses	291	315	561	600
Operating Income (Loss)	74	69	139	141
Other Income and (Expense):
Allowance for equity funds used during construction	0	3	0	8
Interest expense, net of amounts capitalized	(12)	(12)	(25)	(26)
Other income (expense), net	(1)	(1)	(2)	(2)
Total other income and (expense)	(13)	(10)	(27)	(20)
Earnings (Loss) Before Income Taxes	61	59	112	121
Income taxes (benefit)	24	21	44	44
Net Income (Loss)	37	38	68	77
Dividends on preferred and preference stock of subsidiaries	3	3	5	5
Net Income (Loss) After Dividends on Preferred and Preference Stock of Subsidiaries	34	35	63	72
Mississippi Power [Member]
Operating Revenues:
Retail revenues	206	189	389	357
Wholesale revenues, non-affiliates	60	63	120	141
Wholesale revenues, affiliates	7	18	16	45
Other revenues	4	5	8	9
Total operating revenues	277	275	533	552
Operating Expenses:
Fuel	81	115	157	229
Purchased power, non-affiliates	1	2	1	3
Purchased power, affiliates	4	2	9	4
Other operations and maintenance	68	68	136	144
Depreciation and amortization	45	30	84	57
Taxes other than income taxes	25	23	50	48
Estimated loss on Kemper IGCC	81	23	134	32
Total operating expenses	305	263	571	517
Operating Income (Loss)	(28)	12	(38)	35
Other Income and (Expense):
Allowance for equity funds used during construction	30	25	59	53
Interest expense, net of amounts capitalized	(15)	30	(31)	19
Other income (expense), net	(1)	(1)	(3)	(2)
Total other income and (expense)	14	54	25	70
Earnings (Loss) Before Income Taxes	(14)	66	(13)	105
Income taxes (benefit)	(17)	16	(27)	20
Net Income (Loss)	3	50	14	85
Dividends on preferred and preference stock of subsidiaries	1	1	1	1
Net Income (Loss) After Dividends on Preferred and Preference Stock of Subsidiaries	2	49	13	84
Southern Power [Member]
Operating Revenues:
Wholesale revenues, non-affiliates	264	250	480	481
Wholesale revenues, affiliates	107	85	204	199
Other revenues	2	2	4	4
Total operating revenues	373	337	688	684
Operating Expenses:
Fuel	96	105	187	243
Purchased power, non-affiliates	21	18	35	34
Purchased power, affiliates	2	4	8	14
Other operations and maintenance	86	69	162	121
Depreciation and amortization	81	60	154	118
Taxes other than income taxes	6	6	13	12
Total operating expenses	292	262	559	542
Operating Income (Loss)	81	75	129	142
Other Income and (Expense):
Interest expense, net of amounts capitalized	(22)	(23)	(43)	(45)
Other income (expense), net	1	1	1	1
Total other income and (expense)	(21)	(22)	(42)	(44)
Earnings (Loss) Before Income Taxes	60	53	87	98
Income taxes (benefit)	(41)	1	(65)	13
Net Income (Loss)	101	52	152	85
Less: Net income attributable to noncontrolling interests	12	6	13	6
Net income attributable to Southern Power Company	$ 89	$ 46	$ 139	$ 79

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Net Income (loss)	$ 636	$ 643	$ 1,133	$ 1,169
Qualifying hedges:
Changes in fair value, net of tax	(20)	19	(137)	1
Reclassification adjustment for amounts included in net income, net of tax	16	2	18	3
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	1	1	2	3
Total other comprehensive income (loss)	(3)	22	(117)	7
Dividends on preferred and preference stock of subsidiaries	12	14	23	31
Comprehensive income attributable to noncontrolling interests	12	0	13	0
Comprehensive Income (Loss)	609	651	980	1,145
Alabama Power [Member]
Net Income (loss)	216	207	376	386
Qualifying hedges:
Changes in fair value, net of tax	0	5	(2)	1
Reclassification adjustment for amounts included in net income, net of tax	1	0	2	1
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	1	5	0	2
Dividends on preferred and preference stock of subsidiaries	5	7	9	17
Comprehensive Income (Loss)	217	212	376	388
Georgia Power [Member]
Net Income (loss)	352	282	625	522
Qualifying hedges:
Changes in fair value, net of tax	0	14	0	0
Reclassification adjustment for amounts included in net income, net of tax	1	1	1	1
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	1	15	1	1
Dividends on preferred and preference stock of subsidiaries	5	5	9	9
Comprehensive Income (Loss)	353	297	626	523
Gulf Power [Member]
Net Income (loss)	37	38	68	77
Qualifying hedges:
Changes in fair value, net of tax	(1)	0	(4)	0
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	(1)	0	(4)	0
Dividends on preferred and preference stock of subsidiaries	3	3	5	5
Comprehensive Income (Loss)	36	38	64	77
Mississippi Power [Member]
Net Income (loss)	3	50	14	85
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	0	0	0	0
Dividends on preferred and preference stock of subsidiaries	1	1	1	1
Comprehensive Income (Loss)	3	50	14	85
Southern Power [Member]
Net Income (loss)	101	52	152	85
Qualifying hedges:
Changes in fair value, net of tax	(24)	0	(24)	0
Reclassification adjustment for amounts included in net income, net of tax	13	0	14	0
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	(11)	0	(10)	0
Comprehensive income attributable to noncontrolling interests	12	6	13	6
Comprehensive Income (Loss)	$ 78	$ 46	$ 129	$ 79

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Changes in fair value, tax	$ (13)	$ 12	$ (85)	$ 1
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	10	1	11	2
Reclassification adjustment for amounts of pension and other post retirement benefit plans included in net income, tax	0	1	1	2
Alabama Power [Member]
Changes in fair value, tax	0	3	(1)	0
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	0	0	1	1
Georgia Power [Member]
Changes in fair value, tax	0	9	0	0
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	0	0	1	1
Gulf Power [Member]
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	(1)	0	(3)	0
Southern Power [Member]
Changes in fair value, tax	(15)	0	(15)	0
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	$ 8	$ 0	$ 8	$ 0

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($)	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Operating Activities:
Net income (loss)	$ 1,133,000,000	$ 1,169,000,000
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	1,306,000,000	1,171,000,000
Deferred income taxes	279,000,000	783,000,000
Allowance for equity funds used during construction	(98,000,000)	(102,000,000)
Stock based compensation expense	69,000,000	66,000,000
Hedge settlements	(201,000,000)	(3,000,000)
Estimated loss on Kemper IGCC	134,000,000	32,000,000
Income taxes receivable, non-current	0	(444,000,000)
Other, net	(69,000,000)	(3,000,000)
Changes in certain current assets and liabilities —
-Receivables	(197,000,000)	(158,000,000)
-Fossil fuel stock	70,000,000	136,000,000
-Other current assets	(53,000,000)	(99,000,000)
-Accounts payable	(71,000,000)	(311,000,000)
-Accrued taxes	74,000,000	(60,000,000)
-Accrued compensation	(222,000,000)	(269,000,000)
-Mirror CWIP	0	82,000,000
-Other current liabilities	(39,000,000)	117,000,000
Net cash provided from (used for) operating activities	2,115,000,000	2,107,000,000
Investing Activities:
Business acquisitions, net of cash acquired	(897,000,000)	(408,000,000)
Property additions	(3,486,000,000)	(2,239,000,000)
Investment in restricted cash	(8,608,000,000)	0
Distributions of restricted cash	649,000,000	0
Nuclear decommissioning trust fund purchases	(585,000,000)	(933,000,000)
Nuclear decommissioning trust fund sales	580,000,000	928,000,000
Cost of removal, net of salvage	(99,000,000)	(87,000,000)
Change in construction payables	(260,000,000)	56,000,000
Prepaid long-term service agreement	(82,000,000)	(110,000,000)
Other investing activities	113,000,000	27,000,000
Net cash used for investing activities	(12,675,000,000)	(2,766,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	471,000,000	184,000,000
Proceeds —
Long-term debt issuances	12,038,000,000	3,075,000,000
Common stock issuances	1,383,000,000	116,000,000
Short-term borrowings	0	320,000,000
Redemptions and repurchases —
Long-term debt	(1,272,000,000)	(939,000,000)
Interest-bearing refundable deposits	0	(275,000,000)
Common stock	0	(115,000,000)
Preferred and preference stock	0	(412,000,000)
Short-term borrowings	(475,000,000)	(250,000,000)
Distributions to noncontrolling interests	(11,000,000)	(1,000,000)
Capital contributions from noncontrolling interests	179,000,000	78,000,000
Purchase of membership interests from noncontrolling interests	(129,000,000)	0
Payment of common stock dividends	(1,023,000,000)	(972,000,000)
Other financing activities	(108,000,000)	(47,000,000)
Net cash provided from (used for) financing activities	11,053,000,000	762,000,000
Net Change in Cash and Cash Equivalents	493,000,000	103,000,000
Cash and Cash Equivalents at Beginning of Period	1,404,000,000	710,000,000
Cash and Cash Equivalents at End of Period	1,897,000,000	813,000,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	458,000,000	374,000,000
Income taxes, net	(138,000,000)	(16,000,000)
Noncash Investing and Financing Items [Abstract]
Noncash transactions - Accrued property additions at end of period	549,000,000	345,000,000
Alabama Power [Member]
Operating Activities:
Net income (loss)	376,000,000	386,000,000
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	419,000,000	387,000,000
Deferred income taxes	175,000,000	60,000,000
Allowance for equity funds used during construction	(16,000,000)	(29,000,000)
Other, net	(37,000,000)	(23,000,000)
Changes in certain current assets and liabilities —
-Receivables	64,000,000	(115,000,000)
-Fossil fuel stock	(32,000,000)	19,000,000
-Other current assets	(67,000,000)	(52,000,000)
-Accounts payable	(75,000,000)	(212,000,000)
-Accrued taxes	98,000,000	177,000,000
-Accrued compensation	(50,000,000)	(66,000,000)
-Retail fuel cost over recovery - short-term	(60,000,000)	25,000,000
-Other current liabilities	8,000,000	40,000,000
Net cash provided from (used for) operating activities	803,000,000	597,000,000
Investing Activities:
Property additions	(645,000,000)	(612,000,000)
Nuclear decommissioning trust fund purchases	(200,000,000)	(278,000,000)
Nuclear decommissioning trust fund sales	200,000,000	278,000,000
Cost of removal, net of salvage	(51,000,000)	(28,000,000)
Change in construction payables	(27,000,000)	28,000,000
Other investing activities	(18,000,000)	(14,000,000)
Net cash used for investing activities	(741,000,000)	(626,000,000)
Proceeds —
Senior notes issuances	400,000,000	975,000,000
Capital contributions from parent company	237,000,000	10,000,000
Pollution control revenue bonds	0	80,000,000
Other long-term debt	45,000,000	0
Redemptions and repurchases —
Pollution control revenue bonds	0	(134,000,000)
Senior notes	(200,000,000)	(250,000,000)
Preferred and preference stock	0	(412,000,000)
Payment of common stock dividends	(382,000,000)	(286,000,000)
Other financing activities	(13,000,000)	(32,000,000)
Net cash provided from (used for) financing activities	87,000,000	(49,000,000)
Net Change in Cash and Cash Equivalents	149,000,000	(78,000,000)
Cash and Cash Equivalents at Beginning of Period	194,000,000	273,000,000
Cash and Cash Equivalents at End of Period	343,000,000	195,000,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	131,000,000	118,000,000
Income taxes, net	(122,000,000)	47,000,000
Noncash Investing and Financing Items [Abstract]
Noncash transactions - Accrued property additions at end of period	94,000,000	35,000,000
Georgia Power [Member]
Operating Activities:
Net income (loss)	625,000,000	522,000,000
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	530,000,000	512,000,000
Deferred income taxes	157,000,000	(6,000,000)
Allowance for equity funds used during construction	(24,000,000)	(10,000,000)
Deferred expenses	39,000,000	28,000,000
Contract amendment	0	(118,000,000)
Settlement of asset retirement obligations	(52,000,000)	(9,000,000)
Other, net	6,000,000	9,000,000
Changes in certain current assets and liabilities —
-Receivables	(25,000,000)	(21,000,000)
-Fossil fuel stock	61,000,000	101,000,000
-Prepaid income taxes	(1,000,000)	86,000,000
-Other current assets	11,000,000	(38,000,000)
-Accounts payable	6,000,000	(110,000,000)
-Accrued taxes	(137,000,000)	(125,000,000)
-Accrued compensation	(44,000,000)	(61,000,000)
-Other current liabilities	17,000,000	14,000,000
Net cash provided from (used for) operating activities	1,169,000,000	774,000,000
Investing Activities:
Property additions	(1,058,000,000)	(853,000,000)
Nuclear decommissioning trust fund purchases	(386,000,000)	(655,000,000)
Nuclear decommissioning trust fund sales	380,000,000	649,000,000
Cost of removal, net of salvage	(34,000,000)	(46,000,000)
Change in construction payables, net of joint owner portion	(75,000,000)	26,000,000
Prepaid long-term service agreement	(14,000,000)	(40,000,000)
Other investing activities	17,000,000	28,000,000
Net cash used for investing activities	(1,170,000,000)	(891,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	39,000,000	44,000,000
Proceeds —
Senior notes issuances	650,000,000	0
FFB loan	300,000,000	600,000,000
Capital contributions from parent company	239,000,000	23,000,000
Pollution control revenue bonds	0	170,000,000
Short-term borrowings	0	250,000,000
Redemptions and repurchases —
Pollution control revenue bonds	(4,000,000)	(65,000,000)
Senior notes	(500,000,000)	(125,000,000)
Short-term borrowings	0	(250,000,000)
Payment of common stock dividends	(653,000,000)	(517,000,000)
Other financing activities	(16,000,000)	(13,000,000)
Net cash provided from (used for) financing activities	55,000,000	117,000,000
Net Change in Cash and Cash Equivalents	54,000,000	0
Cash and Cash Equivalents at Beginning of Period	67,000,000	24,000,000
Cash and Cash Equivalents at End of Period	121,000,000	24,000,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	174,000,000	170,000,000
Income taxes, net	78,000,000	240,000,000
Noncash Investing and Financing Items [Abstract]
Noncash transactions - Accrued property additions at end of period	288,000,000	171,000,000
Gulf Power [Member]
Operating Activities:
Net income (loss)	68,000,000	77,000,000
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	83,000,000	64,000,000
Deferred income taxes	16,000,000	40,000,000
Allowance for equity funds used during construction	0	(8,000,000)
Other, net	(3,000,000)	3,000,000
Changes in certain current assets and liabilities —
-Receivables	(6,000,000)	(15,000,000)
-Fossil fuel stock	34,000,000	6,000,000
-Prepaid income taxes	2,000,000	12,000,000
-Other current assets	(1,000,000)	1,000,000
-Accounts payable	(7,000,000)	(9,000,000)
-Accrued taxes	17,000,000	15,000,000
-Accrued compensation	(12,000,000)	(10,000,000)
-Other current liabilities	4,000,000	(1,000,000)
Net cash provided from (used for) operating activities	195,000,000	183,000,000
Investing Activities:
Property additions	(68,000,000)	(148,000,000)
Cost of removal, net of salvage	(4,000,000)	(7,000,000)
Change in construction payables	(7,000,000)	(15,000,000)
Other investing activities	(5,000,000)	(4,000,000)
Net cash used for investing activities	(84,000,000)	(174,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	46,000,000	4,000,000
Proceeds —
Common stock issuances	0	20,000,000
Short-term borrowings	0	40,000,000
Redemptions and repurchases —
Senior notes	(125,000,000)	0
Payment of common stock dividends	(60,000,000)	(65,000,000)
Other financing activities	0	(3,000,000)
Net cash provided from (used for) financing activities	(139,000,000)	(4,000,000)
Net Change in Cash and Cash Equivalents	(28,000,000)	5,000,000
Cash and Cash Equivalents at Beginning of Period	74,000,000	39,000,000
Cash and Cash Equivalents at End of Period	46,000,000	44,000,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	28,000,000	26,000,000
Income taxes, net	(3,000,000)	(9,000,000)
Noncash Investing and Financing Items [Abstract]
Noncash transactions - Accrued property additions at end of period	13,000,000	28,000,000
Mississippi Power [Member]
Operating Activities:
Net income (loss)	14,000,000	85,000,000
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	82,000,000	55,000,000
Deferred income taxes	(16,000,000)	694,000,000
Investment tax credits	0	32,000,000
Allowance for equity funds used during construction	(59,000,000)	(53,000,000)
Regulatory assets associated with Kemper IGCC	(10,000,000)	(50,000,000)
Estimated loss on Kemper IGCC	134,000,000	32,000,000
Income taxes receivable, non-current	0	(544,000,000)
Other, net	3,000,000	8,000,000
Changes in certain current assets and liabilities —
-Receivables	15,000,000	6,000,000
-Fossil fuel stock	6,000,000	5,000,000
-Prepaid income taxes	34,000,000	24,000,000
-Other current assets	(3,000,000)	(7,000,000)
-Accounts payable	(12,000,000)	(25,000,000)
-Accrued taxes	19,000,000	(51,000,000)
-Accrued interest	0	(7,000,000)
-Accrued compensation	(12,000,000)	(12,000,000)
-Over recovered regulatory clause revenues	4,000,000	32,000,000
-Mirror CWIP	0	82,000,000
-Customer liability associated with Kemper refunds	(69,000,000)	0
-Other current liabilities	7,000,000	3,000,000
Net cash provided from (used for) operating activities	137,000,000	309,000,000
Investing Activities:
Property additions	(403,000,000)	(428,000,000)
Change in construction payables	(11,000,000)	(15,000,000)
Capital grant proceeds	137,000,000	0
Other investing activities	(19,000,000)	(17,000,000)
Net cash used for investing activities	(296,000,000)	(460,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	0	475,000,000
Proceeds —
Capital contributions from parent company	226,000,000	77,000,000
Short-term borrowings	0	30,000,000
Long-term debt issuance to parent company	200,000,000	0
Other long-term debt	900,000,000	0
Redemptions and repurchases —
Short-term borrowings	(475,000,000)	0
Long-term debt to parent company	(225,000,000)	0
Other long-term debt	(425,000,000)	(350,000,000)
Other financing activities	(3,000,000)	(2,000,000)
Net cash provided from (used for) financing activities	198,000,000	230,000,000
Net Change in Cash and Cash Equivalents	39,000,000	79,000,000
Cash and Cash Equivalents at Beginning of Period	98,000,000	133,000,000
Cash and Cash Equivalents at End of Period	137,000,000	212,000,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	26,000,000	2,000,000
Income taxes, net	(122,000,000)	(181,000,000)
Noncash Investing and Financing Items [Abstract]
Noncash transactions - Accrued property additions at end of period	94,000,000	99,000,000
Issuance of promissory note to parent related to repayment of interest-bearing refundable deposits and accrued interest	0	301,000,000
Southern Power [Member]
Operating Activities:
Net income (loss)	152,000,000	85,000,000
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	159,000,000	121,000,000
Deferred income taxes	(71,000,000)	59,000,000
Investment tax credits	0	153,000,000
Amortization of investment tax credits	(15,000,000)	(10,000,000)
Deferred revenues	(31,000,000)	(21,000,000)
Accrued income taxes, non-current	0	100,000,000
Other, net	9,000,000	10,000,000
Changes in certain current assets and liabilities —
-Receivables	(76,000,000)	(26,000,000)
-Prepaid income taxes	(147,000,000)	(102,000,000)
-Other current assets	5,000,000	5,000,000
-Accounts payable	4,000,000	(31,000,000)
-Accrued taxes	62,000,000	(110,000,000)
-Other current liabilities	0	18,000,000
Net cash provided from (used for) operating activities	51,000,000	251,000,000
Investing Activities:
Business acquisitions, net of cash acquired	(502,000,000)	(408,000,000)
Property additions	(1,281,000,000)	(154,000,000)
Investment in restricted cash	(646,000,000)	0
Distributions of restricted cash	649,000,000	0
Change in construction payables	(137,000,000)	38,000,000
Payments pursuant to long-term service agreements	(43,000,000)	(45,000,000)
Other investing activities	(25,000,000)	(1,000,000)
Net cash used for investing activities	(1,985,000,000)	(570,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	695,000,000	(195,000,000)
Proceeds —
Senior notes issuances	1,241,000,000	650,000,000
Capital contributions from parent company	300,000,000	0
Redemptions and repurchases —
Distributions to noncontrolling interests	(11,000,000)	(1,000,000)
Capital contributions from noncontrolling interests	179,000,000	78,000,000
Purchase of membership interests from noncontrolling interests	(129,000,000)	0
Payment of common stock dividends	(136,000,000)	(65,000,000)
Other financing activities	(13,000,000)	(3,000,000)
Net cash provided from (used for) financing activities	2,126,000,000	464,000,000
Net Change in Cash and Cash Equivalents	192,000,000	145,000,000
Cash and Cash Equivalents at Beginning of Period	830,000,000	75,000,000
Cash and Cash Equivalents at End of Period	1,022,000,000	220,000,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	42,000,000	35,000,000
Income taxes, net	115,000,000	(72,000,000)
Noncash Investing and Financing Items [Abstract]
Noncash transactions - Accrued property additions at end of period	$ 108,000,000	$ 38,000,000

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Condensed Consolidated Statements of Cash Flows (Unaudited) (Parenthetical) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Net cash paid for capitalized interest	$ 61	$ 57
Alabama Power [Member]
Net cash paid for capitalized interest	7	10
Georgia Power [Member]
Net cash paid for capitalized interest	10	5
Gulf Power [Member]
Net cash paid for capitalized interest	0	3
Mississippi Power [Member]
Interest paid	49	39
Net cash paid for capitalized interest	23	37
Southern Power [Member]
Net cash paid for capitalized interest	$ 21	$ 1

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Current Assets:
Cash and cash equivalents	$ 1,897	$ 1,404
Restricted cash and cash equivalents	7,963	0
Receivables —
Customer accounts receivable	1,281	1,058
Unbilled revenues	590	397
Under recovered regulatory clause revenues	12	63
Income taxes receivable, current	0	144
Other accounts and notes receivable	247	398
Accumulated provision for uncollectible accounts	(14)	(13)
Fossil fuel stock, at average cost	798	868
Materials and supplies, at average cost	1,210	1,061
Vacation pay	181	178
Other regulatory assets, current	350	402
Prepaid expenses	563	495
Other current assets	71	71
Total current assets	15,149	6,526
Property, Plant, and Equipment:
In service	78,112	75,118
Less accumulated provision for depreciation	24,778	24,253
Plant in service, net of depreciation	53,334	50,865
Other utility plant, net	174	233
Nuclear fuel, at amortized cost	934	934
Construction work in progress	9,451	9,082
Total property, plant, and equipment	63,893	61,114
Other Property and Investments:
Goodwill	264	2
Other intangible assets, net of amortization	490	317
Nuclear decommissioning trusts, at fair value	1,578	1,512
Leveraged leases	763	755
Miscellaneous property and investments	230	166
Total other property and investments	3,325	2,752
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,580	1,560
Unamortized loss on reacquired debt	220	227
Other regulatory assets, deferred	5,460	4,989
Income taxes receivable, non-current	413	413
Other deferred charges and assets	833	737
Total deferred charges and other assets	8,506	7,926
Total Assets	90,873	78,318
Current Liabilities:
Securities due within one year	2,724	2,674
Notes payable	1,372	1,376
Accounts payable —
Accounts payable	1,493	1,905
Customer deposits	408	404
Accrued taxes —
Accrued income taxes	13	19
Other accrued taxes	398	484
Accrued interest	289	249
Accrued vacation pay	229	228
Accrued compensation	335	549
Asset retirement obligations, current	349	217
Liabilities from risk management activities	95	156
Other regulatory liabilities, current	115	278
Other current liabilities	694	590
Total current liabilities	8,514	9,129
Long-term Debt:
Total Long-term Debt	35,368	24,688
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	12,563	12,322
Deferred credits related to income taxes	183	187
Accumulated deferred investment tax credits	1,427	1,219
Employee benefit obligations	2,485	2,582
Asset retirement obligations, deferred	4,129	3,542
Unrecognized tax benefits	380	370
Other cost of removal obligations	1,154	1,162
Other regulatory liabilities, deferred	335	254
Other deferred credits and liabilities	724	720
Total deferred credits and other liabilities	23,380	22,358
Total Liabilities	67,262	56,175
Redeemable Preferred Stock of Subsidiaries	118	118
Redeemable Noncontrolling Interest	47	43
Common Stockholders' Equity:
Common stock	4,708	4,572
Paid-in capital	7,499	6,282
Treasury, at cost	(30)	(142)
Retained earnings (accumulated deficit)	10,085	10,010
Accumulated other comprehensive income (loss)	(247)	(130)
Total common stockholders' equity	22,015	20,592
Preferred and Preference Stock of Subsidiaries	609	609
Noncontrolling Interests	822	781
Total Stockholders' Equity	23,446	21,982
Total Liabilities and Stockholders' Equity	90,873	78,318
Alabama Power [Member]
Current Assets:
Cash and cash equivalents	343	194
Receivables —
Customer accounts receivable	357	332
Unbilled revenues	174	119
Under recovered regulatory clause revenues	7	43
Income taxes receivable, current	0	142
Other accounts and notes receivable	35	20
Affiliated companies	32	50
Accumulated provision for uncollectible accounts	(9)	(10)
Fossil fuel stock, at average cost	271	239
Materials and supplies, at average cost	412	398
Vacation pay	66	66
Other regulatory assets, current	87	115
Prepaid expenses	100	83
Other current assets	10	10
Total current assets	1,885	1,801
Property, Plant, and Equipment:
In service	25,572	24,750
Less accumulated provision for depreciation	8,889	8,736
Plant in service, net of depreciation	16,683	16,014
Nuclear fuel, at amortized cost	368	363
Construction work in progress	423	801
Total property, plant, and equipment	17,474	17,178
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	69	71
Nuclear decommissioning trusts, at fair value	759	737
Miscellaneous property and investments	101	96
Total other property and investments	929	904
Deferred Charges and Other Assets:
Deferred charges related to income taxes	519	522
Deferred under recovered regulatory clause revenues	136	99
Other regulatory assets, deferred	1,100	1,114
Other deferred charges and assets	113	103
Total deferred charges and other assets	1,868	1,838
Total Assets	22,156	21,721
Current Liabilities:
Securities due within one year	200	200
Accounts payable —
Affiliated accounts payable	293	278
Other accounts payable	294	410
Customer deposits	88	88
Accrued taxes —
Accrued income taxes	10	0
Other accrued taxes	93	38
Accrued interest	80	73
Accrued vacation pay	55	55
Accrued compensation	72	119
Liabilities from risk management activities	17	55
Other regulatory liabilities, current	81	240
Other current liabilities	41	39
Total current liabilities	1,324	1,595
Long-term Debt:
Total Long-term Debt	6,894	6,654
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,413	4,241
Deferred credits related to income taxes	68	70
Accumulated deferred investment tax credits	114	118
Employee benefit obligations	360	388
Asset retirement obligations, deferred	1,502	1,448
Other cost of removal obligations	699	722
Other regulatory liabilities, deferred	106	136
Deferred over recovered regulatory clause revenues	102	0
Other deferred credits and liabilities	69	76
Total deferred credits and other liabilities	7,433	7,199
Total Liabilities	15,651	15,448
Redeemable Preferred Stock	85	85
Preference Stock	196	196
Common Stockholders' Equity:
Common stock	1,222	1,222
Paid-in capital	2,589	2,341
Retained earnings (accumulated deficit)	2,445	2,461
Accumulated other comprehensive income (loss)	(32)	(32)
Total common stockholders' equity	6,224	5,992
Total Liabilities and Stockholders' Equity	22,156	21,721
Georgia Power [Member]
Current Assets:
Cash and cash equivalents	121	67
Receivables —
Customer accounts receivable	592	541
Unbilled revenues	293	188
Joint owner accounts receivable	51	227
Income taxes receivable, current	0	114
Other accounts and notes receivable	52	57
Affiliated companies	16	18
Accumulated provision for uncollectible accounts	(2)	(2)
Fossil fuel stock, at average cost	340	402
Materials and supplies, at average cost	477	449
Vacation pay	93	91
Other regulatory assets, current	123	123
Prepaid income taxes	157	156
Other current assets	55	92
Total current assets	2,368	2,523
Property, Plant, and Equipment:
In service	33,045	31,841
Less accumulated provision for depreciation	11,087	10,903
Plant in service, net of depreciation	21,958	20,938
Other utility plant, net	174	171
Nuclear fuel, at amortized cost	566	572
Construction work in progress	4,655	4,775
Total property, plant, and equipment	27,353	26,456
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	62	64
Nuclear decommissioning trusts, at fair value	819	775
Miscellaneous property and investments	42	43
Total other property and investments	923	882
Deferred Charges and Other Assets:
Deferred charges related to income taxes	677	679
Other regulatory assets, deferred	2,524	2,152
Other deferred charges and assets	170	173
Total deferred charges and other assets	3,371	3,004
Total Assets	34,015	32,865
Current Liabilities:
Securities due within one year	658	712
Notes payable	197	158
Accounts payable —
Affiliated accounts payable	407	411
Other accounts payable	541	750
Customer deposits	268	264
Accrued taxes —
Accrued income taxes	0	12
Other accrued taxes	199	325
Accrued interest	107	99
Accrued vacation pay	64	62
Accrued compensation	88	142
Asset retirement obligations, current	323	179
Other current liabilities	299	181
Total current liabilities	3,151	3,295
Long-term Debt:
Total Long-term Debt	10,120	9,616
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,788	5,627
Deferred credits related to income taxes	104	105
Accumulated deferred investment tax credits	199	204
Employee benefit obligations	901	949
Asset retirement obligations, deferred	2,249	1,737
Other deferred credits and liabilities	302	347
Total deferred credits and other liabilities	9,543	8,969
Total Liabilities	22,814	21,880
Redeemable Preferred Stock	45	45
Preference Stock	221	221
Common Stockholders' Equity:
Common stock	398	398
Paid-in capital	6,527	6,275
Retained earnings (accumulated deficit)	4,024	4,061
Accumulated other comprehensive income (loss)	(14)	(15)
Total common stockholders' equity	10,935	10,719
Total Liabilities and Stockholders' Equity	34,015	32,865
Gulf Power [Member]
Current Assets:
Cash and cash equivalents	46	74
Receivables —
Customer accounts receivable	81	76
Unbilled revenues	77	54
Under recovered regulatory clause revenues	5	20
Income taxes receivable, current	0	27
Other accounts and notes receivable	3	9
Affiliated companies	10	1
Accumulated provision for uncollectible accounts	(1)	(1)
Fossil fuel stock, at average cost	74	108
Materials and supplies, at average cost	56	56
Other regulatory assets, current	65	90
Other current assets	17	22
Total current assets	433	536
Property, Plant, and Equipment:
In service	5,032	5,045
Less accumulated provision for depreciation	1,351	1,296
Plant in service, net of depreciation	3,681	3,749
Other utility plant, net	0	62
Construction work in progress	68	48
Total property, plant, and equipment	3,749	3,859
Other Property and Investments:
Total other property and investments	4	4
Deferred Charges and Other Assets:
Deferred charges related to income taxes	60	61
Other regulatory assets, deferred	523	427
Other deferred charges and assets	49	33
Total deferred charges and other assets	632	521
Total Assets	4,818	4,920
Current Liabilities:
Securities due within one year	195	110
Notes payable	187	142
Accounts payable —
Affiliated accounts payable	46	55
Other accounts payable	44	44
Customer deposits	36	36
Accrued taxes —
Accrued income taxes	5	4
Other accrued taxes	25	9
Accrued interest	8	9
Accrued compensation	13	25
Deferred capacity expense, current	22	22
Liabilities from risk management activities	32	49
Other regulatory liabilities, current	19	22
Other current liabilities	30	40
Total current liabilities	662	567
Long-term Debt:
Total Long-term Debt	987	1,193
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	905	893
Employee benefit obligations	126	129
Deferred capacity expense	130	141
Asset retirement obligations, deferred	128	113
Other cost of removal obligations	237	233
Other regulatory liabilities, deferred	46	47
Other deferred credits and liabilities	90	102
Total deferred credits and other liabilities	1,662	1,658
Total Liabilities	3,311	3,418
Preference Stock	147	147
Common Stockholders' Equity:
Common stock	503	503
Paid-in capital	573	567
Retained earnings (accumulated deficit)	288	285
Accumulated other comprehensive income (loss)	(4)	0
Total common stockholders' equity	1,360	1,355
Total Liabilities and Stockholders' Equity	4,818	4,920
Mississippi Power [Member]
Current Assets:
Cash and cash equivalents	137	98
Receivables —
Customer accounts receivable	35	26
Unbilled revenues	46	36
Income taxes receivable, current	0	20
Other accounts and notes receivable	5	10
Affiliated companies	12	20
Fossil fuel stock, at average cost	99	104
Materials and supplies, at average cost	77	75
Other regulatory assets, current	97	95
Prepaid income taxes	5	39
Other current assets	7	8
Total current assets	520	531
Property, Plant, and Equipment:
In service	4,809	4,886
Less accumulated provision for depreciation	1,248	1,262
Plant in service, net of depreciation	3,561	3,624
Construction work in progress	2,429	2,254
Total property, plant, and equipment	5,990	5,878
Other Property and Investments:
Total other property and investments	11	11
Deferred Charges and Other Assets:
Deferred charges related to income taxes	317	290
Other regulatory assets, deferred	520	525
Income taxes receivable, non-current	544	544
Other deferred charges and assets	85	61
Total deferred charges and other assets	1,466	1,420
Total Assets	7,987	7,840
Current Liabilities:
Securities due within one year	343	728
Notes payable	25	500
Accounts payable —
Affiliated accounts payable	87	85
Other accounts payable	120	135
Customer deposits	16	16
Accrued taxes —
Accrued income taxes	57	0
Other accrued taxes	48	85
Accrued interest	19	18
Accrued compensation	14	26
Asset retirement obligations, current	21	22
Over recovered regulatory clause liabilities	100	96
Customer liability associated with Kemper refunds	5	73
Other current liabilities	41	52
Total current liabilities	896	1,836
Long-term Debt:
Long-term Debt, Affiliated	551	576
Long-term debt, non-affiliated	2,164	1,310
Total Long-term Debt	2,715	1,886
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	773	762
Deferred credits related to income taxes	8	8
Accumulated deferred investment tax credits	5	5
Employee benefit obligations	148	153
Asset retirement obligations, deferred	157	154
Unrecognized tax benefits	368	368
Other cost of removal obligations	169	165
Other regulatory liabilities, deferred	74	71
Other deferred credits and liabilities	40	40
Total deferred credits and other liabilities	1,742	1,726
Total Liabilities	5,353	5,448
Redeemable Preferred Stock	33	33
Common Stockholders' Equity:
Common stock	38	38
Paid-in capital	3,122	2,893
Retained earnings (accumulated deficit)	(553)	(566)
Accumulated other comprehensive income (loss)	(6)	(6)
Total common stockholders' equity	2,601	2,359
Total Liabilities and Stockholders' Equity	7,987	7,840
Southern Power [Member]
Current Assets:
Cash and cash equivalents	1,022	830
Receivables —
Customer accounts receivable	115	75
Other accounts and notes receivable	23	19
Affiliated companies	60	30
Fossil fuel stock, at average cost	14	16
Materials and supplies, at average cost	120	63
Prepaid income taxes	192	45
Other current assets	31	30
Total current assets	1,577	1,108
Property, Plant, and Equipment:
In service	8,348	7,275
Less accumulated provision for depreciation	1,374	1,248
Plant in service, net of depreciation	6,974	6,027
Construction work in progress	1,852	1,137
Total property, plant, and equipment	8,826	7,164
Other Property and Investments:
Goodwill	2	2
Other intangible assets, net of amortization	316	317
Total other property and investments	318	319
Deferred Charges and Other Assets:
Prepaid long-term service agreements	165	166
Other deferred charges and assets -- affiliated	23	9
Other deferred charges and assets	173	139
Total deferred charges and other assets	361	314
Total Assets	11,082	8,905
Current Liabilities:
Securities due within one year	403	403
Notes payable	831	137
Accounts payable —
Affiliated accounts payable	80	66
Other accounts payable	175	327
Accrued taxes —
Accrued income taxes	9	198
Other accrued taxes	16	5
Accrued interest	22	23
Contingent consideration	23	36
Other current liabilities	69	44
Total current liabilities	1,628	1,239
Long-term Debt:
Total Long-term Debt	3,929	2,719
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	524	601
Accumulated deferred investment tax credits	1,107	889
Accrued income taxes, non-current	109	109
Asset retirement obligations, deferred	28	21
Deferred capacity revenues -- affiliated	7	17
Other deferred credits and liabilities	105	3
Total deferred credits and other liabilities	1,880	1,640
Total Liabilities	7,437	5,598
Redeemable Noncontrolling Interest	47	43
Common Stockholders' Equity:
Common stock	0	0
Paid-in capital	2,121	1,822
Retained earnings (accumulated deficit)	661	657
Accumulated other comprehensive income (loss)	(6)	4
Total common stockholders' equity	2,776	2,483
Noncontrolling Interests, Total	822	781
Total Stockholders' Equity	3,598	3,264
Total Liabilities and Stockholders' Equity	$ 11,082	$ 8,905

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Other intangible assets, accumulated amortization	$ 14	$ 12
Common stock, par value (in dollars per share)	$ 5	$ 5
Common stock, shares authorized	1,500,000,000.0	1,500,000,000.0
Common stock, shares issued	942,000,000	915,000,000
Treasury shares at cost	800,000	3,400,000
Alabama Power [Member]
Common stock, par value (in dollars per share)	$ 40	$ 40
Common stock, shares authorized	40,000,000	40,000,000
Common stock, shares outstanding	30,537,500	30,537,500
Georgia Power [Member]
Common stock, no par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares outstanding	9,261,500	9,261,500
Gulf Power [Member]
Common stock, no par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares outstanding	5,642,717	5,642,717
Mississippi Power [Member]
Common stock, no par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized	1,130,000	1,130,000
Common stock, shares outstanding	1,121,000	1,121,000
Southern Power [Member]
Other intangible assets, accumulated amortization	$ 14	$ 12
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	1,000,000	1,000,000
Common stock, shares outstanding	1,000	1,000

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Introduction

6 Months Ended

Jun. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

INTRODUCTION

INTRODUCTION

The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 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 June 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.

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 unchangedand 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. 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 Southern Company and the traditional electric operating companies' 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 in 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 $102 million made by Georgia Power to PowerSecure under the two agreements since inception in 2014 are included in CWIP at June 30, 2016. PowerSecure construction service costs of approximately $13 million are included in accounts payable, affiliated in Georgia Power's balance sheet at June 30, 2016. The facilities will be owned and operated by Georgia Power and are expected to be operational by the end of 2016. The ultimate outcome of this matter cannot be determined at this time.

See Note (I) under "Southern Company– Acquisition of PowerSecure International, Inc." for additional information regarding Southern Company's acquisition of PowerSecure.

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 the EPA's regulation of CCR.

The cost estimates below are based on information as of June 30, 2016 using 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.

As of June 30, 2016, details of the asset retirement obligations (ARO) 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	9			5			—			—			—			4
Liabilities settled	(66		)	(6		)	(52		)	(1		)	(7		)	—
Accretion	77			36			34			1			2			1
Cash flow revisions	699			19			673			3			6			2
Balance at end of period	$	4,478		$	1,502		$	2,571		$	133		$	178		$	28

The traditional electric operating companies' increases in cash flow revisions for the six months ended June 30, 2016 primarily relate to changes in ash pond closure strategy. The increase for Georgia Power was due to 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

Goodwill and other intangible assets consisted of the following:

	At June 30, 2016
	Estimated Useful Life	Gross Carrying Amount		Accumulated Amortization			Intangible Assets, Net
		(in millions)
Intangibles subject to amortization:
Southern Company
Customer relationships	14-26 years	$	47	$	—		$	47
Trade names	5-9 years	43		—			43
Patents	3-10 years	4		—			4
Backlog	5 years	5		—			5
Southern Power
PPA fair value adjustments	20 years	330		(14		)	316
Total intangibles subject to amortization		$	429	$	(14	)	$	415
Intangibles not subject to amortization:
Southern Company
Federal Communications Commission licenses		$	75	$	—		$	75
Goodwill:
Southern Company		$	262	$	—		$	262
Southern Power		2		—			2
Total goodwill and other intangible assets		$	768	$	(14	)	$	754

Amortization expense associated with intangible assets during the three and six months ended June 30, 2016 was immaterial.

Intangibles at December 31, 2015 consisted primarily of Southern Power's PPA fair value adjustments with a net carrying amount of $317 million. The increases in goodwill and other intangibles relate to Southern Company's acquisition of PowerSecure on May 9, 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. See Note (I) under "Southern Company– Acquisition of PowerSecure International, Inc." for additional information regarding Southern Company's acquisition of PowerSecure.

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Contingencies and Regulatory Matters

6 Months Ended

Jun. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

CONTINGENCIES AND REGULATORY MATTERS

CONTINGENCIES AND REGULATORY MATTERS

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

General Litigation Matters

Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, 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 have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs.

Georgia Power's environmental remediation liability as of June 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 June 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.

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. 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. The increase is primarily due to the Plant Daniel Units 1 and 2 scrubbers, which were placed in service in November 2015. 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 $8 million through the Kemper IGCC's projected in-service date of October 31, 2016.

Fuel Cost Recovery

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At June 30, 2016, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $23 million compared to $24 million at December 31, 2015. 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.

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	June 30, 2016		December 31, 2015
		(in millions)
Rate CNP Compliance	Under recovered regulatory clause revenues	$	7	$	43
	Deferred under recovered regulatory clause revenues	21		—
Rate CNP PPA	Deferred under recovered regulatory clause revenues	115		99
Retail Energy Cost Recovery	Other regulatory liabilities, current	75		238
	Deferred over recovered regulatory clause revenues	102		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	72		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 May 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 "Fuel Cost Recovery" 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 – Fuel Cost Recovery" and " – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery and the NCCR tariff, respectively.

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 (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. Georgia Power exercised its contractual option to sell its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc., with an expected closing date in late August 2016.

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 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. 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 2019 general base rate case.

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 June 30, 2016 and December 31, 2015, Georgia Power's over recovered fuel balance totaled $164 million and $116 million, respectively, and is included in current liabilities and other deferred liabilities on Southern Company's and Georgia Power'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.

Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's or Georgia Power's revenues or net income, but will affect cash flow.

Nuclear Construction

See Note 3 to the financial statements of Southern Company and Georgia Power under "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.

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 (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) as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated Vogtle Owner's costs associated with the proposed 18-month Contractor delay 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. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service and contemplated in a general base rate case, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.

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 $250 million had been paid as of June 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.

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. The Staff is conducting a review of all costs incurred related to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the Contractor Settlement Agreement, and is authorized to engage in related settlement discussions with Georgia Power and any intervenors.

The order provides that the Staff is required to report to the Georgia PSC by October 19, 2016 with respect to the status of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of Plant Vogtle Units 3 and 4, the Georgia PSC will then conduct a hearing to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing Georgia Power to file a request for an amendment to the certificate for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority.

The Georgia PSC has approved thirteen VCM reports covering the periods through June 30, 2015, including construction capital costs incurred, which through that date totaled $3.1 billion. On February 26, 2016, Georgia Power filed its fourteenth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2015. The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. Georgia Power is requesting approval of $160 million of construction capital costs incurred during that period. Georgia Power incurred approximately $141 million in total construction capital costs during the period of January 1, 2016 through June 30, 2016. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.7 billion as of June 30, 2016. The in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion, of which $1.1 billion had been incurred through June 30, 2016.

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, assembly, delivery, and installation of plant equipment, the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS 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

Retail Base Rate Case

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 for additional information.

In 2013, the Florida PSC approved a settlement agreement that authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through June 2017. In any given month, such depreciation reduction 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, 2015, and the first six months of 2016, Gulf Power recognized reductions in depreciation of $8.4 million, $20.1 million, and $6.4 million, respectively.

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 Location	June 30, 2016		December 31, 2015
		(in millions)
Fuel Cost Recovery	Other regulatory liabilities, current	$	18	$	18
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	4		1
Environmental Cost Recovery	Under recovered regulatory clause revenues	1		19
Energy Conservation Cost Recovery	Other regulatory liabilities, current	—		4

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

Fuel Cost Recovery

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

At June 30, 2016, the amount of over-recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet was $76 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 of February. As required by the order, on February 1, 2016, Mississippi Power submitted updated natural gas price forecasts and resulting fuel factors to the Mississippi PSC. If approved by the Mississippi PSC, the updated forecast would decrease fuel cost recovery rates by an additional $36 million annually. The ultimate outcome of this matter cannot be determined at this time.

Integrated Coal Gasification Combined Cycle

See Note 3 to the financial statements of 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

Construction of Mississippi Power's Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. 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 in-service date for the remainder of the Kemper IGCC is currently expected to occur by October 31, 2016, which reflects a one-month extension. The initial production of syngas began on July 14, 2016 and testing has continued on gasifier 'B' and the related lignite feed and ash systems. The schedule extension provides for time to complete mechanical equipment modifications to the gasifiers' supporting systems to increase capacity to the levels necessary to complete the remaining start-up activities and achieve sustained operations on both gasifiers. The remaining schedule also reflects the time expected to complete the initial operation and testing of the facility's syngas clean-up systems, as well as 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 June 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	$	5.43		$	5.15
Lignite Mine and Equipment	0.21		0.23			0.23
CO2 Pipeline Facilities	0.14		0.11			0.12
AFUDC(d)	0.17		0.72			0.66
Combined Cycle and Related Assets Placed in Service – Incremental(e)	—		0.03			0.02
General Exceptions	0.05		0.10			0.09
Deferred Costs(e)	—		0.20			0.19
Additional DOE Grants(f)	—		(0.14		)	(0.14		)
Total Kemper IGCC	$	2.97	$	6.68		$	6.32

(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 reflect estimated costs through October 31, 2016.

(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 June 30, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, are not included in the Current Cost Estimate and the Actual Costs at June 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.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of June 30, 2016, $3.59 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 $2.55 billion), $6 million in other property and investments, $81 million in fossil fuel stock, $46 million in materials and supplies, $35 million in other regulatory assets, current, $180 million in other regulatory assets, deferred, $1 million in other current assets, and $11 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 $81 million ($50 million after tax) in the second quarter 2016 and a total of $134 million ($83 million after tax) for the six months ended June 30, 2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.55 billion ($1.57 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through June 30, 2016. The increase to the cost estimate in 2016 primarily reflects costs for the extension of the Kemper IGCC's projected in-service date through October 31, 2016 and increased efforts related to operational readiness and challenges in start-up and commissioning activities, which includes the cost of repairs and modifications associated with the lignite feed process and the refractory lining for the gasifiers. Any extension of the in-service date beyond October 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 October 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 $14 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. Significant testing activities, including those for coal feed and gasification systems, as well as the initial operation and testing of the facility's gas clean-up systems and production of clean syngas, and, ultimately the generation of electricity, remain in process. 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, 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 to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's and Mississippi Power's statements of income and these changes could be material.

Rate Recovery of Kemper IGCC Costs

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.

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. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed 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 in September 2015, subject to refund and certain other conditions.

On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full a stipulation 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.

Pursuant to the In-Service Asset Rate Order, Mississippi Power is required to file a subsequent rate request within 18 months. As part of the filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation.

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.

Mississippi Power expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at June 30, 2016 of $6.68 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, and additional carrying costs. Mississippi Power will seek approval from the Mississippi PSC to defer these costs for future rate recovery to be determined in connection with the final Kemper IGCC cost recovery approach ultimately approved. See "Regulatory Assets and Liabilities" below for additional information.

Regulatory Assets and Liabilities

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

In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015 and 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 June 30, 2016, the balance associated with these regulatory assets was $114 million, of which $35 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $101 million as of June 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 "2013 MPSC Rate Order" herein for information related to the July 7, 2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP. Also see "FERC Matters" herein for information related to the 2016 settlement agreement with wholesale customers.

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.

The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. At June 30, 2016, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $5 million. See "2015 Rate Case" herein 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, 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. 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 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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Fair Value Measurements

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

As of June 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 June 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	$	—	$	36	$	—	$	—	$	36
Interest rate derivatives	—		27		—		—		27
Nuclear decommissioning trusts(a)	642		917		—		18		1,577
Cash equivalents	1,014		—		—		—		1,014
Other investments	9		—		1		—		10
Total	$	1,665	$	980	$	1	$	18	$	2,664
Liabilities:
Energy-related derivatives	$	—	$	110	$	—	$	—	$	110
Interest rate derivatives	—		7		—		—		7
Foreign currency derivatives	—		38		—		—		38
Total	$	—	$	155	$	—	$	—	$	155
Alabama Power
Assets:
Energy-related derivatives	$	—	$	10	$	—	$	—	$	10
Nuclear decommissioning trusts(b)
Domestic equity	363		67		—		—		430
Foreign equity	46		47		—		—		93
U.S. Treasury and government agency securities	—		24		—		—		24
Corporate bonds	21		142		—		—		163
Mortgage and asset backed securities	—		22		—		—		22
Private Equity	—		—		—		18		18
Other	—		8		—		—		8
Cash equivalents	210		—		—		—		210
Total	$	640	$	320	$	—	$	18	$	978
Liabilities:
Energy-related derivatives	$	—	$	22	$	—	$	—	$	22

	Fair Value Measurements Using
As of June 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	—		14		—		—		14
Nuclear decommissioning trusts(b) (c)
Domestic equity	187		1		—		—		188
Foreign equity	—		116		—		—		116
U.S. Treasury and government agency securities	—		109		—		—		109
Municipal bonds	—		57		—		—		57
Corporate bonds	—		159		—		—		159
Mortgage and asset backed securities	—		159		—		—		159
Other	25		6		—		—		31
Cash equivalents	90		—		—		—		90
Total	$	302	$	636	$	—	$	—	$	938
Liabilities:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Gulf Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	—	$	2
Cash equivalents	20		—		—		—		20
Total	$	20	$	2	$	—	$	—	$	22
Liabilities:
Energy-related derivatives	$	—	$	55	$	—	$	—	$	55
Interest rate derivatives	—		7		—		—		7
Total	$	—	$	62	$	—	$	—	$	62
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	—	$	1
Cash equivalents	102		—		—		—		102
Total	$	102	$	1	$	—	$	—	$	103
Liabilities:
Energy-related derivatives	$	—	$	23	$	—	$	—	$	23

	Fair Value Measurements Using
As of June 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	$	—	$	8	$	—	$	—	$	8
Cash equivalents	449		—		—		—		449
Total	$	449	$	8	$	—	$	—	$	457
Liabilities:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Foreign currency derivatives	—		38		—		—		38
Total	$	—	$	43	$	—	$	—	$	43

(a) For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.

(b) Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies.

(c) Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of June 30, 2016, approximately $46 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 $28 million and $48 million, respectively, for the three and six months ended June 30, 2016, and decreased by $1 million and increased by $31 million, respectively, for the three and six months ended June 30, 2015. Alabama Power recorded an increase in fair value of $29 million and $40 million, respectively, for the three and six months ended June 30, 2016 and $5 million and $19 million, respectively, for the three and six months ended June 30, 2015 as a change in regulatory liabilities related to its AROs. Georgia Power recorded a decrease in fair value of $1 million and an increase of $8 million, respectively, for the three and six months ended June 30, 2016 and a decrease in fair value of $6 million and an increase in fair value of $12 million, respectively, for the three and six months ended June 30, 2015 as a change in its regulatory asset related to its AROs.

Valuation Methodologies

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

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

"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 June 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 June 30, 2016:	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company	$	18	$	28	Not Applicable	Not Applicable
Alabama Power	$	18	$	28	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.

As of June 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	$	37,953	$	40,992
Alabama Power	$	7,090	$	7,940
Georgia Power	$	10,603	$	11,881
Gulf Power	$	1,182	$	1,275
Mississippi Power	$	2,983	$	2,967
Southern Power	$	4,332	$	4,523

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.

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Stockholders' Equity

6 Months Ended

Jun. 30, 2016

Equity [Abstract]

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY

Earnings per Share

For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:

	Three Months Ended June 30, 2016	Three Months Ended June 30, 2015	Six Months Ended June 30, 2016	Six Months Ended June 30, 2015
	(in millions)
As reported shares	934	909	925	910
Effect of options and performance share award units	6	3	6	4
Diluted shares	940	912	931	914

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 andsix months ended June 30, 2016, respectively, and were 15 million and 1 million for the three and six months ended June 30, 2015, respectively.

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	—	—		1,097			—			—			1,097
Other comprehensive income (loss)	—	—		(117		)	—			—			(117		)
Stock issued	27,297	2,599		1,383			—			—			1,383
Stock-based compensation	—	—		82			—			—			82
Cash dividends on common stock	—	—		(1,023		)	—			—			(1,023		)
Contributions from noncontrolling interests	—	—		—			—			169			169
Distributions to noncontrolling interests	—	—		—			—			(10		)	(10		)
Purchase of membership interests from noncontrolling interests	—	—		—			—			(129		)	(129		)
Net income attributable to noncontrolling interests	—	—		—			—			11			11
Other	—	(19	)	1			—			—			1
Balance at June 30, 2016	942,370	(772	)	$	22,015		$	609		$	822		$	23,446
Balance at December 31, 2014	908,502	(725	)	$	19,949		$	756		$	221		$	20,926
Consolidated net income attributable to Southern Company	—	—		1,138			—			—			1,138
Other comprehensive income (loss)	—	—		7			—			—			7
Stock issued	3,222	—		117			—			—			117
Stock-based compensation	—	—		66			—			—			66
Stock repurchased, at cost	—	(2,599	)	(115		)	—			—			(115		)
Cash dividends on common stock	—	—		(972		)	—			—			(972		)
Preference stock redemption	—	—		—			(150		)	—			(150		)
Contributions from noncontrolling interests	—	—		—			—			135			135
Distributions to noncontrolling interests	—	—		—			—			(5		)	(5		)
Net income attributable to noncontrolling interests	—	—		—			—			4			4
Other	—	25		(8		)	3			—			(5		)
Balance at June 30, 2015	911,724	(3,299	)	$	20,182		$	609		$	355		$	21,146

(*) Primarily related to Southern Power Company.

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Financing

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

FINANCING

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 June 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 June 30, 2016, the traditional electric operating companies had approximately $320 million (comprised of approximately $87 million at Alabama Power, $212 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 June 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	3		32		500		800		1,335		1,335		—		—		—		35
Georgia Power	—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	75		40		165		—		280		280		45		—		45		70
Mississippi Power	115		60		—		—		175		150		—		15		15		160
Southern Power Company(b)	—		—		—		600		600		560		—		—		—		—
Other	25		45		—		40		110		80		20		—		20		50
Total	$	218	$	177	$	1,665	$	4,440	$	6,500	$	6,387	$	65	$	15	$	80	$	315

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

(b) Excluding its subsidiaries. See "Southern Power Project Credit Facilities" below and Note (I) under "Southern Power" for additional information.

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 Tranquillity LLC, RE Roserock LLC, and RE Garland Holdings 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. Proceeds from the Project Credit Facilities are being used to finance project costs related to the respective solar facilities currently under construction. 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 June 30, 2016.

Project	Maturity Date	Construction Loan Facility		Bridge Loan Facility		Loan Facility Total		Total Loan Facility Undrawn		Letter of Credit Facility		Total Letter of Credit Facility Undrawn
		(in millions)
Tranquillity	Earlier of PPA COD or December 31, 2016	$	86	$	172	$	258	$	19	$	77	$	26
Roserock	Earlier of PPA COD or November 30, 2016	63		180		243		34		23		16
Garland	Earlier of PPA COD or November 30, 2016	86		308		394		73		49		23
Total		$	235	$	660	$	895	$	126	$	149	$	65

The Project Credit Facilities had total amounts outstanding as of June 30, 2016 of $769 million at a weighted average interest rate of 2.02%. For the three-month period ended June 30, 2016, these credit agreements had a maximum amount outstanding of $769 million and an average amount outstanding of $586 million at a weighted average interest rate of 2.03%.

Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six 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	$	8,500	$	—	$	—	$	—		$	—
Alabama Power	400		200		—		45			—
Georgia Power	650		500		4		300			3
Gulf Power	—		125		—		—			—
Mississippi Power	—		—		—		1,100			651
Southern Power	1,241		—		—		2			4
Other	—		—		—		—			10
Elimination(b)	—		—		—		(200		)	(225		)
Total	$	10,791	$	825	$	4	$	1,247		$	443

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

(b) 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 Merger and related transaction costs and for other general corporate purposes.

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 power generation facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar power or wind generation 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. The interest rate applicable to the $300 million principal amount is 2.571% for an interest period that extends to 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

In January 2016, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $275 million, which matures on December 1, 2017, bearing interest based on one-month LIBOR. As of June 30, 2016, Mississippi Power had borrowed $100 million under this promissory note with a $50 million draw occurring on each of January 29, 2016 and March 14, 2016. In addition, on January 19, 2016, Mississippi Power borrowed $100 million from Southern Company pursuant to a promissory note issued in November 2015. 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 existing promissory note issued in November 2015. As of June 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.

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 to repay existing indebtedness and for other general corporate purposes. Mississippi Power borrowed $900 million under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016, upon satisfaction of certain customary conditions. Mississippi Power used the initial proceeds to repay $900 million in maturing bank notes on March 8, 2016 and expects the remaining $300 million to be used to repay senior notes maturing in October 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR.

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.

Southern Power

During the six months ended June 30, 2016, Southern Power's subsidiaries borrowed an additional $632 million pursuant to the Project Credit Facilities at a weighted average interest rate of 2.00%. In addition, Southern Power's subsidiaries issued $16 million in letters of credit.

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 will be 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.

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Retirement Benefits

6 Months Ended

Jun. 30, 2016

Compensation and Retirement Disclosure [Abstract]

RETIREMENT BENEFITS

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.

Components of the net periodic benefit costs for the three and six months ended June 30, 2016 and 2015 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended June 30, 2016
Service cost	$	62		$	15		$	18		$	3		$	3
Interest cost	101			24			34			4			5
Expected return on plan assets	(187		)	(46		)	(65		)	(8		)	(8		)
Amortization:
Prior service costs	3			—			2			1			—
Net (gain)/loss	37			10			13			1			1
Net cost	$	16		$	3		$	2		$	1		$	1
Six Months Ended June 30, 2016
Service cost	$	124		$	29		$	35		$	6		$	6
Interest cost	201			48			68			9			10
Expected return on plan assets	(374		)	(92		)	(129		)	(17		)	(17		)
Amortization:
Prior service costs	7			1			3			1			—
Net (gain)/loss	75			20			27			3			3
Net cost	$	33		$	6		$	4		$	2		$	2
Three Months Ended June 30, 2015
Service cost	$	64		$	15		$	18		$	3		$	3
Interest cost	111			27			39			5			6
Expected return on plan assets	(181		)	(44		)	(63		)	(8		)	(9		)
Amortization:
Prior service costs	7			1			2			—			1
Net (gain)/loss	54			13			19			2			2
Net cost	$	55		$	12		$	15		$	2		$	3
Six Months Ended June 30, 2015
Service cost	$	128		$	30		$	36		$	6		$	6
Interest cost	222			53			77			10			11
Expected return on plan assets	(362		)	(89		)	(126		)	(16		)	(17		)
Amortization:
Prior service costs	13			3			5			—			1
Net (gain)/loss	108			27			38			5			5
Net cost	$	109		$	24		$	30		$	5		$	6

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended June 30, 2016
Service cost	$	6		$	2		$	1		$	1		$	1
Interest cost	17			4			7			—			1
Expected return on plan assets	(14		)	(7		)	(5		)	(1		)	(1		)
Amortization:
Prior service costs	1			1			1			—			—
Net (gain)/loss	4			1			2			—			—
Net cost	$	14		$	1		$	6		$	—		$	1
Six Months Ended June 30, 2016
Service cost	$	11		$	3		$	3		$	1		$	1
Interest cost	35			9			15			1			2
Expected return on plan assets	(28		)	(13		)	(11		)	(1		)	(1		)
Amortization:
Prior service costs	3			2			1			—			—
Net (gain)/loss	7			1			4			—			—
Net cost	$	28		$	2		$	12		$	1		$	2
Three Months Ended June 30, 2015
Service cost	$	5		$	2		$	1		$	—		$	1
Interest cost	20			5			9			1			1
Expected return on plan assets	(14		)	(7		)	(6		)	(1		)	(1		)
Amortization:
Prior service costs	1			—			—			—			—
Net (gain)/loss	4			1			3			—			—
Net cost	$	16		$	1		$	7		$	—		$	1
Six Months Ended June 30, 2015
Service cost	$	11		$	3		$	3		$	—		$	1
Interest cost	39			10			17			2			2
Expected return on plan assets	(29		)	(13		)	(12		)	(1		)	(1		)
Amortization:
Prior service costs	2			1			—			—			—
Net (gain)/loss	9			1			6			—			—
Net cost	$	32		$	2		$	14		$	1		$	2

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Income Taxes

6 Months Ended

Jun. 30, 2016

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for additional tax information.

Current and Deferred Income Taxes

Tax Credit Carryforwards

Southern Company has federal ITC and PTC carryforwards totaling $801 million and $16 million, respectively, at June 30, 2016 (comprised primarily of $784 million and $16 million of ITC and PTC carryforwards, respectively, at Southern Power). These ITC and PTC carryforwards increased from $554 million and $1 million, respectively, as of December 31, 2015 (comprised primarily of $551 million and $1 million of ITC and PTC carryforwards, respectively, at Southern Power). Additionally, Southern Company has $208 million of state ITC carryforwards for the state of Georgia as of June 30, 2016, compared to $188 million at December 31, 2015.

The federal ITC carryforwards as of June 30, 2016 begin expiring in 2034 but are expected to be utilized by the end of 2021. The PTC carryforwards as of June 30, 2016 begin expiring in 2035 but are expected to be utilized by the end of 2020. The state ITC carryforwards for the state of Georgia as of June 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 30.4% for the six months ended June 30, 2016 compared to 32.9% 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 and increased tax benefits related to the estimated probable losses on Mississippi Power's construction of the Kemper IGCC, partially offset by the impact of additional state income tax benefits recognized in 2015.

Mississippi Power

Mississippi Power's effective tax rate (benefit rate) was (205.6)%for the six months ended June 30,2016 compared to 19.0% for the corresponding period in 2015. The effective tax rate decrease was primarily due to increased tax benefits related to the estimated probable losses on construction of the Kemper IGCC.

Southern Power

Southern Power's effective tax rate (benefit rate) was (74.0)%for the six months ended June 30,2016 compared to 13.7% 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.

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	—		9		10
Balance as of June 30, 2016	$	421	$	17	$	443

The tax positions from current periods primarily relate to federal income tax benefits from ITCs impacting the estimated annual effective tax rate for interim reporting purposes.

The impact on the effective tax rate, if recognized, is as follows:

	As of June 30, 2016							As of December 31, 2015
	Mississippi Power			Southern Power		Southern Company		Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	(2	)	$	17	$	20	$	10
Tax positions not impacting the effective tax rate	423			—		423		423
Balance of unrecognized tax benefits	$	421		$	17	$	443	$	433

The tax positions impacting the effective tax rate primarily relate to federal income tax benefits from ITCs. The tax positions not impacting the effective tax rate relate to 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.

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 and 2014 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.

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. The IRS is currently reviewing the underlying support for the deduction, but has not completed its audit of these expenditures. 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 $423 million and associated interest of $15 million as of June 30, 2016. The ultimate outcome of this matter cannot be determined at this time.

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Derivatives

6 Months Ended

Jun. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES

DERIVATIVES

Southern Company, the traditional electric operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate 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 gross 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

The traditional electric operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional electric operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, 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) and Southern Power have limited exposure to market volatility in commodity fuel prices and prices of electricity because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity.

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' 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 industry. 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 June 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	250	2020	2016
Alabama Power	60	2019	—
Georgia Power	82	2019	—
Gulf Power	66	2020	—
Mississippi Power	29	2019	—
Southern Power	13	2017	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 3 million mmBtu for Southern Company and Georgia Power.

For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending June 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.

At June 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 June 30, 2016
	(in millions)							(in millions)
Cash Flow Hedges of Forecasted Debt
Gulf Power	$	80		3-month LIBOR	2.32%	December 2026		$	(7	)
Cash Flow Hedges of Existing Debt
Southern Company	8		(d)	3-month LIBOR	1.73%	June 2020		—
Southern Company	3		(d)	3-month LIBOR	1.73%	June 2020		—
Georgia Power	200			3-month LIBOR + 0.40%	1.01%	August 2016		—
Fair Value Hedges of Existing Debt
Southern Company	250			1.30%	3-month LIBOR + 0.17%	August 2017		2
Southern Company	300			2.75%	3-month LIBOR + 0.92%	June 2020		11
Georgia Power	250			5.40%	3-month LIBOR + 4.02%	June 2018		3
Georgia Power	200			4.25%	3-month LIBOR + 2.46%	December 2019		6
Georgia Power	500			1.95%	3-month LIBOR + 0.76%	December 2018		5
Derivatives not Designated as Hedges
Southern Power	65		(a,d)	3-month LIBOR	2.50%	October 2016	(e)	—
Southern Power	47		(b,d)	3-month LIBOR	2.21%	October 2016	(e)	—
Southern Power	65		(c,d)	3-month LIBOR	2.21%	November 2016	(f)	—
Total	$	1,968						$	20

(a) 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.

(b) 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.

(c) 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.

(d) Amortizing notional amount.

(e) Represents the mandatory settlement date. Settlement will be based on a 15-year amortizing swap.

(f) 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 June 30, 2017 are immaterial for all registrants. Southern Company and certain subsidiaries have deferred gains and losses that are expected to be amortized into earnings through 2046.

Foreign Currency Derivatives

Southern Company and certain subsidiaries may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time that the hedged transactions affect earnings, including 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 June 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 June 30, 2016
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	(17	)
Southern Power	564		3.78%	500		1.85%	June 2026	(21		)
Total	$	1,241		€	1,100			$	(38	)

The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to earnings for the next 12-month period ending June 30, 2017 are $(24) million for Southern Company and Southern Power.

Derivative Financial Statement Presentation and Amounts

At June 30, 2016, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:

Asset Derivatives at June 30, 2016
	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:
Other current assets	$	12	$	5	$	6	$	1	$	—
Other deferred charges and assets	16		5		9		1		1
Total derivatives designated as hedging instruments for regulatory purposes	$	28	$	10	$	15	$	2	$	1	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets	$	5	$	—	$	—	$	—	$	—	$	5
Other deferred charges and assets	1		—		—		—		—		1
Interest rate derivatives:
Other current assets	11		—		6		—		—		—
Other deferred charges and assets	16		—		8		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	33	$	—	$	14	$	—	$	—	$	6
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets	$	2	$	—	$	—	$	—	$	—	$	2
Total asset derivatives	$	63	$	10	$	29	$	2	$	1	$	8

Liability Derivatives at June 30, 2016
	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(*)	$	61	$	17	$	4	$	25	$	15
Other deferred credits and liabilities	44		5		1		30		8
Total derivatives designated as hedging instruments for regulatory purposes	$	105	$	22	$	5	$	55	$	23	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities(*)	$	3	$	—	$	—	$	—	$	—	$	3
Other deferred credits and liabilities	1		—		—		—		—		1
Interest rate derivatives:
Liabilities from risk management activities(*)	7		—		—		7		—		—
Foreign currency derivatives:
Liabilities from risk management activities(*)	24		—		—		—		—		24
Other deferred credits and liabilities	14		—		—		—		—		14
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	49	$	—	$	—	$	7	$	—	$	42
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current liabilities	$	1	$	—	$	—	$	—	$	—	$	1
Total liability derivatives	$	155	$	22	$	5	$	62	$	23	$	43

(*) Georgia Power, Mississippi Power, and Southern Power include current liabilities related to derivatives in "Other current liabilities."

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		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	3	$	1	$	2	$	—	$	—	N/A
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

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."

The derivative contracts of Southern Company, the traditional electric operating companies, and Southern Power are not subject to master netting arrangements or similar agreements and 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, interest rate derivative contracts, and foreign currency derivative contracts at June 30, 2016 and December 31, 2015 are presented in the following tables.

Derivative Contracts at June 30, 2016
	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)	$	36		$	10		$	15		$	2		$	1		$	8
Gross amounts not offset in the Balance Sheet (b)	(32		)	(8		)	(4		)	(2		)	(1		)	(3		)
Net energy-related derivative assets	$	4		$	2		$	11		$	—		$	—		$	5
Interest rate and foreign currency derivatives:
Interest rate and foreign currency derivatives presented in the Balance Sheet (a)	$	27		$	—		$	14		$	—		$	—		$	—
Gross amounts not offset in the Balance Sheet (b)	(18		)	—			—			—			—			—
Net interest rate and foreign currency derivative assets	$	9		$	—		$	14		$	—		$	—		$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	110		$	22		$	5		$	55		$	23		$	5
Gross amounts not offset in the Balance Sheet (b)	(32		)	(8		)	(4		)	(2		)	(1		)	(3		)
Net energy-related derivative liabilities	$	78		$	14		$	1		$	53		$	22		$	2
Interest rate and foreign currency derivatives:
Interest rate and foreign currency derivatives presented in the Balance Sheet (a)	$	45		$	—		$	—		$	7		$	—		$	38
Gross amounts not offset in the Balance Sheet (b)	(18		)	—			—			—			—			—
Net interest rate and foreign currency derivative liabilities	$	27		$	—		$	—		$	7		$	—		$	38

(a) None of the registrants offsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.

(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

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) None of the registrants offsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.

(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

At June 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 on the Balance Sheet at June 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	$	(61	)	$	(17	)	$	(4	)	$	(25	)	$	(15	)
Other regulatory assets, deferred	(44		)	(5		)	(1		)	(30		)	(8		)
Other regulatory liabilities, current (a)	12			5			6			1			—
Other regulatory liabilities, deferred (b)	16			5			9			1			1
Total energy-related derivative gains (losses)	$	(77	)	$	(12	)	$	10		$	(53	)	$	(22	)

(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 on 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.

For the three months ended June 30, 2016 and 2015, the pre-tax effects of 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
Interest rate derivatives	$	6		$	31	Interest expense, net of amounts capitalized	$	(4	)	$	(2	)
Foreign currency derivatives	(39		)	—		Interest expense, net of amounts capitalized	(1		)	—
						Other income (expense), net	(20		)	—
Total	$	(33	)	$	31		$	(25	)	$	(2	)
Alabama Power
Interest rate derivatives	$	—		$	7	Interest expense, net of amounts capitalized	$	(2	)	$	(1	)
Georgia Power
Interest rate derivatives	$	—		$	24	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Gulf Power
Interest rate derivatives	$	(2	)	$	—	Interest expense, net of amounts capitalized	$	—		$	—
Southern Power
Foreign currency derivatives	$	(39	)	$	—	Interest expense, net of amounts capitalized	$	(1	)	$	—
						Other income (expense), net	(20		)	—
Total	$	(39	)	$	—		$	(21	)	$	—

For the six months ended June 30, 2016 and 2015, the pre-tax effects of 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
Interest rate derivatives	$	(184	)	$	2	Interest expense, net of amounts capitalized	$	(7	)	$	(4	)
Foreign currency derivatives	(39		)	—		Interest expense, net of amounts capitalized	(1		)	—
						Other income (expense), net	(20		)	—
Total	$	(223	)	$	2		$	(28	)	$	(4	)
Alabama Power
Interest rate derivatives	$	(4	)	$	1	Interest expense, net of amounts capitalized	$	(3	)	$	(1	)
Georgia Power
Interest rate derivatives	$	—		$	1	Interest expense, net of amounts capitalized	$	(2	)	$	(2	)
Gulf Power
Interest rate derivatives	$	(7	)	$	—	Interest expense, net of amounts capitalized	$	—		$	—
Mississippi Power
Interest rate derivatives	$	—		$	—	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Southern Power
Interest rate derivatives	$	—		$	—	Interest expense, net of amounts capitalized	$	(1	)	$	—
Foreign currency derivatives	(39		)	—		Interest expense, net of amounts capitalized	(1		)	—
						Other income (expense), net	(20		)	—
Total	$	(39	)	$	—		$	(22	)	$	—

For the three and six months ended June 30, 2016 and 2015, the pre-tax effects of energy-related derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were immaterial for all registrants.

For the three months ended June 30, 2016 and 2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were immaterial on a gross basis for all registrants.

For the six months ended June 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)
Derivative Category	Statements of Income Location	2016		2015
		(in millions)
Southern Company
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	24	$	4
Georgia Power
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	15	$	2

For the three and six months ended June 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 six months ended June 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

The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At June 30, 2016, the registrants' collateral posted with their derivative counterparties was immaterial.

At June 30, 2016, the fair value of derivative liabilities with contingent features was $24 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 $24 million and include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade.

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.

Southern Company, the traditional electric operating companies, and Southern Power are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional electric operating companies, and Southern Power 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, and Southern Power 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', and Southern Power's exposure to counterparty credit risk. 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.

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Acquisitions

6 Months Ended

Jun. 30, 2016

Business Combinations [Abstract]

ACQUISITIONS

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.

The Merger will be accounted for using the acquisition method of accounting whereby the assets acquired and liabilities assumed are recognized at fair value as of the acquisition date. The excess of the purchase price over the fair values of Southern Company Gas' assets and liabilities will be recorded as goodwill. The following table presents the preliminary purchase price allocation:

Southern Company Gas Purchase Price	June 30, 2016
	(in millions)
Current assets	$	1,474
Property, plant, and equipment	9,795
Goodwill	6,333
Intangible assets	436
Regulatory assets	846
Other assets	273
Current liabilities	(2,205		)
Other liabilities	(4,529		)
Long-term debt	(4,261		)
Noncontrolling interests	(160		)
Total purchase price	$	8,002

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 may have a material impact on the results of operations and financial position of Southern Company.

During the three and six months ended June 30, 2016, Southern Company recorded in its statements of income external transaction costs for financing, legal, and consulting services associated with the Merger of approximately $43.4 million and $63.3 million, respectively, of which $26.9 million and $32.9 million is included in operating expenses and $16.5 million and $30.4 million is included in other income and (expense), respectively.

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 leading 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 aggregate purchase price was allocated on a preliminary basis to the assets acquired and liabilities assumed based upon the current determination of fair values at the date of acquisition. The preliminary allocation of the purchase price is as follows:

PowerSecure Purchase Price	June 30, 2016
	(in millions)
Current assets	$	174
Property, plant, and equipment	48
Goodwill	262
Intangible assets	99
Other assets	8
Current liabilities	(111		)
Long-term debt, including current portion	(47		)
Deferred credits and other liabilities	(4		)
Total purchase price	$	429

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $262 million was recognized as goodwill, which is primarily attributable to the 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. Assumptions and estimates underlying the fair value adjustments are subject to change pending further review of the assets acquired and liabilities assumed.

The preliminary valuation of identifiable intangible assets included customer relationships, trade names, patents, and backlog with estimated lives of three 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.

Natural Gas Pipeline Venture

On July 10, 2016, Southern Company and Kinder Morgan, Inc. (Kinder Morgan) entered into a definitive agreement under which Southern Company will acquire a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG), which is the owner of a 7,600-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, Alabama, and the Gulf of Mexico to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. Southern Company expects to finance the purchase price of approximately $1.5 billion with a mix of equity and debt in a credit-supportive manner. Southern Company's investment in SNG will be accounted for under the equity method of accounting.

The transaction is subject to the notification and clearance and reporting requirements under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Southern Company and Kinder Morgan expect to complete the transaction in the third quarter or early in the fourth quarter 2016. The ultimate outcome of this matter cannot be determined at this time.

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 six months ended June 30, 2016, the fair values of the assets and liabilities acquired of Garland, Garland A, Lost Hills Blackwell, Morelos, North Star, and Roserock were finalized and there were no changes.

During 2016, in accordance with its overall growth strategy, Southern Power acquired or contracted to acquire through its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC or Southern Renewable Energy, Inc., 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.

Project Facility	Resource	Seller; Acquisition Date	Approx. Nameplate Capacity	Location	Southern Power Percentage Ownership			Expected/Actual COD	PPA Counterparties for Plant Output	PPA Contract Period
			(MW)
Acquisitions for the Six Months Ended June 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	%		Fourth quarter 2016	Austin Energy	15 years
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
Passadumkeag	Wind	Quantum Utility Generation, LLC June 30, 2016	42	Penobscot County, ME	100	%		July 2016	Western Massachusetts Electric Company	15 years
Acquisitions Subsequent to June 30, 2016
Henrietta	Solar	SunPower Corp. July 1, 2016	102	Kings County, CA	51	%	(*)	July 2016	Pacific Gas and Electric Company	20 years
Lamesa	Solar	RES America Developments Inc. July 1, 2016	102	Dawson County, TX	100	%		Second quarter 2017	City of Garland, Texas	15 years
Rutherford	Solar	Cypress Creek Renewables, LLC July 1, 2016	74	Rutherford County, NC	90	%		Fourth quarter 2016	Duke Energy Carolinas, LLC	15 years

(*) 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.

Acquisitions During the Six Months Ended June 30, 2016

Southern Power's aggregate purchase price for the project facilities acquired during the six months ended June 30, 2016 is approximately $477 million, which includes $6 million of contingent consideration. Including the minority owner Turner Renewable Energy, LLC's (TRE) 10% ownership interest in Calipatria, the total aggregate purchase price is approximately $483 million for the project facilities acquired during the six months ended June 30, 2016. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: $426 million as CWIP, $58 million as property, plant, and equipment, $4 million as other assets, and $7 million as accounts payable; however, the allocations of the purchase price to individual assets have not been finalized. For East Pecos, which is currently under construction, total construction costs, excluding the acquisition costs, are expected to be approximately $160 million to $180 million. The ultimate outcome of this matter cannot be determined at this time.

Acquisitions Subsequent to June 30, 2016

Southern Power's aggregate purchase price for acquisitions subsequent to June 30, 2016 is approximately $275 million. Including the minority owner, SunPower Corp.'s 49% ownership interest in Henrietta, and TRE's 10% ownership interest in Rutherford, the aggregate total purchase price is approximately $447 million for the project facilities acquired subsequent to June 30, 2016. The aggregate purchase price includes the assumption of $217 million in construction debt (non-recourse to Southern Power). For Lamesa and Rutherford, which are currently under construction, total aggregate construction costs, excluding the acquisition costs, are expected to be approximately $260 million to $300 million. The ultimate outcome of these matters cannot be determined at this time.

Acquisition Agreements Executed but Not Yet Closed

During the six months ended June 30, 2016 and subsequent to that date, Southern Power entered into agreements to acquire the following projects for an aggregate purchase price of $1.1 billion: 100% ownership interests in two wind facilities totaling 299 MWs in Texas, significantly covered with PPAs for the first 12 to 14 years of operation; a 51% ownership interest (through 100% ownership of the Class A membership interests entitling Southern Power to 51% of all cash distributions and significantly all of the federal tax benefits) in a 100-MW solar facility in Nevada with a 20-year PPA; and a 90.1% ownership interest in a 257-MW wind facility in Texas significantly covered with a 12-year PPA. These acquisitions are expected to close in the third and fourth quarters of 2016. 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 six months ended June 30, 2016 included in the consolidated statement of income for year-to-date 2016 is $4 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 six months ended June 30, 2016 included in the consolidated statement 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 six months ended June 30, 2016, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service the Butler Solar Farm and Pawpaw solar facilities. In addition, Southern Power continued construction of the projects set forth in the table below. Through June 30, 2016, total costs of construction incurred for the projects below were $2.7 billion, of which $1.7 billion remains in CWIP. Including the total construction costs incurred to date and the acquisition prices allocated to CWIP, total aggregate construction costs for the projects below are estimated to be approximately $3.0 billion to $3.2 billion. The ultimate outcome of these matters cannot be determined at this time.

Solar Facility	Seller	Approx. Nameplate Capacity	Location	Expected/Actual COD	PPA Counterparties for Plant Output	PPA Contract Period
		(MW)
Butler	CERSM, LLC and Community Energy, Inc.	103	Taylor County, GA	Fourth quarter 2016	Georgia Power(a)	30 years
Desert Stateline(b)	First Solar Development, LLC	299(c)	San Bernardino County, CA	Through third quarter 2016	Southern California Edison Company (SCE)	20 years
Garland and Garland A	Recurrent Energy, LLC	205	Kern County, CA	Fourth quarter 2016 and Third quarter 2016	SCE	15 years and 20 years
Roserock	Recurrent Energy, LLC	160	Pecos County, TX	Fourth quarter 2016	Austin Energy	20 years
Sandhills	N/A	146	Taylor County, GA	Fourth quarter 2016	Cobb, Flint, Irwin, Middle Georgia and Sawnee Electric Membership Corporations	25 years
Tranquillity	Recurrent Energy, LLC	205	Fresno County, CA	July 2016	Shell Energy North America (US), LP/SCE	18 years

(a) Butler - Affiliate PPA approved by the FERC.

(b) Desert Stateline - 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. Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized.

(c) Desert Stateline - The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 152 MWs were placed in service during the six months ended June 30, 2016. Subsequent to June 30, 2016, 37 MWs were placed in service.

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Segment and Related Information

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

SEGMENT AND RELATED INFORMATION

SEGMENT AND RELATED INFORMATION

The primary business of the Southern Company system is electricity sales by the traditional electric operating companies and Southern Power. 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 generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market.

Southern Company's reportable business segments are the sale of electricity by the four traditional electric operating companies and Southern Power. Revenues from sales by Southern Power to the traditional electric operating companies were $107 million and $204 million for the three and six months ended June 30, 2016, respectively, and $85 million and $199 million for the three and six months ended June 30, 2015, respectively. The "All Other" column includes parent Southern Company, 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.

Financial data for business segments and products and services for the three and six months ended June 30, 2016 and 2015 was as follows:

	Electric Utilities
	Traditional Electric Operating Companies		Southern Power		Eliminations			Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2016:
Operating revenues	$	4,115	$	373	$	(109	)	$	4,379	$	125		$	(45	)	$	4,459
Segment net income (loss)(a)(b)	595		89		—			684		(68		)	(4		)	612
Six Months Ended June 30, 2016:
Operating revenues	$	7,884	$	688	$	(212	)	$	8,360	$	172		$	(81	)	$	8,451
Segment net income (loss)(a)(c)	1,059		139		—			1,198		(94		)	(7		)	1,097
Total assets at June 30, 2016	$	70,706	$	11,082	$	(425	)	$	81,363	$	10,505		$	(995	)	$	90,873
Three Months Ended June 30, 2015:
Operating revenues	$	4,077	$	337	$	(90	)	$	4,324	$	43		$	(30	)	$	4,337
Segment net income (loss)(a)(b)	561		46		—			607		18			4			629
Six Months Ended June 30, 2015:
Operating revenues	$	8,025	$	684	$	(213	)	$	8,496	$	83		$	(59	)	$	8,520
Segment net income (loss)(a)(c)	1,038		79		—			1,117		21			—			1,138
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 $81 million ($50 million after tax) and $23 million ($14 million after tax) for the three months ended June 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 $134 million ($83 million after tax) and $32 million ($20 million after tax) for the six months ended June 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 June 30, 2016	$	3,748	$	446	$	185	$	4,379
Three Months Ended June 30, 2015	3,714		448		162		4,324
Six Months Ended June 30, 2016	$	7,124	$	842	$	394	$	8,360
Six Months Ended June 30, 2015	7,256		915		325		8,496

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Introduction (Policies)

6 Months Ended

Jun. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Accounting

The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 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 June 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.

Reclassification

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

Recently Issued Accounting Standards

Recently Issued Accounting Standards

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 unchangedand 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. 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 Southern Company and the traditional electric operating companies' 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 in 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.

Asset Retirement Obligations

The cost estimates below are based on information as of June 30, 2016 using 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.

As of June 30, 2016, details of the asset retirement obligations (ARO) 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	9			5			—			—			—			4
Liabilities settled	(66		)	(6		)	(52		)	(1		)	(7		)	—
Accretion	77			36			34			1			2			1
Cash flow revisions	699			19			673			3			6			2
Balance at end of period	$	4,478		$	1,502		$	2,571		$	133		$	178		$	28

The traditional electric operating companies' increases in cash flow revisions for the six months ended June 30, 2016 primarily relate to changes in ash pond closure strategy. The increase for Georgia Power was due to 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.

Valuation Methodologies

Valuation Methodologies

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

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

"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.

Earnings per Share

Earnings per Share

For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on the stock option and performance share plans. The effect of both stock options and performance share award units was determined using the treasury stock method.

Energy-Related Derivatives and Interest Rate Derivatives

Interest Rate Derivatives

Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Southern Company, the traditional electric operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate 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 gross 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

The traditional electric operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional electric operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, 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) and Southern Power have limited exposure to market volatility in commodity fuel prices and prices of electricity because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity.

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' 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 industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

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Introduction (Tables)

6 Months Ended

Jun. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Asset Retirement Obligations

As of June 30, 2016, details of the asset retirement obligations (ARO) 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	9			5			—			—			—			4
Liabilities settled	(66		)	(6		)	(52		)	(1		)	(7		)	—
Accretion	77			36			34			1			2			1
Cash flow revisions	699			19			673			3			6			2
Balance at end of period	$	4,478		$	1,502		$	2,571		$	133		$	178		$	28

Schedule of Goodwill and Other Intangible Assets

Goodwill and other intangible assets consisted of the following:

	At June 30, 2016
	Estimated Useful Life	Gross Carrying Amount		Accumulated Amortization			Intangible Assets, Net
		(in millions)
Intangibles subject to amortization:
Southern Company
Customer relationships	14-26 years	$	47	$	—		$	47
Trade names	5-9 years	43		—			43
Patents	3-10 years	4		—			4
Backlog	5 years	5		—			5
Southern Power
PPA fair value adjustments	20 years	330		(14		)	316
Total intangibles subject to amortization		$	429	$	(14	)	$	415
Intangibles not subject to amortization:
Southern Company
Federal Communications Commission licenses		$	75	$	—		$	75
Goodwill:
Southern Company		$	262	$	—		$	262
Southern Power		2		—			2
Total goodwill and other intangible assets		$	768	$	(14	)	$	754

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Contingencies and Regulatory Matters (Tables)

6 Months Ended

Jun. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Recovery Balance of Each Regulatory Clause

The balance of each regulatory clause recovery on the balance sheet follows:

Regulatory Clause	Balance Sheet Location	June 30, 2016		December 31, 2015
		(in millions)
Fuel Cost Recovery	Other regulatory liabilities, current	$	18	$	18
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	4		1
Environmental Cost Recovery	Under recovered regulatory clause revenues	1		19
Energy Conservation Cost Recovery	Other regulatory liabilities, current	—		4

The balance of each regulatory clause recovery on the balance sheet follows:

Regulatory Clause	Balance Sheet Line Item	June 30, 2016		December 31, 2015
		(in millions)
Rate CNP Compliance	Under recovered regulatory clause revenues	$	7	$	43
	Deferred under recovered regulatory clause revenues	21		—
Rate CNP PPA	Deferred under recovered regulatory clause revenues	115		99
Retail Energy Cost Recovery	Other regulatory liabilities, current	75		238
	Deferred over recovered regulatory clause revenues	102		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	72		75

Current And Actual Cost Estimate for Kemper IGCC

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 June 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	$	5.43		$	5.15
Lignite Mine and Equipment	0.21		0.23			0.23
CO2 Pipeline Facilities	0.14		0.11			0.12
AFUDC(d)	0.17		0.72			0.66
Combined Cycle and Related Assets Placed in Service – Incremental(e)	—		0.03			0.02
General Exceptions	0.05		0.10			0.09
Deferred Costs(e)	—		0.20			0.19
Additional DOE Grants(f)	—		(0.14		)	(0.14		)
Total Kemper IGCC	$	2.97	$	6.68		$	6.32

(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 reflect estimated costs through October 31, 2016.

(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 June 30, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, are not included in the Current Cost Estimate and the Actual Costs at June 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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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Assets and liabilities measured at fair value on a recurring basis

As of June 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 June 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	$	—	$	36	$	—	$	—	$	36
Interest rate derivatives	—		27		—		—		27
Nuclear decommissioning trusts(a)	642		917		—		18		1,577
Cash equivalents	1,014		—		—		—		1,014
Other investments	9		—		1		—		10
Total	$	1,665	$	980	$	1	$	18	$	2,664
Liabilities:
Energy-related derivatives	$	—	$	110	$	—	$	—	$	110
Interest rate derivatives	—		7		—		—		7
Foreign currency derivatives	—		38		—		—		38
Total	$	—	$	155	$	—	$	—	$	155
Alabama Power
Assets:
Energy-related derivatives	$	—	$	10	$	—	$	—	$	10
Nuclear decommissioning trusts(b)
Domestic equity	363		67		—		—		430
Foreign equity	46		47		—		—		93
U.S. Treasury and government agency securities	—		24		—		—		24
Corporate bonds	21		142		—		—		163
Mortgage and asset backed securities	—		22		—		—		22
Private Equity	—		—		—		18		18
Other	—		8		—		—		8
Cash equivalents	210		—		—		—		210
Total	$	640	$	320	$	—	$	18	$	978
Liabilities:
Energy-related derivatives	$	—	$	22	$	—	$	—	$	22

	Fair Value Measurements Using
As of June 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	—		14		—		—		14
Nuclear decommissioning trusts(b) (c)
Domestic equity	187		1		—		—		188
Foreign equity	—		116		—		—		116
U.S. Treasury and government agency securities	—		109		—		—		109
Municipal bonds	—		57		—		—		57
Corporate bonds	—		159		—		—		159
Mortgage and asset backed securities	—		159		—		—		159
Other	25		6		—		—		31
Cash equivalents	90		—		—		—		90
Total	$	302	$	636	$	—	$	—	$	938
Liabilities:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Gulf Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	—	$	2
Cash equivalents	20		—		—		—		20
Total	$	20	$	2	$	—	$	—	$	22
Liabilities:
Energy-related derivatives	$	—	$	55	$	—	$	—	$	55
Interest rate derivatives	—		7		—		—		7
Total	$	—	$	62	$	—	$	—	$	62
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	—	$	1
Cash equivalents	102		—		—		—		102
Total	$	102	$	1	$	—	$	—	$	103
Liabilities:
Energy-related derivatives	$	—	$	23	$	—	$	—	$	23

	Fair Value Measurements Using
As of June 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	$	—	$	8	$	—	$	—	$	8
Cash equivalents	449		—		—		—		449
Total	$	449	$	8	$	—	$	—	$	457
Liabilities:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Foreign currency derivatives	—		38		—		—		38
Total	$	—	$	43	$	—	$	—	$	43

(a) For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.

(b) Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies.

(c) Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of June 30, 2016, approximately $46 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program.

Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments

As of June 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 June 30, 2016:	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company	$	18	$	28	Not Applicable	Not Applicable
Alabama Power	$	18	$	28	Not Applicable	Not Applicable

Financial instruments for which carrying amount did not equal fair value

As of June 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	$	37,953	$	40,992
Alabama Power	$	7,090	$	7,940
Georgia Power	$	10,603	$	11,881
Gulf Power	$	1,182	$	1,275
Mississippi Power	$	2,983	$	2,967
Southern Power	$	4,332	$	4,523

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Stockholders' Equity (Tables)

6 Months Ended

Jun. 30, 2016

Equity [Abstract]

Earnings per Share

Shares used to compute diluted earnings per share were as follows:

	Three Months Ended June 30, 2016	Three Months Ended June 30, 2015	Six Months Ended June 30, 2016	Six Months Ended June 30, 2015
	(in millions)
As reported shares	934	909	925	910
Effect of options and performance share award units	6	3	6	4
Diluted shares	940	912	931	914

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	—	—		1,097			—			—			1,097
Other comprehensive income (loss)	—	—		(117		)	—			—			(117		)
Stock issued	27,297	2,599		1,383			—			—			1,383
Stock-based compensation	—	—		82			—			—			82
Cash dividends on common stock	—	—		(1,023		)	—			—			(1,023		)
Contributions from noncontrolling interests	—	—		—			—			169			169
Distributions to noncontrolling interests	—	—		—			—			(10		)	(10		)
Purchase of membership interests from noncontrolling interests	—	—		—			—			(129		)	(129		)
Net income attributable to noncontrolling interests	—	—		—			—			11			11
Other	—	(19	)	1			—			—			1
Balance at June 30, 2016	942,370	(772	)	$	22,015		$	609		$	822		$	23,446
Balance at December 31, 2014	908,502	(725	)	$	19,949		$	756		$	221		$	20,926
Consolidated net income attributable to Southern Company	—	—		1,138			—			—			1,138
Other comprehensive income (loss)	—	—		7			—			—			7
Stock issued	3,222	—		117			—			—			117
Stock-based compensation	—	—		66			—			—			66
Stock repurchased, at cost	—	(2,599	)	(115		)	—			—			(115		)
Cash dividends on common stock	—	—		(972		)	—			—			(972		)
Preference stock redemption	—	—		—			(150		)	—			(150		)
Contributions from noncontrolling interests	—	—		—			—			135			135
Distributions to noncontrolling interests	—	—		—			—			(5		)	(5		)
Net income attributable to noncontrolling interests	—	—		—			—			4			4
Other	—	25		(8		)	3			—			(5		)
Balance at June 30, 2015	911,724	(3,299	)	$	20,182		$	609		$	355		$	21,146

(*) Primarily related to Southern Power Company.

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Financing (Tables)

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Credit arrangements by company

The following table outlines the committed credit arrangements by company as of June 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	3		32		500		800		1,335		1,335		—		—		—		35
Georgia Power	—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	75		40		165		—		280		280		45		—		45		70
Mississippi Power	115		60		—		—		175		150		—		15		15		160
Southern Power Company(b)	—		—		—		600		600		560		—		—		—		—
Other	25		45		—		40		110		80		20		—		20		50
Total	$	218	$	177	$	1,665	$	4,440	$	6,500	$	6,387	$	65	$	15	$	80	$	315

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

(b) Excluding its subsidiaries. See "Southern Power Project Credit Facilities" below and Note (I) under "Southern Power" for additional information.

The table below summarizes each Project Credit Facility as of June 30, 2016.

Project	Maturity Date	Construction Loan Facility		Bridge Loan Facility		Loan Facility Total		Total Loan Facility Undrawn		Letter of Credit Facility		Total Letter of Credit Facility Undrawn
		(in millions)
Tranquillity	Earlier of PPA COD or December 31, 2016	$	86	$	172	$	258	$	19	$	77	$	26
Roserock	Earlier of PPA COD or November 30, 2016	63		180		243		34		23		16
Garland	Earlier of PPA COD or November 30, 2016	86		308		394		73		49		23
Total		$	235	$	660	$	895	$	126	$	149	$	65

Schedule of Long-term Debt Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six 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	$	8,500	$	—	$	—	$	—		$	—
Alabama Power	400		200		—		45			—
Georgia Power	650		500		4		300			3
Gulf Power	—		125		—		—			—
Mississippi Power	—		—		—		1,100			651
Southern Power	1,241		—		—		2			4
Other	—		—		—		—			10
Elimination(b)	—		—		—		(200		)	(225		)
Total	$	10,791	$	825	$	4	$	1,247		$	443

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

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

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Retirement Benefits (Tables)

6 Months Ended

Jun. 30, 2016

Compensation and Retirement Disclosure [Abstract]

Pension Plans and Postretirement Plans

Components of the net periodic benefit costs for the three and six months ended June 30, 2016 and 2015 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended June 30, 2016
Service cost	$	62		$	15		$	18		$	3		$	3
Interest cost	101			24			34			4			5
Expected return on plan assets	(187		)	(46		)	(65		)	(8		)	(8		)
Amortization:
Prior service costs	3			—			2			1			—
Net (gain)/loss	37			10			13			1			1
Net cost	$	16		$	3		$	2		$	1		$	1
Six Months Ended June 30, 2016
Service cost	$	124		$	29		$	35		$	6		$	6
Interest cost	201			48			68			9			10
Expected return on plan assets	(374		)	(92		)	(129		)	(17		)	(17		)
Amortization:
Prior service costs	7			1			3			1			—
Net (gain)/loss	75			20			27			3			3
Net cost	$	33		$	6		$	4		$	2		$	2
Three Months Ended June 30, 2015
Service cost	$	64		$	15		$	18		$	3		$	3
Interest cost	111			27			39			5			6
Expected return on plan assets	(181		)	(44		)	(63		)	(8		)	(9		)
Amortization:
Prior service costs	7			1			2			—			1
Net (gain)/loss	54			13			19			2			2
Net cost	$	55		$	12		$	15		$	2		$	3
Six Months Ended June 30, 2015
Service cost	$	128		$	30		$	36		$	6		$	6
Interest cost	222			53			77			10			11
Expected return on plan assets	(362		)	(89		)	(126		)	(16		)	(17		)
Amortization:
Prior service costs	13			3			5			—			1
Net (gain)/loss	108			27			38			5			5
Net cost	$	109		$	24		$	30		$	5		$	6

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended June 30, 2016
Service cost	$	6		$	2		$	1		$	1		$	1
Interest cost	17			4			7			—			1
Expected return on plan assets	(14		)	(7		)	(5		)	(1		)	(1		)
Amortization:
Prior service costs	1			1			1			—			—
Net (gain)/loss	4			1			2			—			—
Net cost	$	14		$	1		$	6		$	—		$	1
Six Months Ended June 30, 2016
Service cost	$	11		$	3		$	3		$	1		$	1
Interest cost	35			9			15			1			2
Expected return on plan assets	(28		)	(13		)	(11		)	(1		)	(1		)
Amortization:
Prior service costs	3			2			1			—			—
Net (gain)/loss	7			1			4			—			—
Net cost	$	28		$	2		$	12		$	1		$	2
Three Months Ended June 30, 2015
Service cost	$	5		$	2		$	1		$	—		$	1
Interest cost	20			5			9			1			1
Expected return on plan assets	(14		)	(7		)	(6		)	(1		)	(1		)
Amortization:
Prior service costs	1			—			—			—			—
Net (gain)/loss	4			1			3			—			—
Net cost	$	16		$	1		$	7		$	—		$	1
Six Months Ended June 30, 2015
Service cost	$	11		$	3		$	3		$	—		$	1
Interest cost	39			10			17			2			2
Expected return on plan assets	(29		)	(13		)	(12		)	(1		)	(1		)
Amortization:
Prior service costs	2			1			—			—			—
Net (gain)/loss	9			1			6			—			—
Net cost	$	32		$	2		$	14		$	1		$	2

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Income Taxes (Tables)

6 Months Ended

Jun. 30, 2016

Income Tax Disclosure [Abstract]

Change in Unrecognized Tax Benefits

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	—		9		10
Balance as of June 30, 2016	$	421	$	17	$	443

Impact on Effective Tax Rate, If Recognized

The impact on the effective tax rate, if recognized, is as follows:

	As of June 30, 2016							As of December 31, 2015
	Mississippi Power			Southern Power		Southern Company		Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	(2	)	$	17	$	20	$	10
Tax positions not impacting the effective tax rate	423			—		423		423
Balance of unrecognized tax benefits	$	421		$	17	$	443	$	433

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Derivatives (Tables)

6 Months Ended

Jun. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of energy-related derivatives

At June 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	250	2020	2016
Alabama Power	60	2019	—
Georgia Power	82	2019	—
Gulf Power	66	2020	—
Mississippi Power	29	2019	—
Southern Power	13	2017	2016

Schedule of interest rate derivatives

At June 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 June 30, 2016
	(in millions)							(in millions)
Cash Flow Hedges of Forecasted Debt
Gulf Power	$	80		3-month LIBOR	2.32%	December 2026		$	(7	)
Cash Flow Hedges of Existing Debt
Southern Company	8		(d)	3-month LIBOR	1.73%	June 2020		—
Southern Company	3		(d)	3-month LIBOR	1.73%	June 2020		—
Georgia Power	200			3-month LIBOR + 0.40%	1.01%	August 2016		—
Fair Value Hedges of Existing Debt
Southern Company	250			1.30%	3-month LIBOR + 0.17%	August 2017		2
Southern Company	300			2.75%	3-month LIBOR + 0.92%	June 2020		11
Georgia Power	250			5.40%	3-month LIBOR + 4.02%	June 2018		3
Georgia Power	200			4.25%	3-month LIBOR + 2.46%	December 2019		6
Georgia Power	500			1.95%	3-month LIBOR + 0.76%	December 2018		5
Derivatives not Designated as Hedges
Southern Power	65		(a,d)	3-month LIBOR	2.50%	October 2016	(e)	—
Southern Power	47		(b,d)	3-month LIBOR	2.21%	October 2016	(e)	—
Southern Power	65		(c,d)	3-month LIBOR	2.21%	November 2016	(f)	—
Total	$	1,968						$	20

(a) 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.

(b) 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.

(c) 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.

(d) Amortizing notional amount.

(e) Represents the mandatory settlement date. Settlement will be based on a 15-year amortizing swap.

(f) Represents the mandatory settlement date. Settlement will be based on a 12-year amortizing swap.

Schedule of foreign currency derivatives

At June 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 June 30, 2016
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	(17	)
Southern Power	564		3.78%	500		1.85%	June 2026	(21		)
Total	$	1,241		€	1,100			$	(38	)

Fair value of energy-related derivatives and interest rate derivatives

At June 30, 2016, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:

Asset Derivatives at June 30, 2016
	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:
Other current assets	$	12	$	5	$	6	$	1	$	—
Other deferred charges and assets	16		5		9		1		1
Total derivatives designated as hedging instruments for regulatory purposes	$	28	$	10	$	15	$	2	$	1	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets	$	5	$	—	$	—	$	—	$	—	$	5
Other deferred charges and assets	1		—		—		—		—		1
Interest rate derivatives:
Other current assets	11		—		6		—		—		—
Other deferred charges and assets	16		—		8		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	33	$	—	$	14	$	—	$	—	$	6
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets	$	2	$	—	$	—	$	—	$	—	$	2
Total asset derivatives	$	63	$	10	$	29	$	2	$	1	$	8

Liability Derivatives at June 30, 2016
	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(*)	$	61	$	17	$	4	$	25	$	15
Other deferred credits and liabilities	44		5		1		30		8
Total derivatives designated as hedging instruments for regulatory purposes	$	105	$	22	$	5	$	55	$	23	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities(*)	$	3	$	—	$	—	$	—	$	—	$	3
Other deferred credits and liabilities	1		—		—		—		—		1
Interest rate derivatives:
Liabilities from risk management activities(*)	7		—		—		7		—		—
Foreign currency derivatives:
Liabilities from risk management activities(*)	24		—		—		—		—		24
Other deferred credits and liabilities	14		—		—		—		—		14
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	49	$	—	$	—	$	7	$	—	$	42
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current liabilities	$	1	$	—	$	—	$	—	$	—	$	1
Total liability derivatives	$	155	$	22	$	5	$	62	$	23	$	43

(*) Georgia Power, Mississippi Power, and Southern Power include current liabilities related to derivatives in "Other current liabilities."

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		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	3	$	1	$	2	$	—	$	—	N/A
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

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."

Offsetting disclosure tables

Amounts related to energy-related derivative contracts, interest rate derivative contracts, and foreign currency derivative contracts at June 30, 2016 and December 31, 2015 are presented in the following tables.

Derivative Contracts at June 30, 2016
	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)	$	36		$	10		$	15		$	2		$	1		$	8
Gross amounts not offset in the Balance Sheet (b)	(32		)	(8		)	(4		)	(2		)	(1		)	(3		)
Net energy-related derivative assets	$	4		$	2		$	11		$	—		$	—		$	5
Interest rate and foreign currency derivatives:
Interest rate and foreign currency derivatives presented in the Balance Sheet (a)	$	27		$	—		$	14		$	—		$	—		$	—
Gross amounts not offset in the Balance Sheet (b)	(18		)	—			—			—			—			—
Net interest rate and foreign currency derivative assets	$	9		$	—		$	14		$	—		$	—		$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	110		$	22		$	5		$	55		$	23		$	5
Gross amounts not offset in the Balance Sheet (b)	(32		)	(8		)	(4		)	(2		)	(1		)	(3		)
Net energy-related derivative liabilities	$	78		$	14		$	1		$	53		$	22		$	2
Interest rate and foreign currency derivatives:
Interest rate and foreign currency derivatives presented in the Balance Sheet (a)	$	45		$	—		$	—		$	7		$	—		$	38
Gross amounts not offset in the Balance Sheet (b)	(18		)	—			—			—			—			—
Net interest rate and foreign currency derivative liabilities	$	27		$	—		$	—		$	7		$	—		$	38

(a) None of the registrants offsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.

(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

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) None of the registrants offsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.

(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

Pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments

At June 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 on the Balance Sheet at June 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	$	(61	)	$	(17	)	$	(4	)	$	(25	)	$	(15	)
Other regulatory assets, deferred	(44		)	(5		)	(1		)	(30		)	(8		)
Other regulatory liabilities, current (a)	12			5			6			1			—
Other regulatory liabilities, deferred (b)	16			5			9			1			1
Total energy-related derivative gains (losses)	$	(77	)	$	(12	)	$	10		$	(53	)	$	(22	)

(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 on 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.

Pre-tax effects of interest rate derivatives, designated as cash flow hedging instruments

For the three months ended June 30, 2016 and 2015, the pre-tax effects of 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
Interest rate derivatives	$	6		$	31	Interest expense, net of amounts capitalized	$	(4	)	$	(2	)
Foreign currency derivatives	(39		)	—		Interest expense, net of amounts capitalized	(1		)	—
						Other income (expense), net	(20		)	—
Total	$	(33	)	$	31		$	(25	)	$	(2	)
Alabama Power
Interest rate derivatives	$	—		$	7	Interest expense, net of amounts capitalized	$	(2	)	$	(1	)
Georgia Power
Interest rate derivatives	$	—		$	24	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Gulf Power
Interest rate derivatives	$	(2	)	$	—	Interest expense, net of amounts capitalized	$	—		$	—
Southern Power
Foreign currency derivatives	$	(39	)	$	—	Interest expense, net of amounts capitalized	$	(1	)	$	—
						Other income (expense), net	(20		)	—
Total	$	(39	)	$	—		$	(21	)	$	—

For the six months ended June 30, 2016 and 2015, the pre-tax effects of 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
Interest rate derivatives	$	(184	)	$	2	Interest expense, net of amounts capitalized	$	(7	)	$	(4	)
Foreign currency derivatives	(39		)	—		Interest expense, net of amounts capitalized	(1		)	—
						Other income (expense), net	(20		)	—
Total	$	(223	)	$	2		$	(28	)	$	(4	)
Alabama Power
Interest rate derivatives	$	(4	)	$	1	Interest expense, net of amounts capitalized	$	(3	)	$	(1	)
Georgia Power
Interest rate derivatives	$	—		$	1	Interest expense, net of amounts capitalized	$	(2	)	$	(2	)
Gulf Power
Interest rate derivatives	$	(7	)	$	—	Interest expense, net of amounts capitalized	$	—		$	—
Mississippi Power
Interest rate derivatives	$	—		$	—	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Southern Power
Interest rate derivatives	$	—		$	—	Interest expense, net of amounts capitalized	$	(1	)	$	—
Foreign currency derivatives	(39		)	—		Interest expense, net of amounts capitalized	(1		)	—
						Other income (expense), net	(20		)	—
Total	$	(39	)	$	—		$	(22	)	$	—

Pre-tax effects of interest rate derivatives, designated as fair value hedging instruments

For the six months ended June 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)
Derivative Category	Statements of Income Location	2016		2015
		(in millions)
Southern Company
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	24	$	4
Georgia Power
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	15	$	2

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Acquisitions (Tables)

6 Months Ended

Jun. 30, 2016

Business Combinations [Abstract]

Schedule of Business Acquisitions

The preliminary allocation of the purchase price is as follows:

PowerSecure Purchase Price	June 30, 2016
	(in millions)
Current assets	$	174
Property, plant, and equipment	48
Goodwill	262
Intangible assets	99
Other assets	8
Current liabilities	(111		)
Long-term debt, including current portion	(47		)
Deferred credits and other liabilities	(4		)
Total purchase price	$	429

The following table presents the preliminary purchase price allocation:

Southern Company Gas Purchase Price	June 30, 2016
	(in millions)
Current assets	$	1,474
Property, plant, and equipment	9,795
Goodwill	6,333
Intangible assets	436
Regulatory assets	846
Other assets	273
Current liabilities	(2,205		)
Other liabilities	(4,529		)
Long-term debt	(4,261		)
Noncontrolling interests	(160		)
Total purchase price	$	8,002

During 2016, in accordance with its overall growth strategy, Southern Power acquired or contracted to acquire through its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC or Southern Renewable Energy, Inc., 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.

Project Facility	Resource	Seller; Acquisition Date	Approx. Nameplate Capacity	Location	Southern Power Percentage Ownership			Expected/Actual COD	PPA Counterparties for Plant Output	PPA Contract Period
			(MW)
Acquisitions for the Six Months Ended June 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	%		Fourth quarter 2016	Austin Energy	15 years
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
Passadumkeag	Wind	Quantum Utility Generation, LLC June 30, 2016	42	Penobscot County, ME	100	%		July 2016	Western Massachusetts Electric Company	15 years
Acquisitions Subsequent to June 30, 2016
Henrietta	Solar	SunPower Corp. July 1, 2016	102	Kings County, CA	51	%	(*)	July 2016	Pacific Gas and Electric Company	20 years
Lamesa	Solar	RES America Developments Inc. July 1, 2016	102	Dawson County, TX	100	%		Second quarter 2017	City of Garland, Texas	15 years
Rutherford	Solar	Cypress Creek Renewables, LLC July 1, 2016	74	Rutherford County, NC	90	%		Fourth quarter 2016	Duke Energy Carolinas, LLC	15 years

(*) 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.

Schedule of Construction Projects

Through June 30, 2016, total costs of construction incurred for the projects below were $2.7 billion, of which $1.7 billion remains in CWIP. Including the total construction costs incurred to date and the acquisition prices allocated to CWIP, total aggregate construction costs for the projects below are estimated to be approximately $3.0 billion to $3.2 billion. The ultimate outcome of these matters cannot be determined at this time.

Solar Facility	Seller	Approx. Nameplate Capacity	Location	Expected/Actual COD	PPA Counterparties for Plant Output	PPA Contract Period
		(MW)
Butler	CERSM, LLC and Community Energy, Inc.	103	Taylor County, GA	Fourth quarter 2016	Georgia Power(a)	30 years
Desert Stateline(b)	First Solar Development, LLC	299(c)	San Bernardino County, CA	Through third quarter 2016	Southern California Edison Company (SCE)	20 years
Garland and Garland A	Recurrent Energy, LLC	205	Kern County, CA	Fourth quarter 2016 and Third quarter 2016	SCE	15 years and 20 years
Roserock	Recurrent Energy, LLC	160	Pecos County, TX	Fourth quarter 2016	Austin Energy	20 years
Sandhills	N/A	146	Taylor County, GA	Fourth quarter 2016	Cobb, Flint, Irwin, Middle Georgia and Sawnee Electric Membership Corporations	25 years
Tranquillity	Recurrent Energy, LLC	205	Fresno County, CA	July 2016	Shell Energy North America (US), LP/SCE	18 years

(a) Butler - Affiliate PPA approved by the FERC.

(b) Desert Stateline - 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. Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized.

(c) Desert Stateline - The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 152 MWs were placed in service during the six months ended June 30, 2016. Subsequent to June 30, 2016, 37 MWs were placed in service.

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Segment and Related Information (Tables)

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

Financial data for business segments

Financial data for business segments and products and services for the three and six months ended June 30, 2016 and 2015 was as follows:

	Electric Utilities
	Traditional Electric Operating Companies		Southern Power		Eliminations			Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2016:
Operating revenues	$	4,115	$	373	$	(109	)	$	4,379	$	125		$	(45	)	$	4,459
Segment net income (loss)(a)(b)	595		89		—			684		(68		)	(4		)	612
Six Months Ended June 30, 2016:
Operating revenues	$	7,884	$	688	$	(212	)	$	8,360	$	172		$	(81	)	$	8,451
Segment net income (loss)(a)(c)	1,059		139		—			1,198		(94		)	(7		)	1,097
Total assets at June 30, 2016	$	70,706	$	11,082	$	(425	)	$	81,363	$	10,505		$	(995	)	$	90,873
Three Months Ended June 30, 2015:
Operating revenues	$	4,077	$	337	$	(90	)	$	4,324	$	43		$	(30	)	$	4,337
Segment net income (loss)(a)(b)	561		46		—			607		18			4			629
Six Months Ended June 30, 2015:
Operating revenues	$	8,025	$	684	$	(213	)	$	8,496	$	83		$	(59	)	$	8,520
Segment net income (loss)(a)(c)	1,038		79		—			1,117		21			—			1,138
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 $81 million ($50 million after tax) and $23 million ($14 million after tax) for the three months ended June 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 $134 million ($83 million after tax) and $32 million ($20 million after tax) for the six months ended June 30, 2016 and 2015, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.

Financial data for products and services

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended June 30, 2016	$	3,748	$	446	$	185	$	4,379
Three Months Ended June 30, 2015	3,714		448		162		4,324
Six Months Ended June 30, 2016	$	7,124	$	842	$	394	$	8,360
Six Months Ended June 30, 2015	7,256		915		325		8,496

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Introduction - Asset Retirement Obligations (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($)
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	$ 3,759
Liabilities incurred	9
Liabilities settled	(66)
Accretion	77
Cash flow revisions	699
Balance at end of period	4,478
Alabama Power [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	1,448
Liabilities incurred	5
Liabilities settled	(6)
Accretion	36
Cash flow revisions	19
Balance at end of period	$ 1,502
Georgia Power [Member]
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation, Period Of Update Cycle	3 years
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	$ 1,916
Liabilities incurred	0
Liabilities settled	(52)
Accretion	34
Cash flow revisions	673
Balance at end of period	2,571
Gulf Power [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	130
Liabilities incurred	0
Liabilities settled	(1)
Accretion	1
Cash flow revisions	3
Balance at end of period	133
Mississippi Power [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	177
Liabilities incurred	0
Liabilities settled	(7)
Accretion	2
Cash flow revisions	6
Balance at end of period	178
Southern Power [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	21
Liabilities incurred	4
Liabilities settled	0
Accretion	1
Cash flow revisions	2
Balance at end of period	$ 28

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Introduction - Goodwill and Intangible Assets (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Indefinite-lived Intangible Assets [Line Items]
Goodwill	$ 264	$ 2
Total goodwill and other intangible assets - gross	768
Total goodwill and other intangible assets - net	754
Finite-Lived Intangible Assets [Line Items]
Intangibles subject to amortization - gross carrying amount	429
Intangibles subject to amortization - accumulated amortization	(14)	(12)
Intangibles subject to amortization - net	415
Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Intangibles subject to amortization - accumulated amortization	$ 0
Customer Relationships [Member] | Minimum [Member]
Finite-Lived Intangible Assets [Line Items]
Intangibles subject to amortization - estimated useful life	14 years
Customer Relationships [Member] | Maximum [Member]
Finite-Lived Intangible Assets [Line Items]
Intangibles subject to amortization - estimated useful life	26 years
Trade Names [Member]
Finite-Lived Intangible Assets [Line Items]
Intangibles subject to amortization - accumulated amortization	$ 0
Trade Names [Member] | Minimum [Member]
Finite-Lived Intangible Assets [Line Items]
Intangibles subject to amortization - estimated useful life	5 years
Trade Names [Member] | Maximum [Member]
Finite-Lived Intangible Assets [Line Items]
Intangibles subject to amortization - estimated useful life	9 years
Patents [Member]
Finite-Lived Intangible Assets [Line Items]
Intangibles subject to amortization - accumulated amortization	$ 0
Patents [Member] | Minimum [Member]
Finite-Lived Intangible Assets [Line Items]
Intangibles subject to amortization - estimated useful life	3 years
Patents [Member] | Maximum [Member]
Finite-Lived Intangible Assets [Line Items]
Intangibles subject to amortization - estimated useful life	10 years
Order or Production Backlog [Member]
Finite-Lived Intangible Assets [Line Items]
Intangibles subject to amortization - accumulated amortization	$ 0
Southern Company [Member]
Indefinite-lived Intangible Assets [Line Items]
Goodwill	262
Southern Company [Member] | Federal Communications Commission Licenses [Member]
Indefinite-lived Intangible Assets [Line Items]
Intangibles not subject to amortization	75
Southern Company [Member] | Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Intangibles subject to amortization - gross carrying amount	47
Intangibles subject to amortization - net	47
Southern Company [Member] | Trade Names [Member]
Finite-Lived Intangible Assets [Line Items]
Intangibles subject to amortization - gross carrying amount	43
Intangibles subject to amortization - net	43
Southern Company [Member] | Patents [Member]
Finite-Lived Intangible Assets [Line Items]
Intangibles subject to amortization - gross carrying amount	4
Intangibles subject to amortization - net	$ 4
Southern Company [Member] | Order or Production Backlog [Member]
Finite-Lived Intangible Assets [Line Items]
Intangibles subject to amortization - estimated useful life	5 years
Intangibles subject to amortization - gross carrying amount	$ 5
Intangibles subject to amortization - net	5
Southern Power [Member]
Indefinite-lived Intangible Assets [Line Items]
Goodwill	2	2
Finite-Lived Intangible Assets [Line Items]
Intangibles subject to amortization - accumulated amortization	$ (14)	$ (12)
Southern Power [Member] | PPA Fair Value Adjustments [Member]
Finite-Lived Intangible Assets [Line Items]
Intangibles subject to amortization - estimated useful life	20 years
Intangibles subject to amortization - gross carrying amount	$ 330
Intangibles subject to amortization - accumulated amortization	(14)
Intangibles subject to amortization - net	$ 316

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Introduction - Narrative (Details) $ in Millions	30 Months Ended
	Jun. 30, 2016 USD ($) agreement location	Dec. 31, 2015 USD ($)
Related Party Transaction [Line Items]
Intangible Assets, Net (Excluding Goodwill)	$ 490	$ 317
Construction work in progress	9,451	9,082
Southern Power [Member]
Related Party Transaction [Line Items]
Intangible Assets, Net (Excluding Goodwill)	316	317
Construction work in progress	1,852	1,137
Due to Related Parties, Current	$ 80	66
Georgia Power [Member]
Related Party Transaction [Line Items]
Number Of Military Bases For Renewable Generation | location	2
Construction work in progress	$ 4,655	4,775
Due to Related Parties, Current	$ 407	$ 411
Affiliated Entity [Member] | Georgia Power [Member]
Related Party Transaction [Line Items]
Number Of Agreements for Renewable Generation | agreement	2
Construction work in progress	$ 102
Due to Related Parties, Current	$ 13

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Contingencies and Regulatory Matters - Recovery Balance of Each Regulatory Clause - Alabama Power (Details) - Alabama Power [Member] - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Under recovered regulatory clause revenues, current [Member]
Loss Contingencies [Line Items]
Rate CNP Compliance	$ 7	$ 43
Deferred under recovered regulatory clause revenues [Member]
Loss Contingencies [Line Items]
Rate CNP Compliance	21	0
Rate CNP PPA	115	99
Other regulatory liabilities, current [Member]
Loss Contingencies [Line Items]
Retail Energy Cost Recovery	75	238
Deferred Over Recovered Regulatory Clause Revenues [Member]
Loss Contingencies [Line Items]
Retail Energy Cost Recovery	102	0
Other regulatory liabilities, deferred [Member]
Loss Contingencies [Line Items]
Natural Disaster Reserve	$ 72	$ 75

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Contingencies and Regulatory Matters - Recovery Balance of Each Regulatory Clause - Gulf Power (Details) - Gulf Power [Member] - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Under recovered regulatory clause revenues [Member]
Loss Contingencies [Line Items]
Purchased Power Capacity Recovery	$ 4	$ 1
Under Recovered Environmental Cost	1	19
Other regulatory liabilities, current [Member]
Loss Contingencies [Line Items]
Fuel Cost Recovery	18	18
Energy Conservation Cost Recovery	$ 0	$ 4

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Contingencies and Regulatory Matters - Current And Actual Cost Estimate (Details) - Mississippi Power [Member] - USD ($) $ in Millions		6 Months Ended	12 Months Ended
	Apr. 08, 2016	Jun. 30, 2016	Dec. 31, 2012	Dec. 03, 2015
Loss Contingencies [Line Items]
Cost Related to Grant Funding			$ 245
Kemper IGCC [Member]
Loss Contingencies [Line Items]
Plant Subject to Cost Cap		$ 5,150	$ 2,880
Lignite Mine and Equipment		230
CO2 Pipeline Facilities		120
AFUDC		660
Combined Cycle and Related Assets Placed in Service – Incremental		20
General Exceptions		90
Deferred Costs		190
Total Kemper IGCC, Actual Costs		6,320
Cost Related to Grant Funding		$ (140)
Purchase of Interest		100.00%		15.00%
Government Grants Received	$ 137
Project Estimate [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Plant Subject to Cost Cap		$ 2,400
Lignite Mine and Equipment		210
CO2 Pipeline Facilities		140
AFUDC		170
Combined Cycle and Related Assets Placed in Service – Incremental		0
General Exceptions		50
Deferred Costs		0
Total Kemper IGCC, Actual Costs		2,970
Cost Related to Grant Funding		0
Current Estimate [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Plant Subject to Cost Cap		5,430
Lignite Mine and Equipment		230
CO2 Pipeline Facilities		110
AFUDC		720
Combined Cycle and Related Assets Placed in Service – Incremental		30
General Exceptions		100
Deferred Costs		200
Total Kemper IGCC, Actual Costs		6,680
Cost Related to Grant Funding		(140)
Maximum [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Plant Subject to Cost Cap		$ 2,880

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Contingencies and Regulatory Matters - Narrative (Details)												1 Months Ended				3 Months Ended		6 Months Ended			10 Months Ended	12 Months Ended								54 Months Ended	84 Months Ended
	Jun. 30, 2016 USD ($) mi	Jun. 09, 2016 USD ($)	Jun. 03, 2016	May 01, 2016 USD ($)	Mar. 31, 2016	Dec. 03, 2015 USD ($)	Jul. 07, 2015 USD ($)	Jun. 30, 2015 USD ($)	Apr. 15, 2015 USD ($)	Jan. 01, 2014 USD ($)	Mar. 19, 2013	Apr. 30, 2016 MW	Dec. 31, 2015 USD ($)	Feb. 28, 2013 USD ($)	Jan. 31, 2013 USD ($)	Jun. 30, 2016 USD ($) mi	Jun. 30, 2015 USD ($)	Jun. 30, 2016 USD ($) clause mi MW	Dec. 31, 2015 USD ($)	Jun. 30, 2015 USD ($)	Oct. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2010	Dec. 31, 2009 USD ($)	Dec. 31, 2008 USD ($)	Jun. 30, 2016 USD ($) mi	Dec. 31, 2022	Jun. 30, 2019 USD ($)	Jul. 28, 2016 MW	May 17, 2016 USD ($)	May 03, 2016 USD ($)	Apr. 01, 2016 USD ($)	Mar. 09, 2016 USD ($)	Feb. 01, 2016 USD ($)	Jan. 05, 2016 USD ($)	Jul. 10, 2015 USD ($)
Loss Contingencies [Line Items]
Maximum Borrowing Capacity	$ 6,500,000,000															$ 6,500,000,000		$ 6,500,000,000												$ 6,500,000,000
Construction work in progress	9,451,000,000												$ 9,082,000,000			9,451,000,000		9,451,000,000	$ 9,082,000,000				$ 9,082,000,000							9,451,000,000
Projected Balance Of Regulatory Assets	350,000,000												402,000,000			350,000,000		350,000,000	402,000,000				402,000,000							350,000,000
Kemper IGCC [Member]
Loss Contingencies [Line Items]
Pre-Tax Charge To Income																81,000,000	$ 23,000,000	134,000,000		$ 32,000,000
After Tax Charge To Income																50,000,000	$ 14,000,000	83,000,000		$ 20,000,000
Georgia Power [Member]
Loss Contingencies [Line Items]
Environmental Exit Costs, Assets Previously Disposed, Liability for Remediation	23,000,000															23,000,000		23,000,000												23,000,000
Rate ECR Increase Decrease																																		15.00%
Approved Increase (Decrease) in Annual Billing Based on Fuel Cost Recovery Rate																																		$ (313,000,000)
Additional Construction Capital Costs								$ 3,100,000,000											160,000,000
Percentage of Proportionate Share Owed in Consortium Agreement																													45.70%
Maximum Borrowing Capacity	1,750,000,000															1,750,000,000		$ 1,750,000,000												1,750,000,000
Increase (Decrease) In Projected Certified Construction Capital Costs																		5.00%
Estimated In-service Capital Cost																												$ 4,400,000,000
Amendment To Estimated In-service Capital Cost														$ 4,800,000,000
Delay Of Estimated In-service Date									18 months
Construction work in progress	4,655,000,000												4,775,000,000			4,655,000,000		$ 4,655,000,000	4,775,000,000				4,775,000,000							4,655,000,000
Projected Balance Of Regulatory Assets	123,000,000												123,000,000			123,000,000		123,000,000	123,000,000				123,000,000							123,000,000
Georgia Power [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Additional Construction Capital Costs																													$ 114,000,000
Georgia Power [Member] | Other Current Liabilities [Member]
Loss Contingencies [Line Items]
Over Recovered Fuel Balance	164,000,000															164,000,000		164,000,000												164,000,000
Georgia Power [Member] | Other deferred credits and liabilities [Member]
Loss Contingencies [Line Items]
Over Recovered Fuel Balance													116,000,000						116,000,000				116,000,000
Georgia Power [Member] | Plant Vogtle Units 3 And 4 [Member]
Loss Contingencies [Line Items]
Additional Construction Capital Costs																		141,000,000
Maximum Borrowing Capacity																																					$ 920,000,000
Estimated In-service Capital Cost									$ 5,000,000,000
Monthly Operational Readiness Costs									$ 10,000,000
Construction Financing Costs	1,100,000,000
Construction work in progress	3,700,000,000															3,700,000,000		3,700,000,000												3,700,000,000
Georgia Power [Member] | Plant Vogtle Units 3 And 4 [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Project Settlement Cost To Be Capitalized													350,000,000						350,000,000				350,000,000
Project Settlement Cost To Be Capitalized, Amount Paid To Date	250,000,000															250,000,000		250,000,000												250,000,000
Gulf Power [Member]
Loss Contingencies [Line Items]
Environmental Exit Costs, Assets Previously Disposed, Liability for Remediation	46,000,000															46,000,000		46,000,000												46,000,000
Maximum Borrowing Capacity	280,000,000															280,000,000		280,000,000												280,000,000
Construction work in progress	68,000,000												48,000,000			68,000,000		68,000,000	48,000,000				48,000,000							68,000,000
Reduction In Depreciation Expense																									$ 62,500,000
Reduction In Depreciation Expense Year One																		$ 6,400,000					20,100,000	$ 8,400,000
Number Of Regulatory Clauses | clause																		4
Projected Balance Of Regulatory Assets	65,000,000												90,000,000			65,000,000		$ 65,000,000	90,000,000				90,000,000							65,000,000
Mississippi Power [Member]
Loss Contingencies [Line Items]
Increase in Base Rate Under Cost Based Electric Tariff Due to Settlement				$ 7,000,000
Over Recovered Fuel Cost	76,000,000												71,000,000			76,000,000		76,000,000	71,000,000				71,000,000							76,000,000
Approved Increase (Decrease) in Annual Billing Based on Fuel Cost Recovery Rate																																						$ (36,000,000)	$ (120,000,000)
Maximum Borrowing Capacity	175,000,000															175,000,000		175,000,000												175,000,000
Construction work in progress	2,429,000,000												2,254,000,000			2,429,000,000		$ 2,429,000,000	2,254,000,000				2,254,000,000							2,429,000,000
PSC Retail Rate Increase (Decrease)																																			$ (2,000,000)
Annual PEP Filing Rate Increase Amount																																				$ 5,000,000
Plant Capacity Under Coal Gasification Combined Cycle Technology (in MWs) | MW																		582
Costs associated with CCP12 grant funds																										$ 245,000,000
Increase Retail Rates In Year One											15.00%
Increase Retail Rates In Year Two										3.00%
Settlement Agreement Collection Amount To Mitigate Rate Impact Year Two										$ 156,000,000
Retail Rate Recovery							$ 342,000,000
Carrying Costs Associated With Retail Rate Recovery							$ 29,000,000
Projected Balance Of Regulatory Assets	97,000,000												95,000,000			97,000,000		$ 97,000,000	95,000,000				95,000,000							97,000,000
Regulatory Liabilities	5,000,000															5,000,000		5,000,000												5,000,000
Mississippi Power [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Costs Due To Extension Of In-service Date																		25,000,000
Mississippi Power [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Costs Due To Extension Of In-service Date																		35,000,000
Mississippi Power [Member] | Construction in Progress [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	2,550,000,000															2,550,000,000		2,550,000,000												2,550,000,000
Mississippi Power [Member] | MRA Revenue [Member]
Loss Contingencies [Line Items]
Over Recovered Fuel Cost	$ 23,000,000												24,000,000			$ 23,000,000		$ 23,000,000	24,000,000				24,000,000							$ 23,000,000
Mississippi Power [Member] | Electricity Generation Plant, Non-Nuclear [Member]
Loss Contingencies [Line Items]
Estimated Cost															$ 2,400,000,000											2,400,000,000
Alternate Financing																									$ 1,000,000,000
Mississippi Power [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Period of Amortization of Regulatory Assets					36 months
Co Two Pipeline Infrastructure (in miles) | mi	61															61		61												61
Estimated Cost																		$ 5,150,000,000								$ 2,880,000,000
Costs associated with CCP12 grant funds																		$ (140,000,000)
Period of Extension for In-service Date																		1 month
Pre-Tax Charge To Income																$ 81,000,000		$ 134,000,000												$ 2,550,000,000
After Tax Charge To Income																$ 50,000,000		83,000,000												$ 1,570,000,000
Monthly Charge Of Allowance For Equity Funds Used During Construction																		14,000,000
Monthly Cost Regulatory Assets Deferred																		$ 3,000,000
Purchase of Interest	100.00%					15.00%										100.00%		100.00%												100.00%
Maximum Cap Construction Cost																		$ 6,320,000,000
Regulatory Assets	$ 114,000,000															$ 114,000,000		114,000,000												$ 114,000,000
Projected Balance Of Regulatory Assets	101,000,000															101,000,000		101,000,000												101,000,000
Mississippi Power [Member] | Kemper IGCC [Member] | Current Estimate [Member]
Loss Contingencies [Line Items]
Estimated Cost																		5,430,000,000
Costs associated with CCP12 grant funds																		(140,000,000)
Maximum Cap Construction Cost																		$ 6,680,000,000
Mississippi Power [Member] | Kemper IGCC [Member] | In-Service Asset Proposal [Member]
Loss Contingencies [Line Items]
PSC Retail Rate Increase (Decrease)						$ 126,000,000																																		$ 159,000,000
Public Utilities, Approved Equity Capital Structure, Percentage						49.733%
Public Utilities, Approved Return on Equity, Percentage						9.225%
Customer Refund													11,000,000
Period to File Subsequent Rate Request						18 months
Mississippi Power [Member] | Kemper IGCC [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value		$ 100,000,000
Mississippi Power [Member] | Kemper IGCC [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Amortization Period of Regulatory Assets and Liabilities																		2 years
Mississippi Power [Member] | Kemper IGCC [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Estimated Cost																		$ 2,880,000,000
Amortization Period of Regulatory Assets and Liabilities																		10 years
Mississippi Power [Member] | Kemper IGCC [Member] | Property, Plant and Equipment [Member]
Loss Contingencies [Line Items]
Estimated Cost																		$ 3,590,000,000
Mississippi Power [Member] | Kemper IGCC [Member] | Other Property And Investments [Member]
Loss Contingencies [Line Items]
Estimated Cost																		6,000,000
Mississippi Power [Member] | Kemper IGCC [Member] | Fossil Fuel Stock [Member]
Loss Contingencies [Line Items]
Estimated Cost																		81,000,000
Mississippi Power [Member] | Kemper IGCC [Member] | Materials And Supplies [Member]
Loss Contingencies [Line Items]
Estimated Cost																		46,000,000
Mississippi Power [Member] | Kemper IGCC [Member] | Other regulatory assets deferred [Member]
Loss Contingencies [Line Items]
Estimated Cost																		35,000,000
Mississippi Power [Member] | Kemper IGCC [Member] | Other regulatory assets, deferred [Member]
Loss Contingencies [Line Items]
Estimated Cost																		180,000,000
Mississippi Power [Member] | Kemper IGCC [Member] | Other current assets [Member]
Loss Contingencies [Line Items]
Estimated Cost																		1,000,000
Mississippi Power [Member] | Kemper IGCC [Member] | Other deferred charges and assets [Member]
Loss Contingencies [Line Items]
Estimated Cost																		11,000,000
Mississippi Power [Member] | Kemper IGCC [Member] | Current Assets [Member]
Loss Contingencies [Line Items]
Regulatory Assets	35,000,000															35,000,000		35,000,000												35,000,000
Mississippi Power [Member] | Mine [Member]
Loss Contingencies [Line Items]
Term of Management Fee Contract																											40 years
Alabama Power [Member]
Loss Contingencies [Line Items]
Maximum Borrowing Capacity	1,335,000,000															1,335,000,000		1,335,000,000												1,335,000,000
Construction work in progress	423,000,000												801,000,000			423,000,000		423,000,000	801,000,000				801,000,000							423,000,000
Projected Balance Of Regulatory Assets	$ 87,000,000												$ 115,000,000			$ 87,000,000		$ 87,000,000	$ 115,000,000				$ 115,000,000							$ 87,000,000
Alabama Power [Member] | Plant Greene County Units 1 And 2 [Member]
Loss Contingencies [Line Items]
Capacity Of Units Included In Request For Decertification Of Units | MW												300
Scenario, Forecast [Member] | Georgia Power [Member]
Loss Contingencies [Line Items]
Cost Recovery, New Nuclear																																$ 99,000,000
Additional Construction Capital Costs																						$ 5,440,000,000
Scenario, Forecast [Member] | Georgia Power [Member] | Plant Vogtle Units 3 And 4 [Member]
Loss Contingencies [Line Items]
Construction Financing Costs																						$ 2,400,000,000
Scenario, Forecast [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
AFUDC Cost																					$ 8,000,000
Scenario, Forecast [Member] | Georgia Power And Atlanta Gas Light Company [Member]
Loss Contingencies [Line Items]
Percentage Basis, Net Merger Savings																															40.00%
Customers [Member] | Scenario, Forecast [Member]
Loss Contingencies [Line Items]
Percentage Basis, Net Merger Savings																															60.00%
Subsequent Event [Member] | Georgia Power [Member]
Loss Contingencies [Line Items]
Capacity of Renewable Resources Approved For Procurement | MW																																	1,200
Capacity of Renewable Resources Approved For Self-build | MW																																	200
Subsequent Event [Member] | Georgia Power [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Capacity of Renewable Resources Considered For Renewable Commercial and Industrial Program | MW																																	200
Subsequent Event [Member] | Georgia Power [Member] | Plant Mitchell Units 3, 4A, and 4B [Member]
Loss Contingencies [Line Items]
Capacity Of Units Approved For Decertification Of Units | MW																																	217
Subsequent Event [Member] | Georgia Power [Member] | Plant Kraft Unit 1 [Member]
Loss Contingencies [Line Items]
Capacity Of Units Approved For Decertification Of Units | MW																																	17
Intercession City Combustion Turbine [Member] | Subsequent Event [Member] | Georgia Power [Member]
Loss Contingencies [Line Items]
Capacity Of Units Approved For Decertification Of Units | MW																																	143
Jointly Owned Utility Plant, Proportionate Ownership Share																																	33.00%
Denbury Onshore, Contractor [Member] | Mississippi Power [Member] | Electricity Generation Plant, Non-Nuclear [Member]
Loss Contingencies [Line Items]
Long-term Contract For Purchase of Carbon Dioxide, Term			16 years
Treetop Midstream Services, LLC, Contractor [Member] | Mississippi Power [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Long Term Contract For Purchase Of Percentage of Carbon Dioxide Captured from Plant	30.00%															30.00%		30.00%												30.00%
Denbury Onshore, Contractor [Member] | Mississippi Power [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Long Term Contract For Purchase Of Percentage of Carbon Dioxide Captured from Plant	70.00%		100.00%													70.00%		70.00%												70.00%

XML

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Assets:
Fair Value	$ 18
Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	36
Interest rate derivatives	27
Nuclear decommissioning trusts	1,577
Cash equivalents	1,014
Other investments	10
Total	2,664
Liabilities:
Energy-related derivatives	110
Interest rate derivatives	7
Foreign Currency Fair Value Hedge Liability at Fair Value	38
Total	155
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Nuclear decommissioning trusts	642
Cash equivalents	1,014
Other investments	9
Total	1,665
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Foreign Currency Fair Value Hedge Liability at Fair Value	0
Total	0
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	36
Interest rate derivatives	27
Nuclear decommissioning trusts	917
Cash equivalents	0
Other investments	0
Total	980
Liabilities:
Energy-related derivatives	110
Interest rate derivatives	7
Foreign Currency Fair Value Hedge Liability at Fair Value	38
Total	155
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Nuclear decommissioning trusts	0
Cash equivalents	0
Other investments	1
Total	1
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Foreign Currency Fair Value Hedge Liability at Fair Value	0
Total	0
Alabama Power [Member]
Assets:
Energy-related derivatives	10	$ 1
Fair Value	18
Liabilities:
Energy-related derivatives	22	70
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	10
Cash equivalents	210
Total	978
Liabilities:
Energy-related derivatives	22
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	430
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	93
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	24
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	163
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	22
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Private Equity Funds [Member]
Assets:
Nuclear decommissioning trusts	18
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	8
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	210
Total	640
Liabilities:
Energy-related derivatives	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	363
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	46
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	21
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Private Equity Funds [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	10
Cash equivalents	0
Total	320
Liabilities:
Energy-related derivatives	22
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	67
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	47
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	24
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	142
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	22
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Private Equity Funds [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	8
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Private Equity Funds [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member]
Assets:
Energy-related derivatives	29	7
Nuclear decommissioning trusts	46
Liabilities:
Energy-related derivatives	5	21
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	15
Interest rate derivatives	14
Cash equivalents	90
Total	938
Liabilities:
Energy-related derivatives	5
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	188
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	116
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	109
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	57
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	159
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	159
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	31
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Cash equivalents	90
Total	302
Liabilities:
Energy-related derivatives	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	187
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	25
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	15
Interest rate derivatives	14
Cash equivalents	0
Total	636
Liabilities:
Energy-related derivatives	5
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	1
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	116
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	109
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	57
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	159
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	159
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	6
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	0
Gulf Power [Member]
Assets:
Energy-related derivatives	2	1
Liabilities:
Energy-related derivatives	62	100
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	2
Cash equivalents	20
Total	22
Liabilities:
Energy-related derivatives	55
Interest rate derivatives	7
Total	62
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	20
Total	20
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Total	0
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	2
Cash equivalents	0
Total	2
Liabilities:
Energy-related derivatives	55
Interest rate derivatives	7
Total	62
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Total	0
Mississippi Power [Member]
Assets:
Energy-related derivatives	1	0
Liabilities:
Energy-related derivatives	23	47
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	1
Cash equivalents	102
Total	103
Liabilities:
Energy-related derivatives	23
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	102
Total	102
Liabilities:
Energy-related derivatives	0
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	1
Cash equivalents	0
Total	1
Liabilities:
Energy-related derivatives	23
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
Southern Power [Member]
Assets:
Energy-related derivatives	8	7
Liabilities:
Energy-related derivatives	43	$ 3
Southern Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	8
Cash equivalents	449
Total	457
Liabilities:
Energy-related derivatives	5
Foreign Currency Fair Value Hedge Liability at Fair Value	38
Total	43
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	449
Total	449
Liabilities:
Energy-related derivatives	0
Foreign Currency Fair Value Hedge Liability at Fair Value	0
Total	0
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	8
Cash equivalents	0
Total	8
Liabilities:
Energy-related derivatives	5
Foreign Currency Fair Value Hedge Liability at Fair Value	38
Total	43
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
Foreign Currency Fair Value Hedge Liability at Fair Value	0
Total	0
Nuclear Decommissioning Trusts [Member]
Assets:
Fair Value	18
Nuclear Decommissioning Trusts [Member] | Alabama Power [Member]
Assets:
Fair Value	$ 18

XML

Fair Value Measurements - Fair Value Measurements Of Investments Calculated At Net Asset Value Per Share (Details) $ in Millions	Jun. 30, 2016 USD ($)
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	$ 18
Private Equity Funds [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	18
Unfunded Commitments	28
Alabama Power [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	18
Alabama Power [Member] | Private Equity Funds [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	18
Unfunded Commitments	$ 28

XML

Fair Value Measurements - Financial Instruments for which Carrying Amount did not Equal Fair Value (Details) $ in Millions	Jun. 30, 2016 USD ($)
Southern Company [Member]
Long-term debt:
Long-term debt, including securities due within one year, Carrying Amount	$ 37,953
Long-term debt, including securities due within one year, Fair Value	40,992
Alabama Power [Member]
Long-term debt:
Long-term debt, including securities due within one year, Carrying Amount	7,090
Long-term debt, including securities due within one year, Fair Value	7,940
Georgia Power [Member]
Long-term debt:
Long-term debt, including securities due within one year, Carrying Amount	10,603
Long-term debt, including securities due within one year, Fair Value	11,881
Gulf Power [Member]
Long-term debt:
Long-term debt, including securities due within one year, Carrying Amount	1,182
Long-term debt, including securities due within one year, Fair Value	1,275
Mississippi Power [Member]
Long-term debt:
Long-term debt, including securities due within one year, Carrying Amount	2,983
Long-term debt, including securities due within one year, Fair Value	2,967
Southern Power [Member]
Long-term debt:
Long-term debt, including securities due within one year, Carrying Amount	4,332
Long-term debt, including securities due within one year, Fair Value	$ 4,523

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Fair Value Measurements - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ 28	$ (1)	$ 48	$ 31
Private Equity Funds [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Liquidations term			10 years
Alabama Power [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	29	5	$ 40	19
Georgia Power [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ (1)	$ (6)	$ 8	$ 12

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Stockholders' Equity - Earnings per Share (Details) - shares shares in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Equity [Abstract]
As reported shares	934	909	925	910
Effect of options and performance share award units	6	3	6	4
Diluted shares	940	912	931	914
Stock options and performance share award units that were not included in the diluted earnings per share calculation (in shares)	0	15	0	1

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Stockholders' Equity - Changes in Stockholders' Equity (Details) - USD ($) shares in Thousands, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Changes in Stockholders' Equity
Beginning Balance, Treasury Shares			(3,400)
Beginning Balance			$ 21,982	$ 20,926
Consolidated net income attributable to Southern Company	$ 612	$ 629	1,097	1,138
Other comprehensive income (loss)	$ (3)	22	(117)	7
Stock issued			1,383	117
Stock-based compensation			82	66
Stock repurchased, at cost				(115)
Cash dividends on common stock			(1,023)	(972)
Preference stock redemption				(150)
Contributions from noncontrolling interests			169	135
Distributions to noncontrolling interests			(10)	(5)
Purchase of membership interests from noncontrolling interests			(129)
Net income attributable to noncontrolling interests			11	4
Other			$ 1	(5)
Beginning Balance, Treasury Shares	(800)		(800)
Ending Balance	$ 23,446	$ 21,146	$ 23,446	$ 21,146
Noncontrolling Interest in Preferred Unit Holders	609		609		$ 609
Nonredeemable Noncontrolling Interest	$ 822		$ 822		$ 781
Number of Common shares Issued [Member]
Changes in Stockholders' Equity
Beginning Balance, Shares			915,073	908,502
Stock issued, Shares			27,297	3,222
Ending Balance, Shares	942,370	911,724	942,370	911,724
Number of Common shares Treasury [Member]
Changes in Stockholders' Equity
Beginning Balance, Treasury Shares			(3,352)	(725)
Stock issued, Shares			2,599
Stock repurchased, at cost, Shares				(2,599)
Other, Shares			(19)	25
Beginning Balance, Treasury Shares	(772)	(3,299)	(772)	(3,299)
Common Stockholders' Equity [Member]
Changes in Stockholders' Equity
Beginning Balance			$ 20,592	$ 19,949
Consolidated net income attributable to Southern Company			1,097	1,138
Other comprehensive income (loss)			(117)	7
Stock issued			1,383	117
Stock-based compensation			82	66
Stock repurchased, at cost				(115)
Cash dividends on common stock			(1,023)	(972)
Other			1	(8)
Ending Balance	$ 22,015	$ 20,182	22,015	20,182
Preferred And Preference Stock [Member]
Changes in Stockholders' Equity
Beginning Balance			609	756
Preference stock redemption				(150)
Other				3
Ending Balance	609	609	609	609
Noncontrolling Interest [Member]
Changes in Stockholders' Equity
Beginning Balance			781	221
Contributions from noncontrolling interests			169	135
Distributions to noncontrolling interests			(10)	(5)
Purchase of membership interests from noncontrolling interests			(129)
Net income attributable to noncontrolling interests			11	4
Ending Balance	$ 822	$ 355	$ 822	$ 355

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Financing - Schedule of Credit Arrangements (Details) - USD ($)	Jun. 30, 2016	May 24, 2016
Line of Credit Facility [Line Items]
Expires, 2016	$ 218,000,000
Expires, 2017	177,000,000
Expires, 2018	1,665,000,000
Expires, 2020	4,440,000,000
Total	6,500,000,000
Unused	6,387,000,000
Executable Term Loans, One Year	65,000,000
Executable Term Loans, Two Years	15,000,000
Due Within One Year, Term Out	80,000,000
Due Within One Year, No Term Out	315,000,000
Bridge Agreement [Member]
Line of Credit Facility [Line Items]
Total		$ 8,100,000,000
Southern Company [Member]
Line of Credit Facility [Line Items]
Expires, 2016	0
Expires, 2017	0
Expires, 2018	1,000,000,000
Expires, 2020	1,250,000,000
Total	2,250,000,000
Unused	2,250,000,000
Executable Term Loans, One Year	0
Executable Term Loans, Two Years	0
Due Within One Year, Term Out	0
Due Within One Year, No Term Out	0
Alabama Power [Member]
Line of Credit Facility [Line Items]
Expires, 2016	3,000,000
Expires, 2017	32,000,000
Expires, 2018	500,000,000
Expires, 2020	800,000,000
Total	1,335,000,000
Unused	1,335,000,000
Executable Term Loans, One Year	0
Executable Term Loans, Two Years	0
Due Within One Year, Term Out	0
Due Within One Year, No Term Out	35,000,000
Georgia Power [Member]
Line of Credit Facility [Line Items]
Expires, 2016	0
Expires, 2017	0
Expires, 2018	0
Expires, 2020	1,750,000,000
Total	1,750,000,000
Unused	1,732,000,000
Executable Term Loans, One Year	0
Executable Term Loans, Two Years	0
Due Within One Year, Term Out	0
Due Within One Year, No Term Out	0
Gulf Power [Member]
Line of Credit Facility [Line Items]
Expires, 2016	75,000,000
Expires, 2017	40,000,000
Expires, 2018	165,000,000
Expires, 2020	0
Total	280,000,000
Unused	280,000,000
Executable Term Loans, One Year	45,000,000
Executable Term Loans, Two Years	0
Due Within One Year, Term Out	45,000,000
Due Within One Year, No Term Out	70,000,000
Mississippi Power [Member]
Line of Credit Facility [Line Items]
Expires, 2016	115,000,000
Expires, 2017	60,000,000
Expires, 2018	0
Expires, 2020	0
Total	175,000,000
Unused	150,000,000
Executable Term Loans, One Year	0
Executable Term Loans, Two Years	15,000,000
Due Within One Year, Term Out	15,000,000
Due Within One Year, No Term Out	160,000,000
Southern Power [Member]
Line of Credit Facility [Line Items]
Expires, 2016	0
Expires, 2017	0
Expires, 2018	0
Expires, 2020	600,000,000
Total	600,000,000
Unused	560,000,000
Executable Term Loans, One Year	0
Executable Term Loans, Two Years	0
Due Within One Year, Term Out	0
Due Within One Year, No Term Out	0
Other [Member]
Line of Credit Facility [Line Items]
Expires, 2016	25,000,000
Expires, 2017	45,000,000
Expires, 2018	0
Expires, 2020	40,000,000
Total	110,000,000
Unused	80,000,000
Executable Term Loans, One Year	20,000,000
Executable Term Loans, Two Years	0
Due Within One Year, Term Out	20,000,000
Due Within One Year, No Term Out	$ 50,000,000

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Financing - Schedule of Line of Credit Facilities (Details)	Jun. 30, 2016 USD ($)
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	$ 6,500,000,000
Remaining Borrowing Capacity	6,387,000,000
Southern Power [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	600,000,000
Remaining Borrowing Capacity	560,000,000
Construction Loans [Member] | Southern Power [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	235,000,000
Construction Loans [Member] | Southern Power [Member] | RE Tranquility Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	86,000,000
Construction Loans [Member] | Southern Power [Member] | RE Roserock Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	63,000,000
Construction Loans [Member] | Southern Power [Member] | RE Garland Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	86,000,000
Bridge Loan [Member] | Southern Power [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	660,000,000
Bridge Loan [Member] | Southern Power [Member] | RE Tranquility Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	172,000,000
Bridge Loan [Member] | Southern Power [Member] | RE Roserock Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	180,000,000
Bridge Loan [Member] | Southern Power [Member] | RE Garland Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	308,000,000
Construction Loan And Bridge Loan [Member] | Southern Power [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	895,000,000
Remaining Borrowing Capacity	126,000,000
Construction Loan And Bridge Loan [Member] | Southern Power [Member] | RE Tranquility Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	258,000,000
Remaining Borrowing Capacity	19,000,000
Construction Loan And Bridge Loan [Member] | Southern Power [Member] | RE Roserock Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	243,000,000
Remaining Borrowing Capacity	34,000,000
Construction Loan And Bridge Loan [Member] | Southern Power [Member] | RE Garland Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	394,000,000
Remaining Borrowing Capacity	73,000,000
Letter of Credit [Member] | Southern Power [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	149,000,000
Remaining Borrowing Capacity	65,000,000
Letter of Credit [Member] | Southern Power [Member] | RE Tranquility Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	77,000,000
Remaining Borrowing Capacity	26,000,000
Letter of Credit [Member] | Southern Power [Member] | RE Roserock Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	23,000,000
Remaining Borrowing Capacity	16,000,000
Letter of Credit [Member] | Southern Power [Member] | RE Garland Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	49,000,000
Remaining Borrowing Capacity	$ 23,000,000

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Financing - Schedule of Long-Term Debt Financing Activities (Details) - USD ($)	1 Months Ended	6 Months Ended
	May 31, 2016	Jun. 30, 2016
Debt Instrument [Line Items]
Senior Note Issuances		$ 10,791,000,000
Senior Note Maturities and Redemptions		825,000,000
Revenue Bond Maturities Redemptions and Repurchases		4,000,000
Other Long-Term Debt Issuances		1,247,000,000
Other Long-Term Debt Redemptions and Maturities		443,000,000
Consolidation, Eliminations [Member]
Debt Instrument [Line Items]
Senior Note Issuances		0
Senior Note Maturities and Redemptions		0
Revenue Bond Maturities Redemptions and Repurchases		0
Other Long-Term Debt Issuances		(200,000,000)
Other Long-Term Debt Redemptions and Maturities		(225,000,000)
Southern Company [Member]
Debt Instrument [Line Items]
Senior Note Issuances	$ 8,500,000,000.0	8,500,000,000
Senior Note Maturities and Redemptions		0
Revenue Bond Maturities Redemptions and Repurchases		0
Other Long-Term Debt Issuances		0
Other Long-Term Debt Redemptions and Maturities		0
Alabama Power [Member]
Debt Instrument [Line Items]
Senior Note Issuances		400,000,000
Senior Note Maturities and Redemptions		200,000,000
Revenue Bond Maturities Redemptions and Repurchases		0
Other Long-Term Debt Issuances		45,000,000
Other Long-Term Debt Redemptions and Maturities		0
Georgia Power [Member]
Debt Instrument [Line Items]
Senior Note Issuances		650,000,000
Senior Note Maturities and Redemptions		500,000,000
Revenue Bond Maturities Redemptions and Repurchases		4,000,000
Other Long-Term Debt Issuances		300,000,000
Other Long-Term Debt Redemptions and Maturities		3,000,000
Gulf Power [Member]
Debt Instrument [Line Items]
Senior Note Issuances		0
Senior Note Maturities and Redemptions		125,000,000
Revenue Bond Maturities Redemptions and Repurchases		0
Other Long-Term Debt Issuances		0
Other Long-Term Debt Redemptions and Maturities		0
Mississippi Power [Member]
Debt Instrument [Line Items]
Senior Note Issuances		0
Senior Note Maturities and Redemptions		0
Revenue Bond Maturities Redemptions and Repurchases		0
Other Long-Term Debt Issuances		1,100,000,000
Other Long-Term Debt Redemptions and Maturities		651,000,000
Southern Power [Member]
Debt Instrument [Line Items]
Senior Note Issuances		1,241,000,000
Senior Note Maturities and Redemptions		0
Revenue Bond Maturities Redemptions and Repurchases		0
Other Long-Term Debt Issuances		2,000,000
Other Long-Term Debt Redemptions and Maturities		4,000,000
Other [Member]
Debt Instrument [Line Items]
Senior Note Issuances		0
Senior Note Maturities and Redemptions		0
Revenue Bond Maturities Redemptions and Repurchases		0
Other Long-Term Debt Issuances		0
Other Long-Term Debt Redemptions and Maturities		$ 10,000,000

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Financing - Narrative (Details)			1 Months Ended			3 Months Ended	6 Months Ended
	Jun. 27, 2016 USD ($)	Mar. 08, 2016 USD ($)	May 31, 2016 USD ($)	Mar. 31, 2016 USD ($)	Jan. 31, 2016 USD ($)	Jun. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)	Jun. 30, 2016 EUR (€)	Mar. 14, 2016 USD ($)	Jan. 29, 2016 USD ($)	Jan. 19, 2016 USD ($)	Dec. 31, 2015 USD ($)
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding						$ 1,900,000,000	$ 1,900,000,000
Maximum Borrowing Capacity						6,500,000,000	6,500,000,000
Senior Note Issuances							10,791,000,000
Remaining Borrowing Capacity						6,387,000,000	6,387,000,000
Alabama Power [Member]
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding						890,000,000	890,000,000
Fixed rate pollution control revenue bonds outstanding						87,000,000	87,000,000
Maximum Borrowing Capacity						1,335,000,000	1,335,000,000
Senior Note Issuances							400,000,000
Repayments of Senior Debt							200,000,000	$ 250,000,000
Capital contributions from parent company							237,000,000	10,000,000
Remaining Borrowing Capacity						1,335,000,000	1,335,000,000
Alabama Power [Member] | Series FF [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage					5.20%
Alabama Power [Member] | Senior Notes [Member] | Series 2016A [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount					$ 400,000,000
Debt Instrument, Interest Rate, Stated Percentage					4.30%
Alabama Power [Member] | Unsecured Debt [Member] | Series FF [Member]
Debt Instrument [Line Items]
Repayments of Senior Debt					$ 200,000,000
Alabama Power [Member] | Bank Loans [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount				$ 45,000,000
Debt Instrument, Interest Rate, Stated Percentage				2.38%
Georgia Power [Member]
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding						868,000,000	868,000,000
Fixed rate pollution control revenue bonds outstanding						212,000,000	212,000,000
Line of Credit Facility, Current Borrowing Capacity						300,000,000	300,000,000
Maximum Borrowing Capacity						1,750,000,000	1,750,000,000
Senior Note Issuances							650,000,000
Repayments of Senior Debt							500,000,000	125,000,000
Capital contributions from parent company							239,000,000	23,000,000
Remaining Borrowing Capacity						$ 1,732,000,000	$ 1,732,000,000
Georgia Power [Member] | Senior Notes [Member] | Series 2016A [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount				$ 325,000,000
Debt Instrument, Interest Rate, Stated Percentage				3.25%
Georgia Power [Member] | Senior Notes [Member] | Series 2016B [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount				$ 325,000,000
Debt Instrument, Interest Rate, Stated Percentage				2.40%
Georgia Power [Member] | Unsecured Debt [Member] | Series 2013B [Member]
Debt Instrument [Line Items]
Repayments of Senior Debt				$ 250,000,000
Georgia Power [Member] | Line of Credit [Member] | FFB Credit Facility due 2044 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage						2.571%	2.571%		2.571%
Gulf Power [Member]
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding						$ 82,000,000	$ 82,000,000
Fixed rate pollution control revenue bonds outstanding						21,000,000	21,000,000
Maximum Borrowing Capacity						280,000,000	280,000,000
Senior Note Issuances							0
Repayments of Senior Debt							125,000,000	0
Remaining Borrowing Capacity						280,000,000	280,000,000
Gulf Power [Member] | Series 2011A [Member]
Debt Instrument [Line Items]
Redemption Amount Of Principal Notes			$ 125,000,000
Gulf Power [Member] | Senior Notes [Member] | Series 2011A [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			5.75%
Gulf Power [Member] | Bank Loans [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 100,000,000
Debt instrument term			11 months
Mississippi Power [Member]
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding						40,000,000	40,000,000
Line of Credit Facility, Current Borrowing Capacity						100,000,000	100,000,000			$ 50,000,000	$ 50,000,000	$ 100,000,000
Maximum Borrowing Capacity						175,000,000	175,000,000
Senior Note Issuances							0
Promissory Note					$ 275,000,000		0	301,000,000
Capital contributions from parent company	$ 225,000,000						226,000,000	77,000,000
Long-term Debt, Affiliated						551,000,000	551,000,000						$ 576,000,000
Remaining Borrowing Capacity						150,000,000	150,000,000
Mississippi Power [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Redemption Amount Of Principal Notes		$ 300,000,000
Mississippi Power [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		900,000,000
Maximum Borrowing Capacity		1,200,000,000.00
Remaining Borrowing Capacity		300,000,000
Mississippi Power [Member] | Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Repayments of Senior Debt		$ 900,000,000
Mississippi Power [Member] | Notes Payable, Other Payables [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount						10,000,000	10,000,000
Traditional Operating Companies [Member]
Debt Instrument [Line Items]
Fixed rate pollution control revenue bonds outstanding						320,000,000	320,000,000
Southern Power [Member]
Debt Instrument [Line Items]
Maximum Borrowing Capacity						600,000,000	600,000,000
Senior Note Issuances							1,241,000,000
Capital contributions from parent company							300,000,000	$ 0
Remaining Borrowing Capacity						$ 560,000,000	$ 560,000,000
Southern Power [Member] | Senior Notes [Member] | Series 2016A [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount | €									€ 600,000,000
Debt Instrument, Interest Rate, Stated Percentage						1.00%	1.00%		1.00%
Southern Power [Member] | Senior Notes [Member] | Series 2016B [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount | €									€ 500,000,000
Debt Instrument, Interest Rate, Stated Percentage						1.85%	1.85%		1.85%
Southern Power [Member] | Project Credit Facilities [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity						$ 769,000,000	$ 769,000,000
Debt, Weighted Average Interest Rate						2.02%	2.02%		2.02%
Maximum Borrowing Capacity						$ 769,000,000	$ 769,000,000
Line of Credit Facility, Average Amount Outstanding						$ 586,000,000	586,000,000
Debt Instrument, Interest Rate During Period						2.03%
Southern Power [Member] | Letter of Credit [Member]
Debt Instrument [Line Items]
Maximum Borrowing Capacity						$ 149,000,000	149,000,000
Remaining Borrowing Capacity						65,000,000	65,000,000
Southern Company [Member]
Debt Instrument [Line Items]
Maximum Borrowing Capacity						2,250,000,000	2,250,000,000
Senior Note Issuances			$ 8,500,000,000.0				8,500,000,000
Remaining Borrowing Capacity						$ 2,250,000,000	2,250,000,000
Southern Company [Member] | Senior Notes [Member] | Senior Notes due July 1, 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 500,000,000
Debt Instrument, Interest Rate, Stated Percentage			1.55%
Southern Company [Member] | Senior Notes [Member] | Senior Notes due July 1, 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 1,000,000,000
Debt Instrument, Interest Rate, Stated Percentage			1.85%
Southern Company [Member] | Senior Notes [Member] | Senior Notes due July 1, 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 1,500,000,000.0
Debt Instrument, Interest Rate, Stated Percentage			2.35%
Southern Company [Member] | Senior Notes [Member] | Senior Notes due July 1, 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 1,250,000,000.00
Debt Instrument, Interest Rate, Stated Percentage			2.95%
Southern Company [Member] | Senior Notes [Member] | Senior Notes due July 1, 2026 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 1,750,000,000.00
Debt Instrument, Interest Rate, Stated Percentage			3.25%
Southern Company [Member] | Senior Notes [Member] | Senior Notes due July 1, 2036 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 500,000,000
Debt Instrument, Interest Rate, Stated Percentage			4.25%
Southern Company [Member] | Senior Notes [Member] | Senior Notes due July 1, 2046 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 2,000,000,000
Debt Instrument, Interest Rate, Stated Percentage			4.40%
Southern Power's Subsidiary(ies) [Member]
Debt Instrument [Line Items]
Proceeds from Long-term Lines of Credit							$ 632,000,000
Southern Power's Subsidiary(ies) [Member] | Line of Credit [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate						2.00%	2.00%		2.00%
Southern Power's Subsidiary(ies) [Member] | Letter of Credit [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount						$ 16,000,000	$ 16,000,000

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Retirement Benefits (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated future employer contributions in next fiscal year			$ 0
Pension Plans [Member] | Southern Company [Member]
Pension Plans and Postretirement Plans
Service cost	$ 62,000,000	$ 64,000,000	124,000,000	$ 128,000,000
Interest cost	101,000,000	111,000,000	201,000,000	222,000,000
Expected return on plan assets	(187,000,000)	(181,000,000)	(374,000,000)	(362,000,000)
Amortization:
Prior service costs	3,000,000	7,000,000	7,000,000	13,000,000
Net (gain)/loss	37,000,000	54,000,000	75,000,000	108,000,000
Net cost	16,000,000	55,000,000	33,000,000	109,000,000
Pension Plans [Member] | Alabama Power [Member]
Pension Plans and Postretirement Plans
Service cost	15,000,000	15,000,000	29,000,000	30,000,000
Interest cost	24,000,000	27,000,000	48,000,000	53,000,000
Expected return on plan assets	(46,000,000)	(44,000,000)	(92,000,000)	(89,000,000)
Amortization:
Prior service costs	0	1,000,000	1,000,000	3,000,000
Net (gain)/loss	10,000,000	13,000,000	20,000,000	27,000,000
Net cost	3,000,000	12,000,000	6,000,000	24,000,000
Pension Plans [Member] | Georgia Power [Member]
Pension Plans and Postretirement Plans
Service cost	18,000,000	18,000,000	35,000,000	36,000,000
Interest cost	34,000,000	39,000,000	68,000,000	77,000,000
Expected return on plan assets	(65,000,000)	(63,000,000)	(129,000,000)	(126,000,000)
Amortization:
Prior service costs	2,000,000	2,000,000	3,000,000	5,000,000
Net (gain)/loss	13,000,000	19,000,000	27,000,000	38,000,000
Net cost	2,000,000	15,000,000	4,000,000	30,000,000
Pension Plans [Member] | Gulf Power [Member]
Pension Plans and Postretirement Plans
Service cost	3,000,000	3,000,000	6,000,000	6,000,000
Interest cost	4,000,000	5,000,000	9,000,000	10,000,000
Expected return on plan assets	(8,000,000)	(8,000,000)	(17,000,000)	(16,000,000)
Amortization:
Prior service costs	1,000,000	0	1,000,000	0
Net (gain)/loss	1,000,000	2,000,000	3,000,000	5,000,000
Net cost	1,000,000	2,000,000	2,000,000	5,000,000
Pension Plans [Member] | Mississippi Power [Member]
Pension Plans and Postretirement Plans
Service cost	3,000,000	3,000,000	6,000,000	6,000,000
Interest cost	5,000,000	6,000,000	10,000,000	11,000,000
Expected return on plan assets	(8,000,000)	(9,000,000)	(17,000,000)	(17,000,000)
Amortization:
Prior service costs	0	1,000,000	0	1,000,000
Net (gain)/loss	1,000,000	2,000,000	3,000,000	5,000,000
Net cost	1,000,000	3,000,000	2,000,000	6,000,000
Other Postretirement Benefits [Member] | Southern Company [Member]
Pension Plans and Postretirement Plans
Service cost	6,000,000	5,000,000	11,000,000	11,000,000
Interest cost	17,000,000	20,000,000	35,000,000	39,000,000
Expected return on plan assets	(14,000,000)	(14,000,000)	(28,000,000)	(29,000,000)
Amortization:
Prior service costs	1,000,000	1,000,000	3,000,000	2,000,000
Net (gain)/loss	4,000,000	4,000,000	7,000,000	9,000,000
Net cost	14,000,000	16,000,000	28,000,000	32,000,000
Other Postretirement Benefits [Member] | Alabama Power [Member]
Pension Plans and Postretirement Plans
Service cost	2,000,000	2,000,000	3,000,000	3,000,000
Interest cost	4,000,000	5,000,000	9,000,000	10,000,000
Expected return on plan assets	(7,000,000)	(7,000,000)	(13,000,000)	(13,000,000)
Amortization:
Prior service costs	1,000,000	0	2,000,000	1,000,000
Net (gain)/loss	1,000,000	1,000,000	1,000,000	1,000,000
Net cost	1,000,000	1,000,000	2,000,000	2,000,000
Other Postretirement Benefits [Member] | Georgia Power [Member]
Pension Plans and Postretirement Plans
Service cost	1,000,000	1,000,000	3,000,000	3,000,000
Interest cost	7,000,000	9,000,000	15,000,000	17,000,000
Expected return on plan assets	(5,000,000)	(6,000,000)	(11,000,000)	(12,000,000)
Amortization:
Prior service costs	1,000,000	0	1,000,000	0
Net (gain)/loss	2,000,000	3,000,000	4,000,000	6,000,000
Net cost	6,000,000	7,000,000	12,000,000	14,000,000
Other Postretirement Benefits [Member] | Gulf Power [Member]
Pension Plans and Postretirement Plans
Service cost	1,000,000	0	1,000,000	0
Interest cost	0	1,000,000	1,000,000	2,000,000
Expected return on plan assets	(1,000,000)	(1,000,000)	(1,000,000)	(1,000,000)
Amortization:
Prior service costs	0	0	0	0
Net (gain)/loss	0	0	0	0
Net cost	0	0	1,000,000	1,000,000
Other Postretirement Benefits [Member] | Mississippi Power [Member]
Pension Plans and Postretirement Plans
Service cost	1,000,000	1,000,000	1,000,000	1,000,000
Interest cost	1,000,000	1,000,000	2,000,000	2,000,000
Expected return on plan assets	(1,000,000)	(1,000,000)	(1,000,000)	(1,000,000)
Amortization:
Prior service costs	0	0	0	0
Net (gain)/loss	0	0	0	0
Net cost	$ 1,000,000	$ 1,000,000	$ 2,000,000	$ 2,000,000

XML

Income Taxes (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Income Tax Contingency [Line Items]
Operating loss carryforwards	$ 208		$ 188
Effective tax rate	30.40%	32.90%
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits as of December 31, 2015	$ 433
Tax positions from current periods	10
Balance as of June 30, 2016	443
Tax positions impacting the effective tax rate	20		10
Tax positions not impacting the effective tax rate	423		423
Kemper IGCC [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance as of June 30, 2016	423
Unrecognized tax benefit, associated interest	$ 15
Mississippi Power [Member]
Income Tax Contingency [Line Items]
Effective tax rate	(205.60%)	19.00%
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits as of December 31, 2015	$ 421
Tax positions from current periods	0
Balance as of June 30, 2016	421
Tax positions impacting the effective tax rate	(2)
Tax positions not impacting the effective tax rate	423
Mississippi Power [Member] | Kemper IGCC [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance as of June 30, 2016	423
Unrecognized tax benefit, associated interest	$ 15
Southern Power [Member]
Income Tax Contingency [Line Items]
Effective tax rate	(74.00%)	13.70%
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits as of December 31, 2015	$ 8
Tax positions from current periods	9
Balance as of June 30, 2016	17
Tax positions impacting the effective tax rate	17
Tax positions not impacting the effective tax rate	0
Investment Tax Credit Carryforward [Member]
Income Tax Contingency [Line Items]
Tax Credit Carryforward, Amount	801		554
Investment Tax Credit Carryforward [Member] | Southern Power [Member]
Income Tax Contingency [Line Items]
Tax Credit Carryforward, Amount	784		551
General Business Tax Credit Carryforward [Member]
Income Tax Contingency [Line Items]
Tax Credit Carryforward, Amount	16		1
General Business Tax Credit Carryforward [Member] | Southern Power [Member]
Income Tax Contingency [Line Items]
Tax Credit Carryforward, Amount	$ 16		$ 1

XML

Derivatives - Schedule of Derivatives and Gains (Losses) (Details) BTU in Millions, $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($) BTU
Southern Company [Member] | Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu | BTU	250
Longest Hedge Date	2020
Longest Non-Hedge Date	2016
Alabama Power [Member] | Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu | BTU	60
Longest Hedge Date	2019
Georgia Power [Member] | Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu | BTU	82
Longest Hedge Date	2019
Gulf Power [Member] | Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu | BTU	66
Longest Hedge Date	2020
Mississippi Power [Member] | Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu | BTU	29
Longest Hedge Date	2019
Southern Power [Member] | Maturity Date October 2016 [Member] | Not Designated as Hedging Instrument [Member]
Interest rate derivatives
Derivative term	15 years
Southern Power [Member] | Maturity Date November 2016 [Member] | Not Designated as Hedging Instrument [Member]
Interest rate derivatives
Derivative term	12 years
Southern Power [Member] | Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu | BTU	13
Longest Hedge Date	2017
Longest Non-Hedge Date	2016
Interest Rate Contract [Member]
Interest rate derivatives
Notional Amount	$ 1,968
Fair Value Gain (Loss) at June 30, 2016	20
Interest Rate Contract [Member] | Southern Company [Member] | Maturity Date June 2020 Number One [Member] | Cash Flow Hedges Of Existing Debt [Member]
Interest rate derivatives
Notional Amount	$ 8
Weighted Average Interest Rate Paid	1.73%
Fair Value Gain (Loss) at June 30, 2016	$ 0
Interest Rate Contract [Member] | Southern Company [Member] | Maturity Date June 2020 Number Two [Member] | Cash Flow Hedges Of Existing Debt [Member]
Interest rate derivatives
Notional Amount	$ 3
Weighted Average Interest Rate Paid	1.73%
Fair Value Gain (Loss) at June 30, 2016	$ 0
Interest Rate Contract [Member] | Southern Company [Member] | Maturity Date August 2017 [Member] | Fair Value Hedges Of Existing Debt [Member]
Interest rate derivatives
Notional Amount	$ 250
Interest Rate Received	1.30%
Fair Value Gain (Loss) at June 30, 2016	$ 2
Interest Rate Contract [Member] | Southern Company [Member] | Maturity Date August 2017 [Member] | London Interbank Offered Rate (LIBOR) [Member] | Fair Value Hedges Of Existing Debt [Member]
Interest rate derivatives
Weighted Average Interest Rate Paid	0.17%
Interest Rate Contract [Member] | Southern Company [Member] | Maturity Date June 2020 [Member] | Fair Value Hedges Of Existing Debt [Member]
Interest rate derivatives
Notional Amount	$ 300
Interest Rate Received	2.75%
Fair Value Gain (Loss) at June 30, 2016	$ 11
Interest Rate Contract [Member] | Southern Company [Member] | Maturity Date June 2020 [Member] | London Interbank Offered Rate (LIBOR) [Member] | Fair Value Hedges Of Existing Debt [Member]
Interest rate derivatives
Weighted Average Interest Rate Paid	0.92%
Interest Rate Contract [Member] | Georgia Power [Member] | Maturity Date August 2016 [Member] | Cash Flow Hedges Of Existing Debt [Member]
Interest rate derivatives
Notional Amount	$ 200
Weighted Average Interest Rate Paid	1.01%
Fair Value Gain (Loss) at June 30, 2016	$ 0
Interest Rate Contract [Member] | Georgia Power [Member] | Maturity Date August 2016 [Member] | London Interbank Offered Rate (LIBOR) [Member] | Cash Flow Hedges Of Existing Debt [Member]
Interest rate derivatives
Interest Rate Received	0.40%
Interest Rate Contract [Member] | Georgia Power [Member] | Maturity Date June 2018 [Member] | Fair Value Hedges Of Existing Debt [Member]
Interest rate derivatives
Notional Amount	$ 250
Interest Rate Received	5.40%
Fair Value Gain (Loss) at June 30, 2016	$ 3
Interest Rate Contract [Member] | Georgia Power [Member] | Maturity Date June 2018 [Member] | London Interbank Offered Rate (LIBOR) [Member] | Fair Value Hedges Of Existing Debt [Member]
Interest rate derivatives
Weighted Average Interest Rate Paid	4.02%
Interest Rate Contract [Member] | Georgia Power [Member] | Maturity Date December 2019 [Member] | Fair Value Hedges Of Existing Debt [Member]
Interest rate derivatives
Notional Amount	$ 200
Interest Rate Received	4.25%
Fair Value Gain (Loss) at June 30, 2016	$ 6
Interest Rate Contract [Member] | Georgia Power [Member] | Maturity Date December 2019 [Member] | London Interbank Offered Rate (LIBOR) [Member] | Fair Value Hedges Of Existing Debt [Member]
Interest rate derivatives
Weighted Average Interest Rate Paid	2.46%
Interest Rate Contract [Member] | Georgia Power [Member] | Maturity Date December 2018 [Member] | Fair Value Hedges Of Existing Debt [Member]
Interest rate derivatives
Notional Amount	$ 500
Interest Rate Received	1.95%
Fair Value Gain (Loss) at June 30, 2016	$ 5
Interest Rate Contract [Member] | Georgia Power [Member] | Maturity Date December 2018 [Member] | London Interbank Offered Rate (LIBOR) [Member] | Fair Value Hedges Of Existing Debt [Member]
Interest rate derivatives
Weighted Average Interest Rate Paid	0.76%
Interest Rate Contract [Member] | Gulf Power [Member] | Maturity Date December 2026 [Member] | Cash Flow Hedges Of Forecasted Debt [Member]
Interest rate derivatives
Notional Amount	$ 80
Weighted Average Interest Rate Paid	2.32%
Fair Value Gain (Loss) at June 30, 2016	$ (7)
Interest Rate Contract [Member] | Southern Power [Member] | Maturity Date October 2016 Number One [Member] | Not Designated as Hedging Instrument [Member]
Interest rate derivatives
Notional Amount	$ 65
Weighted Average Interest Rate Paid	2.50%
Fair Value Gain (Loss) at June 30, 2016	$ 0
Interest Rate Contract [Member] | Southern Power [Member] | Maturity Date October 2016 [Member] | Not Designated as Hedging Instrument [Member]
Interest rate derivatives
Notional Amount	$ 47
Weighted Average Interest Rate Paid	2.21%
Fair Value Gain (Loss) at June 30, 2016	$ 0
Interest Rate Contract [Member] | Southern Power [Member] | Maturity Date November 2016 [Member] | Not Designated as Hedging Instrument [Member]
Interest rate derivatives
Notional Amount	$ 65
Weighted Average Interest Rate Paid	2.21%
Fair Value Gain (Loss) at June 30, 2016	$ 0
Foreign Exchange Contract [Member] | Cash Flow Hedges Of Existing Debt [Member]
Interest rate derivatives
Fair Value Gain (Loss) at June 30, 2016	(38)
Foreign Exchange Contract [Member] | Southern Power [Member] | Maturity Date June 2022 [Member] | Cash Flow Hedges Of Existing Debt [Member]
Interest rate derivatives
Fair Value Gain (Loss) at June 30, 2016	(17)
Foreign Exchange Contract [Member] | Southern Power [Member] | Maturity Date June 2026 [Member] | Cash Flow Hedges Of Existing Debt [Member]
Interest rate derivatives
Fair Value Gain (Loss) at June 30, 2016	$ (21)

XML

Derivatives - Foreign Currency Derivatives (Details) - 6 months ended Jun. 30, 2016 - Cash Flow Hedges Of Existing Debt [Member] - Foreign Exchange Contract [Member] € in Millions, $ in Millions	USD ($)	EUR (€)
Derivative [Line Items]
Pay Notional	$ 1,241
Receive Notional | €		€ 1,100
Fair Value Gain (Loss) at June 30, 2016	(38)
Maturity Date June 2022 [Member] | Southern Power [Member]
Derivative [Line Items]
Pay Notional	$ 677
Pay Rate	2.95%
Receive Notional | €		600
Receive Rate	1.00%
Fair Value Gain (Loss) at June 30, 2016	$ (17)
Maturity Date June 2026 [Member] | Southern Power [Member]
Derivative [Line Items]
Pay Notional	$ 564
Pay Rate	3.78%
Receive Notional | €		€ 500
Receive Rate	1.85%
Fair Value Gain (Loss) at June 30, 2016	$ (21)

XML

Derivatives - Balance Sheet Presentation (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	$ 1
Southern Company [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	63	$ 29
Derivatives, liabilities	155	250
Southern Company [Member] | Energy Related Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount offset against collateral	4	1
Derivative liability amount offset against collateral	78	214
Southern Company [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	36	7
Derivatives, liabilities	110	220
Southern Company [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount not offset against collateral	32	6
Derivative liability amount not offset against collateral	32	6
Southern Company [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount offset against collateral		13
Derivative liability amount offset against collateral		21
Southern Company [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets		22
Derivatives, liabilities		30
Southern Company [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount not offset against collateral		9
Derivative liability amount not offset against collateral		9
Southern Company [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets		4
Southern Company [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	1
Southern Company [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities		1
Southern Company [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets		3
Southern Company [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	28
Derivatives, liabilities	105	217
Southern Company [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	12	3
Southern Company [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	16
Southern Company [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	61	130
Southern Company [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	44	87
Southern Company [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	33	22
Derivatives, liabilities	49	32
Southern Company [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	5	3
Southern Company [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	1
Southern Company [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	3	2
Southern Company [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1
Southern Company [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	11	19
Southern Company [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	16
Southern Company [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	7	23
Southern Company [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities		7
Southern Company [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	24
Southern Company [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	14
Alabama Power [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	10	1
Derivatives, liabilities	22	70
Alabama Power [Member] | Energy Related Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount offset against collateral	2	0
Derivative liability amount offset against collateral	14	54
Alabama Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	10	1
Derivatives, liabilities	22	55
Alabama Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount not offset against collateral	8	1
Derivative liability amount not offset against collateral	8	1
Alabama Power [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount offset against collateral		0
Derivative liability amount offset against collateral		15
Alabama Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets		0
Derivatives, liabilities		15
Alabama Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount not offset against collateral		0
Derivative liability amount not offset against collateral		0
Alabama Power [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets		0
Alabama Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Alabama Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Alabama Power [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets		0
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	10
Derivatives, liabilities	22	55
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	5	1
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	5
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	17	40
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	5	15
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Derivatives, liabilities	0	15
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	15
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities		0
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0
Georgia Power [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	29	7
Derivatives, liabilities	5	21
Georgia Power [Member] | Energy Related Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount offset against collateral	11	0
Derivative liability amount offset against collateral	1	13
Georgia Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	15	2
Derivatives, liabilities	5	15
Georgia Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount not offset against collateral	4	2
Derivative liability amount not offset against collateral	4	2
Georgia Power [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount offset against collateral		1
Derivative liability amount offset against collateral		2
Georgia Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets		5
Derivatives, liabilities		6
Georgia Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount not offset against collateral		4
Derivative liability amount not offset against collateral		4
Georgia Power [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets		0
Georgia Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Georgia Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Georgia Power [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets		0
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	15
Derivatives, liabilities	5	15
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	6	2
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	9
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	4	12
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1	3
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	14	5
Derivatives, liabilities	0	6
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	6	5
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	8
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities		6
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0
Gulf Power [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	1
Derivatives, liabilities	62	100
Gulf Power [Member] | Energy Related Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount offset against collateral	0	0
Derivative liability amount offset against collateral	53	100
Gulf Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	0
Derivatives, liabilities	55	100
Gulf Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount not offset against collateral	2	0
Derivative liability amount not offset against collateral	2	0
Gulf Power [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount offset against collateral		1
Derivative liability amount offset against collateral		0
Gulf Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets		1
Derivatives, liabilities		0
Gulf Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount not offset against collateral		0
Derivative liability amount not offset against collateral		0
Gulf Power [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets		0
Gulf Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Gulf Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Gulf Power [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets		0
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	2
Derivatives, liabilities	55	100
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	0
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	1
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	25	49
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	30	51
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	1
Derivatives, liabilities	7	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	1
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	7	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities		0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0
Mississippi Power [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	0
Derivatives, liabilities	23	47
Mississippi Power [Member] | Energy Related Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount offset against collateral	0	0
Derivative liability amount offset against collateral	22	47
Mississippi Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	0
Derivatives, liabilities	23	47
Mississippi Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount not offset against collateral	1	0
Derivative liability amount not offset against collateral	1	0
Mississippi Power [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount offset against collateral		0
Derivative liability amount offset against collateral		0
Mississippi Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets		0
Derivatives, liabilities		0
Mississippi Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount not offset against collateral		0
Derivative liability amount not offset against collateral		0
Mississippi Power [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets		0
Mississippi Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Mississippi Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Mississippi Power [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets		0
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	1
Derivatives, liabilities	23	47
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	1
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	15	29
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	8	18
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Derivatives, liabilities	0	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities		0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0
Southern Power [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	8	7
Derivatives, liabilities	43	3
Southern Power [Member] | Energy Related Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount offset against collateral	5	3
Derivative liability amount offset against collateral	2	2
Southern Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	8	4
Derivatives, liabilities	5	3
Southern Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount not offset against collateral	3	1
Derivative liability amount not offset against collateral	3	1
Southern Power [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount offset against collateral		3
Derivative liability amount offset against collateral		0
Southern Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets		3
Derivatives, liabilities		0
Southern Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivatives, Fair Value [Line Items]
Derivative asset amount not offset against collateral		0
Derivative liability amount not offset against collateral		0
Southern Power [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets		4
Southern Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	1
Southern Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1	1
Southern Power [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets		3
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	6	3
Derivatives, liabilities	42	2
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	5	3
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	1
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	3	2
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities		$ 0
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	24
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	$ 14

XML

Derivatives - Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Southern Company [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	$ 63	$ 29
Derivatives presented in the Balance Sheet, liabilities	155	250
Southern Company [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Net derivative assets	4	1
Net interest rate derivative liabilities	78	214
Southern Company [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	36	7
Derivatives presented in the Balance Sheet, liabilities	110	220
Southern Company [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	(32)	(6)
Gross amounts not offset in the Balance Sheet, liabilities	(32)	(6)
Southern Company [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Net derivative assets	9
Net interest rate derivative liabilities	27
Southern Company [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	27
Derivatives presented in the Balance Sheet, liabilities	45
Southern Company [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	(18)
Gross amounts not offset in the Balance Sheet, liabilities	(18)
Alabama Power [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	10	1
Derivatives presented in the Balance Sheet, liabilities	22	70
Alabama Power [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Net derivative assets	2	0
Net interest rate derivative liabilities	14	54
Alabama Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	10	1
Derivatives presented in the Balance Sheet, liabilities	22	55
Alabama Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	(8)	(1)
Gross amounts not offset in the Balance Sheet, liabilities	(8)	(1)
Alabama Power [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Net derivative assets	0
Net interest rate derivative liabilities	0
Alabama Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	0
Derivatives presented in the Balance Sheet, liabilities	0
Alabama Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	0
Gross amounts not offset in the Balance Sheet, liabilities	0
Georgia Power [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	29	7
Derivatives presented in the Balance Sheet, liabilities	5	21
Georgia Power [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Net derivative assets	11	0
Net interest rate derivative liabilities	1	13
Georgia Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	15	2
Derivatives presented in the Balance Sheet, liabilities	5	15
Georgia Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	(4)	(2)
Gross amounts not offset in the Balance Sheet, liabilities	(4)	(2)
Georgia Power [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Net derivative assets	14
Net interest rate derivative liabilities	0
Georgia Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	14
Derivatives presented in the Balance Sheet, liabilities	0
Georgia Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	0
Gross amounts not offset in the Balance Sheet, liabilities	0
Gulf Power [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	2	1
Derivatives presented in the Balance Sheet, liabilities	62	100
Gulf Power [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Net derivative assets	0	0
Net interest rate derivative liabilities	53	100
Gulf Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	2	0
Derivatives presented in the Balance Sheet, liabilities	55	100
Gulf Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	(2)	0
Gross amounts not offset in the Balance Sheet, liabilities	(2)	0
Gulf Power [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Net derivative assets	0
Net interest rate derivative liabilities	7
Gulf Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	0
Derivatives presented in the Balance Sheet, liabilities	7
Gulf Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	0
Gross amounts not offset in the Balance Sheet, liabilities	0
Mississippi Power [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	1	0
Derivatives presented in the Balance Sheet, liabilities	23	47
Mississippi Power [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Net derivative assets	0	0
Net interest rate derivative liabilities	22	47
Mississippi Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	1	0
Derivatives presented in the Balance Sheet, liabilities	23	47
Mississippi Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	(1)	0
Gross amounts not offset in the Balance Sheet, liabilities	(1)	0
Mississippi Power [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Net derivative assets	0
Net interest rate derivative liabilities	0
Mississippi Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	0
Derivatives presented in the Balance Sheet, liabilities	0
Mississippi Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	0
Gross amounts not offset in the Balance Sheet, liabilities	0
Southern Power [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	8	7
Derivatives presented in the Balance Sheet, liabilities	43	3
Southern Power [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Net derivative assets	5	3
Net interest rate derivative liabilities	2	2
Southern Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	8	4
Derivatives presented in the Balance Sheet, liabilities	5	3
Southern Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	(3)	(1)
Gross amounts not offset in the Balance Sheet, liabilities	(3)	$ (1)
Southern Power [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Net derivative assets	0
Net interest rate derivative liabilities	38
Southern Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	0
Derivatives presented in the Balance Sheet, liabilities	38
Southern Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	0
Gross amounts not offset in the Balance Sheet, liabilities	$ 0

XML

Derivatives - Pre-tax Effects of Derivatives Designated as Cash Flow Hedging Instruments (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Southern Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	$ (33)	$ 31	$ (223)	$ 2
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(25)	(2)	(28)	(4)
Southern Company [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(77)		(77)		$ (214)
Southern Company [Member] | Energy Related Derivative [Member] | Other regulatory assets, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(61)		(61)		(130)
Southern Company [Member] | Energy Related Derivative [Member] | Other regulatory assets, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(44)		(44)		(87)
Southern Company [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	12		12		3
Southern Company [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	16		16
Southern Company [Member] | Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	6	31	(184)	2
Southern Company [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(4)	(2)	(7)	(4)
Southern Company [Member] | Foreign Exchange Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(39)	0		0
Southern Company [Member] | Foreign Exchange Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(1)	0	(1)	0
Southern Company [Member] | Foreign Exchange Contract [Member] | Other Income Expense Net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(20)		(20)
Alabama Power [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(12)		(12)		(54)
Alabama Power [Member] | Energy Related Derivative [Member] | Other regulatory assets, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(17)		(17)		(40)
Alabama Power [Member] | Energy Related Derivative [Member] | Other regulatory assets, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(5)		(5)		(15)
Alabama Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	5		5		1
Alabama Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	5		5
Alabama Power [Member] | Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	7	(4)	1
Alabama Power [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(2)	(1)	(3)	(1)
Georgia Power [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	10		10		(13)
Georgia Power [Member] | Energy Related Derivative [Member] | Other regulatory assets, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(4)		(4)		(12)
Georgia Power [Member] | Energy Related Derivative [Member] | Other regulatory assets, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(1)		(1)		(3)
Georgia Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	6		6		2
Georgia Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	9		9
Georgia Power [Member] | Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	24	0	1
Georgia Power [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(1)	(1)	(2)	(2)
Gulf Power [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(53)		(53)		(100)
Gulf Power [Member] | Energy Related Derivative [Member] | Other regulatory assets, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(25)		(25)		(49)
Gulf Power [Member] | Energy Related Derivative [Member] | Other regulatory assets, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(30)		(30)		(51)
Gulf Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	1		1		0
Gulf Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	1		1
Gulf Power [Member] | Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(2)	0	(7)	0
Gulf Power [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	0	0	0	0
Mississippi Power [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(22)		(22)		(47)
Mississippi Power [Member] | Energy Related Derivative [Member] | Other regulatory assets, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(15)		(15)		(29)
Mississippi Power [Member] | Energy Related Derivative [Member] | Other regulatory assets, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(8)		(8)		(18)
Mississippi Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	0		0		$ 0
Mississippi Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	1		1
Mississippi Power [Member] | Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			0	0
Mississippi Power [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			(1)	(1)
Southern Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(39)	0	(39)	0
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(21)	0	(22)	0
Southern Power [Member] | Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)			0	0
Southern Power [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			(1)	0
Southern Power [Member] | Foreign Exchange Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(39)	0	(39)	0
Southern Power [Member] | Foreign Exchange Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(1)	$ 0	(1)	$ 0
Southern Power [Member] | Foreign Exchange Contract [Member] | Other Income Expense Net [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	$ (20)		$ (20)

XML

Derivatives - Pre-tax Effects of Derivatives as Fair Value Hedging Relationships (Details) - Interest Rate Contract [Member] - Interest Expense [Member] - Fair Value Hedging [Member] - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Southern Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Assets, Fair Value, Gross Asset	$ 24	$ 4
Georgia Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Assets, Fair Value, Gross Asset	$ 15	$ 2

XML

Derivatives - Narrative (Details) BTU in Millions, $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($) BTU
Derivative [Line Items]
Foreign Currency Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months	$ (24)
Maximum Potential Collateral Requirements Arising from Credit Risk Related Contingent Features	$ 24
Southern Company [Member]
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | BTU	3

XML

Acquisitions - Schedule of Acquisitions (Details) $ in Millions	Jul. 01, 2016 MW	Jun. 30, 2016 USD ($) MW	Apr. 07, 2016 MW	Mar. 04, 2016 MW	Feb. 11, 2016 MW	Dec. 31, 2015 USD ($)
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Goodwill		$ 264				$ 2
Southern Power [Member]
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Goodwill		2				$ 2
Southern Company Gas [Member]
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Current assets		1,474
Property, plant, and equipment		9,795
Goodwill		6,333
Intangible assets		436
Regulatory assets		846
Other assets		273
Current liabilities		(2,205)
Deferred credits and other liabilities		(4,529)
Long-term debt		(4,261)
Noncontrolling interests		(160)
Total purchase price		8,002
PowerSecure International, Inc. [Member]
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Current assets		174
Property, plant, and equipment		48
Goodwill		262
Intangible assets		99
Other assets		8
Current liabilities		(111)
Long-term debt, including current portion		(47)
Deferred credits and other liabilities		(4)
Total purchase price		$ 429
Calipatria [Member] | Southern Power [Member]
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Approx. Nameplate Capacity, Solar (MW) | MW					20
Southern Power Percentage Ownership					90.00%
PPA Contract Period					20 years
East Pecos [Member] | Southern Power [Member]
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Approx. Nameplate Capacity, Solar (MW) | MW				120
Southern Power Percentage Ownership				100.00%
PPA Contract Period				15 years
Grant Wind, LLC [Member] | Southern Power [Member]
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Approx. Nameplate Capacity, Wind (MW) | MW			151
Southern Power Percentage Ownership			100.00%
PPA Contract Period			20 years
Passadumkeag [Member] | Southern Power [Member]
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Approx. Nameplate Capacity, Wind (MW) | MW		42
Southern Power Percentage Ownership		100.00%
PPA Contract Period		15 years
Henrietta [Member] | Subsequent Event [Member] | Southern Power [Member]
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Approx. Nameplate Capacity, Solar (MW) | MW	102
Southern Power Percentage Ownership	51.00%
PPA Contract Period	20 years
Lamesa [Member] | Subsequent Event [Member] | Southern Power [Member]
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Approx. Nameplate Capacity, Solar (MW) | MW	102
Southern Power Percentage Ownership	100.00%
PPA Contract Period	15 years
Rutherford [Member] | Subsequent Event [Member] | Southern Power [Member]
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Approx. Nameplate Capacity, Solar (MW) | MW	74
Southern Power Percentage Ownership	90.00%
PPA Contract Period	15 years
Series of Business Acquisitions [Member] | Southern Power [Member] | Class A Membership Interest [Member]
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Southern Power Percentage Ownership		100.00%
Percentage Of Entitled Cash Distributions		51.00%
Series of Business Acquisitions [Member] | SunPower Corp. [Member] | Class B Membership Interest [Member]
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Percentage Of Entitled Cash Distributions		49.00%
Series of Business Acquisitions [Member] | Recurrent Energy [Member] | Class B Membership Interest [Member]
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net [Abstract]
Southern Power Percentage Ownership		100.00%

XML

Acquisitions - Schedule of Construction Projects (Details) - MW		3 Months Ended		10 Months Ended
	Jul. 19, 2016	Dec. 31, 2016	Sep. 30, 2016	Sep. 30, 2016	Aug. 08, 2016	Jun. 30, 2016	Mar. 29, 2016	Dec. 31, 2015
Southern Power [Member] | Desert Stateline Holdings, LLC [Member]
Business Acquisition [Line Items]
Southern Power Percentage Ownership							15.00%
Capacity Of Small Power Production Facility						152		110
Class A Membership Interest [Member] | Southern Power [Member] | Desert Stateline Holdings, LLC [Member]
Business Acquisition [Line Items]
Percentage Of Entitled Cash Distributions							66.00%
Class B Membership Interest [Member] | First Solar [Member] | Desert Stateline Holdings, LLC [Member]
Business Acquisition [Line Items]
Percentage Of Entitled Cash Distributions							34.00%
Subsequent Event [Member] | Southern Power [Member] | Desert Stateline Holdings, LLC [Member]
Business Acquisition [Line Items]
Capacity Of Small Power Production Facility					37
Subsequent Event [Member] | Southern Power [Member] | RE Tranquility Holdings, LLC [Member]
Business Acquisition [Line Items]
Approx. Nameplate Capacity, Solar (MW)	205
PPA Contract Period	18 years
Scenario, Forecast [Member] | Southern Power [Member] | Butler Solar LLC [Member]
Business Acquisition [Line Items]
Approx. Nameplate Capacity, Solar (MW)		103
PPA Contract Period		30 years
Scenario, Forecast [Member] | Southern Power [Member] | Desert Stateline Holdings, LLC [Member]
Business Acquisition [Line Items]
Approx. Nameplate Capacity, Solar (MW)			299	299
PPA Contract Period				20 years
Scenario, Forecast [Member] | Southern Power [Member] | RE Garland and Garland A Holdings, LLC [Member]
Business Acquisition [Line Items]
Approx. Nameplate Capacity, Solar (MW)		205
Scenario, Forecast [Member] | Southern Power [Member] | RE Garland Holdings, LLC [Member]
Business Acquisition [Line Items]
PPA Contract Period		15 years
Scenario, Forecast [Member] | Southern Power [Member] | RE Garland and Garland A Holdings, LLC [Member]
Business Acquisition [Line Items]
PPA Contract Period			20 years
Scenario, Forecast [Member] | Southern Power [Member] | RE Roserock Holdings, LLC [Member]
Business Acquisition [Line Items]
Approx. Nameplate Capacity, Solar (MW)		160
PPA Contract Period		20 years
Scenario, Forecast [Member] | Southern Power [Member] | Sandhills [Member]
Business Acquisition [Line Items]
Approx. Nameplate Capacity, Solar (MW)		146
PPA Contract Period		25 years

XML

Acquisitions - Narrative (Details) $ / shares in Units, $ in Millions								3 Months Ended	6 Months Ended
	Aug. 08, 2016 USD ($)	Jul. 10, 2016 USD ($) mi	Jul. 01, 2016 USD ($) MW	May 09, 2016 USD ($) $ / shares	Apr. 07, 2016 MW	Mar. 04, 2016 MW	Feb. 11, 2016 MW	Jun. 30, 2016 USD ($)	Dec. 31, 2016 USD ($) entities MW	Jun. 30, 2016 USD ($)	Dec. 31, 2015 USD ($)
Business Acquisition [Line Items]
Goodwill								$ 264.0		$ 264.0	$ 2.0
Construction work in progress								9,451.0		9,451.0	9,082.0
Property, Plant and Equipment, Gross								78,112.0		78,112.0	75,118.0
Other Assets, Current								71.0		71.0	71.0
Southern Power [Member]
Business Acquisition [Line Items]
Aggregate purchase price										477.0
Goodwill								2.0		2.0	2.0
Total costs of construction										2,700.0
Construction work in progress								1,852.0		1,852.0	1,137.0
Contingent consideration								23.0		23.0	36.0
Property, Plant and Equipment, Gross								8,348.0		8,348.0	7,275.0
Other Assets, Current								31.0		31.0	30.0
Accounts Payable, Other, Current								175.0		175.0	$ 327.0
Southern Power and Turner Renewable Energy [Member]
Business Acquisition [Line Items]
Aggregate purchase price										483.0
Subsequent Event [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Aggregate purchase price	$ 275.0
Subsequent Event [Member] | Southern Power and Turner Renewable Energy [Member]
Business Acquisition [Line Items]
Aggregate purchase price	447.0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities	217.0
Subsequent Event [Member] | Minimum [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Estimated Future Construction Payments	260.0
Subsequent Event [Member] | Maximum [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Estimated Future Construction Payments	$ 300.0
Southern Company Gas [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities								2,205.0		2,205.0
Goodwill								6,333.0		6,333.0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net								8,002.0		8,002.0
Southern Company Gas [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Aggregate purchase price			$ 8,000.0
Southern Company Gas [Member] | Bridge Agreement [Member]
Business Acquisition [Line Items]
Acquisition-related costs								43.4		63.3
Southern Company Gas [Member] | Bridge Agreement [Member] | Operating Expense [Member]
Business Acquisition [Line Items]
Acquisition-related costs								26.9		32.9
Southern Company Gas [Member] | Bridge Agreement [Member] | Other Income Expense Net [Member]
Business Acquisition [Line Items]
Acquisition-related costs								16.5		30.4
PowerSecure International, Inc. [Member]
Business Acquisition [Line Items]
Aggregate purchase price				$ 429.0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities								111.0		111.0
Acquisition, share price (in dollars per share) | $ / shares				$ 18.75
Goodwill								262.0		262.0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net								429.0		$ 429.0
PowerSecure International, Inc. [Member] | Minimum [Member]
Business Acquisition [Line Items]
Estimated lives of intangible assets										3 years
PowerSecure International, Inc. [Member] | Maximum [Member]
Business Acquisition [Line Items]
Estimated lives of intangible assets										26 years
Southern Natural Gas Company, LLC [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Aggregate purchase price		$ 1,500.0
Ownership percentage		50.00%
Pipeline Infrastructure (in miles) | mi		7,600
Grant Wind, LLC [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Ownership percentage					100.00%
Approx. Nameplate Capacity, Wind (MW) | MW					151
Life Output Of Plant					20 years
East Pecos [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Ownership percentage						100.00%
Approx. Nameplate Capacity, Solar (MW) | MW						120
Life Output Of Plant						15 years
East Pecos [Member] | Minimum [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Estimated Future Construction Payments								160.0		$ 160.0
East Pecos [Member] | Maximum [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Estimated Future Construction Payments								180.0		180.0
Series of Business Acquisitions [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Revenue of acquirees, actual										4.0
Construction work in progress								426.0		426.0
Contingent consideration								6.0		6.0
Property, Plant and Equipment, Gross								58.0		58.0
Other Assets, Current								4.0		4.0
Accounts Payable, Other, Current								7.0		7.0
Series of Construction Projects [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Construction work in progress								1,700.0		1,700.0
Series of Construction Projects [Member] | Minimum [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Estimated Future Construction Payments								3,000.0		3,000.0
Series of Construction Projects [Member] | Maximum [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Estimated Future Construction Payments								$ 3,200.0		$ 3,200.0
Calipatria [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Ownership percentage							90.00%
Approx. Nameplate Capacity, Solar (MW) | MW							20
Life Output Of Plant							20 years
Calipatria [Member] | Turner Renewable Energy [Member]
Business Acquisition [Line Items]
Ownership percentage								10.00%		10.00%
Henrietta [Member] | Subsequent Event [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Ownership percentage			51.00%
Approx. Nameplate Capacity, Solar (MW) | MW			102
Life Output Of Plant			20 years
Henrietta [Member] | Subsequent Event [Member] | SunPower AssetCo, LLC [Member]
Business Acquisition [Line Items]
Ownership percentage	49.00%
Rutherford [Member] | Subsequent Event [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Ownership percentage			90.00%
Approx. Nameplate Capacity, Solar (MW) | MW			74
Life Output Of Plant			15 years
Rutherford [Member] | Subsequent Event [Member] | Turner Renewable Energy [Member]
Business Acquisition [Line Items]
Ownership percentage	10.00%
Scenario, Forecast [Member] | Series of Business Acquisitions [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Aggregate purchase price									$ 1,100.0
Scenario, Forecast [Member] | Series of Business Acquisitions, Wind [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Ownership percentage									100.00%
Number of Businesses Acquired | entities									2
Approx. Nameplate Capacity, Wind (MW) | MW									299
Scenario, Forecast [Member] | Series of Business Acquisitions, Wind [Member] | Minimum [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Life Output Of Plant									12 years
Scenario, Forecast [Member] | Series of Business Acquisitions, Wind [Member] | Maximum [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Life Output Of Plant									14 years
Scenario, Forecast [Member] | Business Acquisition, Wind [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Ownership percentage									90.10%
Approx. Nameplate Capacity, Wind (MW) | MW									257
Life Output Of Plant									12 years
Scenario, Forecast [Member] | Boulder 1 [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Ownership percentage									51.00%
Approx. Nameplate Capacity, Solar (MW) | MW									100
Life Output Of Plant									20 years
Class A Membership Interest [Member] | Series of Business Acquisitions [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Ownership percentage								100.00%		100.00%
Class A Membership Interest [Member] | Scenario, Forecast [Member] | Boulder 1 [Member] | Southern Power [Member]
Business Acquisition [Line Items]
Ownership percentage									100.00%

XML

Segment and Related Information - Financial Data for Business Segments (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016 USD ($) state	Jun. 30, 2015 USD ($)	Jun. 30, 2016 USD ($) state	Jun. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)
Segment Reporting Information [Line Items]
Number of States in which Entity Operates | state	4		4
Operating revenues	$ 4,459	$ 4,337	$ 8,451	$ 8,520
Segment net income (loss)	612	629	1,097	1,138
Total assets	90,873		90,873		$ 78,318
Kemper IGCC [Member]
Segment Reporting Information [Line Items]
Pre-Tax Charge To Income	81	23	134	32
After Tax Charge To Income	50	14	83	20
Electric Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues	4,379	4,324	8,360	8,496
Segment net income (loss)	684	607	1,198	1,117
Total assets	81,363		81,363		77,560
Intersegment Eliminations [Member] | Electric Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues	(109)	(90)	(212)	(213)
Segment net income (loss)	0	0	0	0
Total assets	(425)		(425)		(397)
Consolidation Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	(45)	(30)	(81)	(59)
Segment net income (loss)	(4)	4	(7)	0
Total assets	(995)		(995)		(1,061)
Traditional Operating Companies [Member] | Electric Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues	4,115	4,077	7,884	8,025
Segment net income (loss)	595	561	1,059	1,038
Total assets	70,706		70,706		69,052
Southern Power [Member]
Segment Reporting Information [Line Items]
Operating revenues	107	85	204	199
Southern Power [Member] | Electric Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues	373	337	688	684
Segment net income (loss)	89	46	139	79
Total assets	11,082		11,082		8,905
All Other [Member]
Segment Reporting Information [Line Items]
Operating revenues	125	43	172	83
Segment net income (loss)	(68)	$ 18	(94)	$ 21
Total assets	$ 10,505		$ 10,505		$ 1,819

XML

Segment and Related Information - Financial Data for Products and Services (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	$ 4,379	$ 4,324	$ 8,360	$ 8,496
Retail [Member]
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	3,748	3,714	7,124	7,256
Wholesale [Member]
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	446	448	842	915
Other [Member]
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	$ 185	$ 162	$ 394	$ 325