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 March 31, 2015

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
333-98553	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 March 31, 2015
The Southern Company	Par Value $5 Per Share	908,261,371
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

March 31, 2015

		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	35
	Condensed Statements of Comprehensive Income	35
	Condensed Statements of Cash Flows	36
	Condensed Balance Sheets	37
	Management's Discussion and Analysis of Financial Condition and Results of Operations	39
	Georgia Power Company
	Condensed Statements of Income	51
	Condensed Statements of Comprehensive Income	51
	Condensed Statements of Cash Flows	52
	Condensed Balance Sheets	53
	Management's Discussion and Analysis of Financial Condition and Results of Operations	55
	Gulf Power Company
	Condensed Statements of Income	70
	Condensed Statements of Comprehensive Income	70
	Condensed Statements of Cash Flows	71
	Condensed Balance Sheets	72
	Management's Discussion and Analysis of Financial Condition and Results of Operations	74
	Mississippi Power Company
	Condensed Statements of Operations	86
	Condensed Statements of Comprehensive Income (Loss)	86
	Condensed Statements of Cash Flows	87
	Condensed Balance Sheets	88
	Management's Discussion and Analysis of Financial Condition and Results of Operations	90
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	113
	Condensed Consolidated Statements of Comprehensive Income	113
	Condensed Consolidated Statements of Cash Flows	114
	Condensed Consolidated Balance Sheets	115
	Management's Discussion and Analysis of Financial Condition and Results of Operations	117
	Notes to the Condensed Financial Statements	126
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	33
Item 4.	Controls and Procedures	33

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q

March 31, 2015

		Page Number
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	170
Item 1A.	Risk Factors	170
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	170
Item 3.	Defaults Upon Senior Securities	Inapplicable
Item 4.	Mine Safety Disclosures	Inapplicable
Item 5.	Other Information	Inapplicable
Item 6.	Exhibits	171
	Signatures	174

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 for Georgia Power for the years 2014 through 2016
AFUDC	Allowance for funds used during construction
Alabama Power	Alabama Power Company
ASC	Accounting Standards Codification
Baseload Act	State of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of Mississippi
CCR	Coal combustion residuals
Clean Air Act	Clean Air Act Amendments of 1990
Contractor	Westinghouse and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.), a subsidiary of The Shaw Group Inc., which was acquired by Chicago Bridge & Iron Company N.V.
CO2	Carbon dioxide
CPCN	Certificate of public convenience and necessity
CWIP	Construction work in progress
DOE	U.S. Department of Energy
ECO Plan	Mississippi Power's Environmental Compliance Overview Plan
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
FFB	Federal Financing Bank
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, 2014
GAAP	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 in Kemper County, Mississippi
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
MATS rule	Mercury and Air Toxics Standards rule
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

5

DEFINITIONS

(continued)

Term	Meaning
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 Plant Vogtle
power pool	The operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power Company are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA	Power purchase agreement
PSC	Public Service Commission
Rate CNP	Alabama Power's Rate Certificated New Plant
Rate CNP Compliance	Alabama Power's Rate Certificated New Plant Compliance
Rate CNP Environmental	Alabama Power's Rate Certificated New Plant Environmental
Rate CNP PPA	Alabama Power's Rate Certificated New Plant Power Purchase Agreement
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
SEC	U.S. Securities and Exchange Commission
SMEPA	South Mississippi Electric Power Association
Southern Company	The Southern Company
Southern Company system	Southern Company, the traditional operating companies, Southern Power, Southern Electric Generating Company, Southern Nuclear, Southern Company Services, Inc. (the Southern Company system service company), Southern Communications Services, Inc., and other subsidiaries
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company and its subsidiaries
traditional 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 recovery, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, access to sources of capital, projections for the qualified pension plan, postretirement benefit plan, and nuclear decommissioning trust fund contributions, financing activities, completion dates of acquisitions, construction projects, and changing fuel sources, filings with state and federal regulatory authorities, 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 electric utility industry, environmental laws including regulation of water, CCR, and emissions of sulfur, nitrogen, CO₂, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, 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 pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, and 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, 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 fuels;

• 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 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 and related legal proceedings involving the commercial parties;

• actions related to cost recovery for the Kemper IGCC, including actions relating to proposed securitization, Mississippi PSC approval of a rate recovery plan, including the ability to complete the proposed sale of an interest in the Kemper IGCC to SMEPA, the ability to utilize bonus depreciation, which currently requires that assets be placed in service in 2015, and satisfaction of requirements to utilize ITCs and grants;

• Mississippi PSC review of the prudence of Kemper IGCC costs;

7

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)

• the ultimate outcome and impact of the February 2015 decision of the Mississippi Supreme Court, Mississippi Power's request for rehearing of such decision, and any further legal or regulatory proceedings regarding any settlement agreement between Mississippi Power and the Mississippi PSC, the March 2013 rate order regarding retail rate increases, or the Baseload Act;

• the ability to successfully operate the electric utilities' generating, transmission, and distribution 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 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 ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;

• the ability to obtain new short- and long-term contracts with wholesale customers;

• the direct or indirect effect on the Southern Company system's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist incidents;

• interest rate fluctuations and financial market conditions and the results of financing efforts;

• changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;

• the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;

• the ability of Southern Company's subsidiaries to obtain additional generating capacity at competitive prices;

• catastrophic events such as fires, earthquakes, explosions, floods, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;

• the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid or operation of generating 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 March 31,
	2015			2014
	(in millions)
Operating Revenues:
Retail revenues	$	3,542		$	3,858
Wholesale revenues	467			604
Other electric revenues	163			165
Other revenues	11			17
Total operating revenues	4,183			4,644
Operating Expenses:
Fuel	1,212			1,647
Purchased power	144			187
Other operations and maintenance	1,122			986
Depreciation and amortization	487			497
Taxes other than income taxes	252			247
Estimated loss on Kemper IGCC	9			380
Total operating expenses	3,226			3,944
Operating Income	957			700
Other Income and (Expense):
Allowance for equity funds used during construction	63			57
Interest expense, net of amounts capitalized	(213		)	(206		)
Other income (expense), net	(8		)	(7		)
Total other income and (expense)	(158		)	(156		)
Earnings Before Income Taxes	799			544
Income taxes	274			176
Consolidated Net Income	525			368
Dividends on Preferred and Preference Stock of Subsidiaries	17			17
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	$	508		$	351
Common Stock Data:
Earnings per share (EPS) —
Basic EPS	$	0.56		$	0.39
Diluted EPS	$	0.56		$	0.39
Average number of shares of common stock outstanding (in millions)
Basic	910			890
Diluted	915			893
Cash dividends paid per share of common stock	$	0.5250		$	0.5075

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 March 31,
	2015			2014
	(in millions)
Consolidated Net Income	$	525		$	368
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(11) and $-, respectively	(18		)	—
Reclassification adjustment for amounts included in net income, net of tax of $1 and $1, respectively	1			1
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $1 and $-, respectively	2			1
Total other comprehensive income (loss)	(15		)	2
Dividends on preferred and preference stock of subsidiaries	(17		)	(17		)
Comprehensive Income	$	493		$	353

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 Three Months Ended March 31,
	2015			2014
	(in millions)
Operating Activities:
Consolidated net income	$	525		$	368
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	578			587
Deferred income taxes	113			(37		)
Allowance for equity funds used during construction	(63		)	(57		)
Stock based compensation expense	56			28
Estimated loss on Kemper IGCC	9			380
Other, net	4			(42		)
Changes in certain current assets and liabilities —
-Receivables	180			(128		)
-Fossil fuel stock	76			441
-Materials and supplies	4			(5		)
-Other current assets	(89		)	(114		)
-Accounts payable	(426		)	(109		)
-Accrued taxes	197			(44		)
-Accrued compensation	(381		)	(144		)
-Mirror CWIP	40			34
-Other current liabilities	90			(55		)
Net cash provided from operating activities	913			1,103
Investing Activities:
Property additions	(1,097		)	(1,180		)
Distribution of restricted cash	—			9
Nuclear decommissioning trust fund purchases	(290		)	(231		)
Nuclear decommissioning trust fund sales	284			229
Cost of removal, net of salvage	(36		)	(22		)
Change in construction payables, net	65			51
Prepaid long-term service agreement	(37		)	(64		)
Other investing activities	4			(7		)
Net cash used for investing activities	(1,107		)	(1,215		)
Financing Activities:
Increase (decrease) in notes payable, net	597			(884		)
Proceeds —
Long-term debt issuances	550			1,251
Interest-bearing refundable deposit	—			75
Common stock issuances	112			128
Short-term borrowings	280			—
Redemptions —
Long-term debt	(333		)	(9		)
Common stock repurchased	(115		)	(4		)
Payment of common stock dividends	(478		)	(451		)
Payment of dividends on preferred and preference stock of subsidiaries	(17		)	(17		)
Other financing activities	—			(46		)
Net cash provided from financing activities	596			43
Net Change in Cash and Cash Equivalents	402			(69		)
Cash and Cash Equivalents at Beginning of Period	710			659
Cash and Cash Equivalents at End of Period	$	1,112		$	590
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $32 and $22 capitalized for 2015 and 2014, respectively)	$	207		$	186
Income taxes, net	(289		)	(7		)
Noncash transactions — Accrued property additions at end of period	347			450

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 March 31, 2015			At December 31, 2014
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,112		$	710
Receivables —
Customer accounts receivable	1,117			1,090
Unbilled revenues	374			432
Under recovered regulatory clause revenues	159			136
Other accounts and notes receivable	241			307
Accumulated provision for uncollectible accounts	(19		)	(18		)
Fossil fuel stock, at average cost	855			930
Materials and supplies, at average cost	1,050			1,039
Vacation pay	178			177
Prepaid expenses	299			665
Deferred income taxes, current	578			506
Other regulatory assets, current	363			346
Other current assets	65			50
Total current assets	6,372			6,370
Property, Plant, and Equipment:
In service	70,279			70,013
Less accumulated depreciation	24,307			24,059
Plant in service, net of depreciation	45,972			45,954
Other utility plant, net	275			211
Nuclear fuel, at amortized cost	914			911
Construction work in progress	8,314			7,792
Total property, plant, and equipment	55,475			54,868
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,574			1,546
Leveraged leases	749			743
Miscellaneous property and investments	204			203
Total other property and investments	2,527			2,492
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,527			1,510
Unamortized debt issuance expense	200			202
Unamortized loss on reacquired debt	239			243
Other regulatory assets, deferred	4,462			4,334
Other deferred charges and assets	808			904
Total deferred charges and other assets	7,236			7,193
Total Assets	$	71,610		$	70,923

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 March 31, 2015			At December 31, 2014
	(in millions)
Current Liabilities:
Securities due within one year	$	3,306		$	3,333
Interest-bearing refundable deposit	275			275
Notes payable	1,679			803
Accounts payable	1,289			1,593
Customer deposits	395			390
Accrued taxes —
Accrued income taxes	198			151
Other accrued taxes	248			487
Accrued interest	286			295
Accrued vacation pay	222			223
Accrued compensation	186			576
Mirror CWIP	311			271
Other current liabilities	790			570
Total current liabilities	9,185			8,967
Long-term Debt	21,093			20,841
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	11,706			11,568
Deferred credits related to income taxes	185			192
Accumulated deferred investment tax credits	1,198			1,208
Employee benefit obligations	2,416			2,432
Asset retirement obligations	2,151			2,168
Other cost of removal obligations	1,209			1,215
Other regulatory liabilities, deferred	439			398
Other deferred credits and liabilities	619			594
Total deferred credits and other liabilities	19,923			19,775
Total Liabilities	50,201			49,583
Redeemable Preferred Stock of Subsidiaries	375			375
Redeemable Noncontrolling Interest	40			39
Stockholders' Equity:
Common Stockholders' Equity:
Common stock, par value $5 per share —
Authorized — 1.5 billion shares
Issued — March 31, 2015: 912 million shares
— December 31, 2014: 909 million shares
Treasury — March 31, 2015: 3.3 million shares
— December 31, 2014: 0.7 million shares
Par value	4,555			4,539
Paid-in capital	6,108			5,955
Treasury, at cost	(142		)	(26		)
Retained earnings	9,639			9,609
Accumulated other comprehensive loss	(143		)	(128		)
Total Common Stockholders' Equity	20,017			19,949
Preferred and Preference Stock of Subsidiaries	756			756
Noncontrolling Interest	221			221
Total Stockholders' Equity	20,994			20,926
Total Liabilities and Stockholders' Equity	$	71,610		$	70,923

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

14

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2015 vs. FIRST QUARTER 2014

OVERVIEW

Southern Company is a holding company that owns all of the common stock of the traditional 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 of electricity sales by the traditional operating companies and Southern Power. The four traditional 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 investments in leveraged lease projects and telecommunications. 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.

In addition, subsidiaries of Southern Company are constructing Plant Vogtle Units 3 and 4 and the Kemper IGCC. Georgia Power has a 45.7% ownership interest in Plant Vogtle Units 3 and 4, each with approximately 1,100 MWs, and Mississippi Power is ultimately expected to hold an 85% ownership interest in the 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.

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

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$157	44.7

Southern Company's first quarter 2015 net income after dividends on preferred and preference stock of subsidiaries was $508 million ($0.56 per share) compared to $351 million ($0.39 per share) for the first quarter 2014. The increase was primarily the result of a lower pre-tax charge of $9 million ($6 million after tax) recorded in the first quarter 2015 compared to a pre-tax charge of $380 million ($235 million after tax) recorded in the first quarter 2014 for revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC, as well as an increase in retail base rates. The increase in net income was partially offset by increases in non-fuel operations and maintenance expenses and a decrease in revenues due to milder weather in the first quarter 2015 as compared to the corresponding period in 2014.

15

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(316)	(8.2)

In the first quarter 2015, retail revenues were $3.5 billion compared to $3.9 billion for the corresponding period in 2014.

Details of the changes in retail revenues were as follows:

	First  Quarter 2015
	(in millions)			(% change)
Retail – prior year	$	3,858
Estimated change resulting from –
Rates and pricing	77			2.0
Sales growth	18			0.5
Weather	(38		)	(1.0	)
Fuel and other cost recovery	(373		)	(9.7	)
Retail – current year	$	3,542		(8.2	)%

Revenues associated with changes in rates and pricing increased in the first quarter 2015 when compared to the corresponding period in 2014 primarily due to increased revenues at Alabama Power associated with an increase in rates under rate stabilization and equalization (Rate RSE) and at Georgia Power related to base tariff increases approved under the 2013 ARP and increases in collections for financing costs related to the construction of Plant Vogtle Units 3 and 4 through the NCCR tariff, all effective January 1, 2015. The increase was partially offset by lower contributions from market-driven rates from commercial and industrial customers at Georgia Power. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate RSE" and "Retail Regulatory Matters – Georgia Power – Rate Plans" in Item 8 of the Form 10-K for additional information.

Revenues attributable to changes in sales increased in the first quarter 2015 as compared to the corresponding period in 2014. Industrial KWH sales increased 2.0% in the first quarter 2015 primarily due to increased sales in the paper, non-manufacturing, stone, clay, and glass, transportation, textiles, and pipeline sectors, partially offset by decreased sales in the primary metals and chemicals sectors. Weather-adjusted commercial KWH sales increased 0.7% in the first quarter 2015 primarily due to customer growth. Weather-adjusted residential KWH sales increased 0.2% in the first quarter 2015 as a result of customer growth, partially offset by decreased customer usage.

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 2014 KWH sales among customer classes that is consistent with the actual allocation in 2015. Without this adjustment, first quarter 2015 industrial KWH sales increased 1.9%, weather-adjusted commercial sales increased 0.3%, and weather-adjusted residential sales decreased 0.1% as compared to the corresponding period in 2014.

Fuel and other cost recovery revenues decreased $373 million in the first quarter 2015 when compared to the corresponding period in 2014 primarily due to a decrease in fuel prices and decreased energy sales as a result of milder weather in the first quarter 2015 as compared to the corresponding period in 2014.

Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income. The

16

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

traditional operating companies may also have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPAs.

Wholesale Revenues

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(137)	(22.7)

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 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. 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 first quarter 2015, wholesale revenues were $467 million compared to $604 million for the corresponding period in 2014 primarily related to a $118 million decrease in energy revenues and a $19 million decrease in capacity revenues. The decrease in energy revenues was primarily related to decreased demand resulting from milder weather in the first quarter 2015 as compared to the corresponding period in 2014 and lower natural gas prices, as well as contract expirations at Southern Power. The decrease in energy revenues was partially offset by new solar PPAs at Southern Power. The decrease in capacity revenues was primarily a result of the expiration of wholesale contracts in December 2014 at Georgia Power and contract expirations at Southern Power.

Fuel and Purchased Power Expenses

	First Quarter 2015 vs. First Quarter 2014
	(change in millions)			(% change)
Fuel	$	(435	)	(26.4)
Purchased power	(43		)	(23.0)
Total fuel and purchased power expenses	$	(478	)

In the first quarter 2015, total fuel and purchased power expenses were $1.4 billion compared to $1.8 billion for the corresponding period in 2014. The decrease was primarily the result of a $443 million decrease in the average cost of fuel and purchased power primarily due to lower coal and natural gas prices and a $35 million decrease in the volume of KWHs generated and purchased primarily due to decreased demand resulting from milder weather in the first quarter 2015 as compared to the corresponding period in 2014.

Fuel and purchased power energy transactions at the traditional 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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	First Quarter 2015	First Quarter 2014
Total generation (billions of KWHs)	46	47
Total purchased power (billions of KWHs)	3	3
Sources of generation (percent) —
Coal	33	47
Nuclear	16	16
Gas	47	33
Hydro	4	4
Cost of fuel, generated (cents per net KWH) —
Coal	3.70	4.19
Nuclear	0.67	0.89
Gas	2.71	4.19
Average cost of fuel, generated (cents per net KWH)	2.71	3.63
Average cost of purchased power (cents per net KWH)(a)	7.18	8.89

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

Fuel

In the first quarter 2015, fuel expense was $1.2 billion compared to $1.6 billion for the corresponding period in 2014. The decrease was primarily due to a 25.3% decrease in the average cost of fuel per KWH generated and a 31.0% decrease in the volume of KWHs generated by coal, partially offset by a 45.5% increase in the volume of KWHs generated by natural gas.

Purchased Power

In the first quarter 2015, purchased power expense was $144 million compared to $187 million for the corresponding period in 2014. The decrease was primarily due to a 19.2% decrease in the average cost per KWH purchased primarily as a result of lower natural gas prices and a 10.2% decrease in the volume of KWHs purchased primarily as a result of decreased demand from milder weather in the first quarter 2015 as compared to the corresponding period in 2014.

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.

Other Operations and Maintenance Expenses

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$136	13.8

In the first quarter 2015, other operations and maintenance expenses were $1.1 billion compared to $986 million for the corresponding period in 2014. The increase was primarily due to a $35 million increase in employee compensation and benefits including pension costs, a $28 million increase in scheduled outage and maintenance costs at generation facilities, a $16 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand side management programs, a $9 million increase in transmission and

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

distribution costs primarily related to overhead line maintenance, and an $8 million increase in other generation expenses. In addition, Alabama Power deferred approximately $25 million of certain non-nuclear outage expenditures under an accounting order in the first quarter 2014. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Non-Nuclear Outage Accounting Order" in Item 8 of the Form 10-K for additional information related to non-nuclear outage expenditures. Also see Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

Depreciation and Amortization

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(10)	(2.0)

In the first quarter 2015, depreciation and amortization was $487 million compared to $497 million for the corresponding period in 2014. The decrease was primarily due to a $26 million reduction in depreciation rates at Alabama Power and a $13 million reduction in depreciation at Gulf Power, as approved by the Florida PSC, partially offset by an increase of $28 million as a result of additional plant in service at the traditional operating companies and Southern Power.

Estimated Loss on Kemper IGCC

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(371)	(97.6)

In the first quarter 2015 and 2014, estimated probable losses on the Kemper IGCC of $9 million and $380 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 (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" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Allowance for Equity Funds Used During Construction

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$6	10.5

In the first quarter 2015, AFUDC equity was $63 million compared to $57 million for the corresponding period in 2014. The increase was primarily related to $17 million of additional capital expenditures for environmental and transmission projects at the traditional operating companies, partially offset by an $11 million decrease related to placing the combined cycle and the associated common facilities portion of Mississippi Power's Kemper IGCC in service in August 2014. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Income Taxes

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$98	55.7

In the first quarter 2015, income taxes were $274 million compared to $176 million for the corresponding period in 2014. The increase primarily reflects a reduction in tax benefits related to the estimated probable losses on Mississippi Power's construction of the Kemper IGCC recorded in 2014, partially offset by otherwise lower pre-tax earnings in 2015.

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. These factors include the traditional operating companies' 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 the Kemper IGCC and Plant Vogtle Units 3 and 4 as well as other ongoing construction projects. Other major factors include the profitability of the competitive wholesale business and successfully expanding investments in renewable energy projects. Future earnings for the electricity business 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 price of electricity, 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 creditworthiness of customers, total generating capacity available and related costs, future acquisitions and construction of generating facilities, including the impact of ITCs, and the successful remarketing of capacity as current contracts expire. Changes in regional and global economic conditions may impact sales for the traditional operating companies and Southern Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and 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 Southern Company 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. 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

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations," – "Retail Regulatory Matters – Alabama Power – Environmental Accounting Order," and – "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Other Matters

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

– Sierra Club Settlement Agreement" in Item 8 of the Form 10-K for additional information on planned unit retirements and fuel conversions at Alabama Power, Georgia Power, and Mississippi Power.

Coal Combustion Residuals

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – 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 April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 14, 2015 as the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this timeand will depend on the traditional operating companies' ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Southern Company expects to record incremental asset retirement obligations of approximately $525 million to $575 million related to the CCR Rule in the second quarter 2015.

FERC Matters

The traditional 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 operating companies and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional 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 operating companies and in some adjacent areas. To retain market-based rate authority, the FERC has directed the traditional operating companies and Southern Power, within 60 days, 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 operating companies and Southern Power are evaluating the order. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Retail Fuel Cost Recovery

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

See 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.

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, rate energy cost recovery, and natural disaster reserve rate. 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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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Rate CNP

In March 2015, the Emerging Issues Task Force unanimously recommended to allow the normal purchases and normal sales exception for physical forward transactions in nodal energy markets. The Financial Accounting Standards Board (FASB) proposed new accounting guidance reflecting the recommendation on April 23, 2015. This guidance is subject to a public comment period before the FASB issues a final accounting standard. The ultimate outcome of this matter cannot be determined at this time.

Environmental Accounting Order

In April 2015, as part of its environmental compliance strategy, Alabama Power retired Plant Gorgas Units 6 and 7. These units represented 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Additionally, in April 2015, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. No later than April 2016, Alabama Power expects to cease using coal at Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. Alabama Power is continuing to evaluate its plans for Plant Barry Unit 3 (225 MWs), which is currently unavailable for generation.

In accordance with an accounting order from the Alabama PSC, Alabama Power will transfer the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on Southern Company's financial statements.

Rate CNP Compliance(Formerly Known As Rate CNP Environmental)

See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" in Item 8 of the Form 10-K for additional information regarding Alabama Power's development of a revised cost recovery mechanism.

On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. Alabama Power incurred $14 million of non-environmental compliance costs during the first quarter 2015 and will be limited to recovery of $50 million for the year. Customer rates will not be impacted before January 2016; therefore, the modification will increase the under-recovered position for Rate CNP Compliance during the year.

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 (DSM) tariffs, Environmental Compliance Cost Recovery (ECCR) tariffs, and Municipal Franchise Fee (MFF) 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 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.

Renewables Development

As part of the Georgia Power Advanced Solar Initiative program, Georgia Power executed ten PPAs that were approved by the Georgia PSC in 2014 and provide for the purchase of energy from 515 MWs of solar capacity. These PPAs are expected to commence in December 2015 and 2016 and have terms ranging from 20 to 30 years. As

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

a result of certain acquisitions by Southern Power, Georgia Power expects that 229 MWs of the 515 MWs will be purchased from solar facilities owned or under development by Southern Power.

Integrated Resource Plan

To comply with the April 16, 2015 effective date of the MATS rule, Plant Branch Units 1, 3, and 4 (1,266 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) were retired on April 15, 2015. In addition, operations were discontinued at Plant Mitchell Unit 3 (155 MWs) and its decertification will be requested in connection with the triennial Integrated Resource Plan in 2016. The switch to natural gas as the primary fuel is complete at Plant Yates Unit 7 and is underway at Plant Yates Unit 6. Plant Yates Unit 7 was returned to service on May 4, 2015 and Plant Yates Unit 6 is expected to return to service in mid-2015.

Gulf Power

Renewables

The Florida PSC preliminarily approved on April 16, 2015, three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. These contracts are expected to begin in 2016 with a term of 25 years each. The Florida PSC preliminarily approved on May 5, 2015, an energy purchase agreement for up to 178 MWs of wind generation in central Oklahoma. The agreement is expected to begin by the end of 2015 with a term of 20 years. Purchases under these agreements will be for energy only and are expected to be recovered through Gulf Power's fuel cost recovery mechanism. The ultimate outcome of these matters cannot be determined at this time.

Mississippi Power

Renewables

Subsequent to March 31, 2015, Mississippi Power entered into separate PPAs for three solar facilities for a combined total of approximately 105 MWs. Mississippi Power would purchase all of the energy produced by the solar facilities for the 25-year term of the contracts. If approved by the Mississippi PSC, the projects are expected to be in service by the end of 2016 and the resulting energy purchases will be recovered through Mississippi Power's fuel cost recovery mechanism. The ultimate outcome of this matter cannot be determined at this time.

Construction Program

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 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.

The two largest construction projects currently underway in the Southern Company system are Plant Vogtle Units 3 and 4 and the Kemper IGCC. Georgia Power has a 45.7% ownership interest in Plant Vogtle Units 3 and 4, each with approximately 1,100 MWs, and Mississippi Power is ultimately expected to hold an 85% ownership interest in the 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 (I) to the Condensed Financial Statements herein.

From 2013 through March 31, 2015, Southern Company recorded pre-tax charges totaling $2.06 billion ($1.27 billion after tax) for revisions of estimated costs expected to be incurred on Mississippi Power's construction

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and excluding the Cost Cap Exceptions. 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 DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and these changes could be material.

On January 29, 2015, Georgia Power announced it was notified by the Contractor of the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4, which would incrementally delay the previously disclosed estimated in-service dates by 18 months (from the fourth quarter of 2017 to the second quarter of 2019 for Unit 3 and from the fourth quarter of 2018 to the second quarter of 2020 for Unit 4).

While Georgia Power has not agreed to any change to the guaranteed substantial completion dates (April 2016 for Unit 3 and April 2017 for Unit 4) included in the engineering, procurement, and construction agreement relating to Plant Vogtle Units 3 and 4, Georgia Power's twelfth Vogtle Construction Monitoring (VCM) report, filed February 27, 2015, included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast, to include the estimated owner's costs associated with the proposed 18-month Contractor delay, and to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $5.0 billion. No Contractor costs related to the Contractor's proposed 18-month delay were included in the twelfth VCM report. The twelfth VCM report estimated financing costs during the construction period to total approximately $2.5 billion.

On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report. Pursuant to this order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3. The Georgia PSC recognized that the certified cost does 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, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.

Additionally, there are certain risks associated with the construction program in general and certain risks associated with the licensing, construction, and operation of nuclear generating units in particular, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world. The ultimate outcome of these events cannot be determined at this time.

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

Income Tax Matters

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

Section 174 Research and Experimental Deduction

Southern Company reflected deductions for research and experimental expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. Due to the uncertainty related to this tax position, Southern Company had unrecognized tax benefits totaling approximately $211 million at March 31, 2015. See Note 5 to the financial statements of Southern Company under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax Benefits," respectively, herein for additional information. The ultimate outcome of this tax matter cannot be determined at this time.

Other Matters

Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims

24

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

TheultimateoutcomeofsuchpendingorpotentiallitigationagainstSouthernCompanyanditssubsidiariescannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementshereinorinNote3tothefinancialstatementsofSouthernCompanyinItem8ofthe Form 10-K,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements. See Note (B) to the Condensed Financial 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

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, Contingent Obligations, and Pension and Other Postretirement Benefits.

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

During 2015, 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 DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery or any joint owner contributions for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the 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 $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, and $540 million ($333 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $2.06 billion ($1.27 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through March 31, 2015.

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 DOE Grants and excluding the Cost Cap Exceptions will be reflected in Southern Company's statements of income and these changes could be material. Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under

25

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).

Mississippi Power's revised cost estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 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. Any further extension of the in-service date with respect to the Kemper IGCC 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 $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting fees and legal fees which are being deferred as regulatory assets and are estimated to total approximately $6 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

In May 2014, the FASB issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition. On April 29, 2015, the FASB issued an exposure draft proposing the standard be effective for fiscal years beginning after December 15, 2017. Southern Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Company currently reflects unamortized debt issuance costs in unamortized debt issuance expense on its balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Southern Company.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at March 31, 2015. Through March 31, 2015, Southern Company has incurred non-recoverable cash expenditures of $1.49 billion and is expected to incur approximately $567 million in additional non-recoverable cash expenditures through completion 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 $913 million for the first three months of 2015, a decrease of $190 million from the corresponding period in 2014. The decrease in net cash provided from operating activities was primarily due to a decrease in KWH generation from coal and the timing of fuel purchases. Net cash used for investing activities totaled $1.1 billion for the first three months of 2015 primarily due to gross property additions for installation of equipment to comply with environmental standards, construction of generation, transmission, and

26

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

distribution facilities, acquisitions of solar facilities, and purchases of nuclear fuel. Net cash provided from financing activities totaled $596 million for the first three months of 2015. This was primarily due to issuances of long-term debt and common stock and an increase in short-term debt outstanding, partially offset by common stock dividend payments, redemptions of long-term debt, and the repurchase of common stock. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2015 include an increase of $607 million in total property, plant, and equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Other significant changes include an $876 million increase in notes payable and a $390 million decrease in accrued compensation.

At the end of the first quarter 2015, the market price of Southern Company's common stock was $44.28 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $22.04 per share, representing a market-to-book ratio of 201%, compared to $49.11, $21.98, and 223%, respectively, at the end of 2014. Southern Company's common stock dividend for the first quarter 2015 was $0.5250 per share compared to $0.5075 per share in the first quarter 2014. In April 2015, the quarterly dividend payable in June 2015 was increased to $0.5425 per share.

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 $3.7 billion will be required through March 31, 2016 to fund maturities of long-term debt and announced redemptions of preferred and preference stock of Alabama Power. See "Sources of Capital" herein for additional information.

The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in 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 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 flow, 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 to be raised in 2015, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements.

27

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Except as described herein, the traditional operating companies 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 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 costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K 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.

Eligible project costs incurred through March 31, 2015 would allow for borrowings of up to $2.1 billion under the FFB Credit Facility. Through March 31, 2015, Georgia Power has borrowed $1.2 billion under the FFB Credit Facility, leaving $0.9 billion of available borrowing ability.

Mississippi Power received $245 million of DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of DOE Grants is expected to be received for commercial operation of the Kemper IGCC. In addition, see Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.

As of March 31, 2015, Southern Company's current liabilities exceeded current assets by $2.8 billion, primarily due to long-term debt that is due within one year of $3.3 billion, including approximately $0.4 billion at Southern Company, $0.7 billion at Alabama Power, $1.6 billion at Georgia Power, and $0.5 billion at Southern Power. In addition, Mississippi Power has $0.9 billion in bank term loans that mature on April 1, 2016. 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 operating companies, and Southern Power 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 operating companies and Southern Power, equity contributions and/or loans from Southern Company to meet their short-term capital needs. In addition, in 2015, Georgia Power expects to utilize borrowings through the FFB Credit Facility as its primary source of long-term borrowed funds.

28

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At March 31, 2015, Southern Company and its subsidiaries had approximately $1.1 billion of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2015 were as follows:

	Expires												Executable Term Loans				Due Within One Year
Company	2015		2016		2017		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)								(in millions)				(in millions)				(in millions)
Southern Company	$	—	$	—	$	—	$	1,000	$	1,000	$	1,000	$	—	$	—	$	—	$	—
Alabama Power	228		50		—		1,030		1,308		1,308		58		—		58		170
Georgia Power	—		150		—		1,600		1,750		1,736		—		—		—		150
Gulf Power	45		200		30		—		275		275		50		—		50		195
Mississippi Power	135		165		—		—		300		270		25		40		65		235
Southern Power	—		—		—		500		500		488		—		—		—		—
Other	70		—		—		—		70		70		20		—		20		50
Total	$	478	$	565	$	30	$	4,130	$	5,203	$	5,147	$	153	$	40	$	193	$	800

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.

A portion of the unused credit with banks is allocated to provide liquidity support to the traditional operating companies' variable rate pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2015 was approximately $1.8 billion. In addition, at March 31, 2015, the traditional operating companies had $396 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to March 31, 2015, $145 million of these fixed rate pollution control revenue bonds were purchased and are being held by the applicable traditional operating company and currently are not required to be remarketed within the next 12 months.

Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements, as needed, prior to expiration.

Most of these bank credit arrangements contain covenants that limit debt levels and contain cross default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Southern Company, the traditional operating companies, and Southern Power are currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

Southern Company, the traditional 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 operating companies, and Southern Power may also borrow through various other arrangements with banks. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets.

29

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of short-term borrowings were as follows:

	Short-term Debt at March 31, 2015				Short-term Debt During the Period(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
Commercial paper	$	1,399	0.3	%	$	883	0.3	%	$	1,487
Short-term bank debt	280		0.8	%	10		1.1	%	280
Total	$	1,679	0.4	%	$	893	0.3	%

(*)    Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2015.

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

Credit Rating Risk

Southern Company and its subsidiaries 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 contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and Baa2, or 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, interest rate derivatives, and construction of new generation at Plant Vogtle Units 3 and 4.

The maximum potential collateral requirements under these contracts at March 31, 2015 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and Baa2	$	9
At BBB- and/or Baa3	385
Below BBB- and/or Baa3	2,454

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.

Financing Activities

During the first three months of 2015, Southern Company issued approximately 3.1 million shares of common stock primarily through the employee equity compensation plan and received proceeds of approximately $112 million. Southern Company is not currently issuing shares of common stock through the Southern Investment Plan or its employee savings plan. All sales under the Southern Investment Plan and the employee savings plan are currently being funded with shares acquired on the open market by independent plan administrators.

On March 2, 2015, Southern Company announced a program to repurchase up to 20 million shares of Southern Company common stock to offset all or a portion of the incremental shares issued under its employee and director equity compensation plans, including through stock option exercises, until December 31, 2017. Under this program, approximately 2.6 million shares have been repurchased through March 31, 2015 at a total cost of approximately $115 million. Pursuant to board approval, Southern Company may repurchase shares through open market

30

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

purchases or privately negotiated transactions, including accelerated or other share repurchase programs, in accordance with applicable securities laws.

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first three months of 2015:

Company(a)	Senior Note Issuances		Senior Note Redemptions		Other Long-Term Debt Redemptions and Maturities(b)
	(in millions)
Alabama Power	$	550	$	250	$	—
Georgia Power	—		—		3
Mississippi Power	—		—		76
Other	—		—		4
Total	$	550	$	250	$	83

(a) Southern Company, Gulf Power, and Southern Power did not issue or redeem any long-term debt during the first three months of 2015.

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

Alabama Power used the proceeds of the debt issuance shown in the table above for its redemption shown in the table above and for general corporate purposes, including its continuous construction program.

In March 2015, Georgia Power entered into a three-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $250 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes.

Subsequent to March 31, 2015, Alabama Power purchased and held $80 million aggregate principal amount of Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Barry Plant Project), Series 2007-B. Alabama Power may reoffer these bonds to the public at a later date.

Also subsequent to March 31, 2015, Alabama Power issued $175 million additional aggregate principal amount of its Series 2015A 3.750% Senior Notes due March 1, 2045 (Additional Series 2015A Senior Notes) and $250 million aggregate principal amount of its Series 2015B 2.800% Senior Notes due April 1, 2025 (Series 2015B Senior Notes). A portion of the proceeds of the Additional Series 2015A Senior Notes and the Series 2015B Senior Notes will be used for the announced redemption on May 15, 2015 of 6.48 million shares ($162 million aggregate stated capital) of Alabama Power's 5.20% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, 4.0 million shares ($100 million aggregate stated capital) of Alabama Power's 5.30% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and 6.0 million shares ($150 million aggregate stated capital) of Alabama Power's 5.625% Series Preference Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and the remaining net proceeds will be used for general corporate purposes, including Alabama Power's continuous construction program.

Also subsequent to March 31, 2015, Georgia Power purchased and held $65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008. Georgia Power may reoffer these bonds to the public at a later date.

Also subsequent to March 31, 2015, Georgia Power redeemed $125 million aggregate principal amount of its Series Y 5.80% Senior Notes due April 15, 2035; as a result, Georgia Power reclassified the outstanding principal balance to securities due within one year at March 31, 2015.

Also subsequent to March 31, 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of

31

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

$275 million, working capital, and other general corporate purposes, including Mississippi Power's ongoing construction program. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.

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.

32

PART I

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

During the three months ended March 31, 2015, 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, 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). 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.

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) during the first quarter 2015 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.

33

ALABAMA POWER COMPANY

34

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2015			2014
	(in millions)
Operating Revenues:
Retail revenues	$	1,268		$	1,297
Wholesale revenues, non-affiliates	65			85
Wholesale revenues, affiliates	15			69
Other revenues	53			57
Total operating revenues	1,401			1,508
Operating Expenses:
Fuel	310			432
Purchased power, non-affiliates	41			57
Purchased power, affiliates	53			49
Other operations and maintenance	399			325
Depreciation and amortization	158			175
Taxes other than income taxes	94			89
Total operating expenses	1,055			1,127
Operating Income	346			381
Other Income and (Expense):
Allowance for equity funds used during construction	15			10
Interest expense, net of amounts capitalized	(65		)	(62		)
Other income (expense), net	(4		)	(5		)
Total other income and (expense)	(54		)	(57		)
Earnings Before Income Taxes	292			324
Income taxes	113			127
Net Income	179			197
Dividends on Preferred and Preference Stock	10			10
Net Income After Dividends on Preferred and Preference Stock	$	169		$	187

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2015			2014
	(in millions)
Net Income	$	179		$	197
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(2) and $-, respectively	(4		)	—
Total other comprehensive income (loss)	(4		)	—
Comprehensive Income	$	175		$	197

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

35

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended March 31,
	2015			2014
	(in millions)
Operating Activities:
Net income	$	179		$	197
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	196			210
Deferred income taxes	16			25
Allowance for equity funds used during construction	(15		)	(10		)
Other, net	2			(22		)
Changes in certain current assets and liabilities —
-Receivables	(3		)	(17		)
-Fossil fuel stock	—			99
-Materials and supplies	12			3
-Other current assets	(80		)	(81		)
-Accounts payable	(229		)	(139		)
-Accrued taxes	246			147
-Accrued compensation	(89		)	(37		)
-Retail fuel cost over recovery	34			(20		)
-Other current liabilities	21			(3		)
Net cash provided from operating activities	290			352
Investing Activities:
Property additions	(325		)	(287		)
Nuclear decommissioning trust fund purchases	(129		)	(56		)
Nuclear decommissioning trust fund sales	129			56
Cost of removal, net of salvage	(13		)	(12		)
Change in construction payables	34			49
Other investing activities	(9		)	(5		)
Net cash used for investing activities	(313		)	(255		)
Financing Activities:
Proceeds —
Senior note issuances	550			—
Capital contributions from parent company	6			7
Redemptions — Senior notes	(250		)	—
Payment of preferred and preference stock dividends	(10		)	(10		)
Payment of common stock dividends	(143		)	(137		)
Other financing activities	(8		)	—
Net cash provided from (used for) financing activities	145			(140		)
Net Change in Cash and Cash Equivalents	122			(43		)
Cash and Cash Equivalents at Beginning of Period	273			295
Cash and Cash Equivalents at End of Period	$	395		$	252
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $5 and $4 capitalized for 2015 and 2014, respectively)	$	68		$	61
Income taxes, net	(136		)	(28		)
Noncash transactions — Accrued property additions at end of period	41			66

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

36

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2015			At December 31, 2014
	(in millions)
Current Assets:
Cash and cash equivalents	$	395		$	273
Receivables —
Customer accounts receivable	374			345
Unbilled revenues	115			138
Under recovered regulatory clause revenues	16			74
Other accounts and notes receivable	24			23
Affiliated companies	36			37
Accumulated provision for uncollectible accounts	(10		)	(9		)
Fossil fuel stock, at average cost	268			268
Materials and supplies, at average cost	410			406
Vacation pay	66			65
Prepaid expenses	134			244
Other regulatory assets, current	91			84
Other current assets	4			5
Total current assets	1,923			1,953
Property, Plant, and Equipment:
In service	23,254			23,080
Less accumulated provision for depreciation	8,627			8,522
Plant in service, net of depreciation	14,627			14,558
Nuclear fuel, at amortized cost	359			348
Construction work in progress	1,089			1,006
Total property, plant, and equipment	16,075			15,912
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	67			66
Nuclear decommissioning trusts, at fair value	770			756
Miscellaneous property and investments	85			84
Total other property and investments	922			906
Deferred Charges and Other Assets:
Deferred charges related to income taxes	523			525
Deferred under recovered regulatory clause revenues	87			31
Other regulatory assets, deferred	1,065			1,063
Other deferred charges and assets	161			162
Total deferred charges and other assets	1,836			1,781
Total Assets	$	20,756		$	20,552

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

37

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At March 31, 2015			At December 31, 2014
	(in millions)
Current Liabilities:
Securities due within one year	$	734		$	454
Accounts payable —
Affiliated	225			248
Other	273			443
Customer deposits	88			87
Accrued taxes —
Accrued income taxes	37			2
Other accrued taxes	59			37
Accrued interest	59			66
Accrued vacation pay	54			54
Accrued compensation	44			131
Other regulatory liabilities, current	2			2
Other current liabilities	114			80
Total current liabilities	1,689			1,604
Long-term Debt	6,193			6,176
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,890			3,874
Deferred credits related to income taxes	71			72
Accumulated deferred investment tax credits	123			125
Employee benefit obligations	322			326
Asset retirement obligations	840			829
Other cost of removal obligations	743			744
Other regulatory liabilities, deferred	242			239
Deferred over recovered regulatory clause revenues	81			47
Other deferred credits and liabilities	88			79
Total deferred credits and other liabilities	6,400			6,335
Total Liabilities	14,282			14,115
Redeemable Preferred Stock	342			342
Preference Stock	343			343
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	2,318			2,304
Retained earnings	2,281			2,255
Accumulated other comprehensive loss	(32		)	(29		)
Total common stockholder's equity	5,789			5,752
Total Liabilities and Stockholder's Equity	$	20,756		$	20,552

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

38

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2015 vs. FIRST QUARTER 2014

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. 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

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(18)	(9.6)

Alabama Power's net income after dividends on preferred and preference stock for the first quarter 2015 was $169 million compared to $187 million for the corresponding period in 2014. The decrease in net income was primarily related to an increase in non-fuel operations and maintenance expenses, partially offset by an increase in rates under rate stabilization and equalization (Rate RSE) as well as a decrease in depreciation expense. Also contributing to the decrease in net income was milder weather in the first quarter 2015 as compared to the corresponding period in 2014.

Retail Revenues

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(29)	(2.2)

In the first quarter 2015, retail revenues were $1.27 billion compared to $1.30 billion for the corresponding period in 2014.

39

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:

	First Quarter 2015
	(in millions)			(% change)
Retail – prior year	$	1,297
Estimated change resulting from –
Rates and pricing	47			3.6
Sales growth	9			0.7
Weather	(20		)	(1.5	)
Fuel and other cost recovery	(65		)	(5.0	)
Retail – current year	$	1,268		(2.2	)%

Revenues associated with changes in rates and pricing increased in the first quarter 2015 when compared to the corresponding period in 2014 primarily due to a Rate RSE increase effective January 1, 2015. 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 increased in the first quarter 2015 when compared to the corresponding period in 2014. Industrial KWH energy sales slightly increased 0.3% in the first quarter 2015 as a result of an increase in demand resulting from changes in production levels primarily in the pipelines, stone, clay, and glass, and automotive and plastics sectors, offset by a decrease in demand in the primary metals and forest products sectors. Weather-adjusted residential and commercial KWH energy sales increased 0.8% and 1.6%, respectively, in the first quarter 2015 as a result of increased customer usage and customer growth.

Revenues resulting from changes in weather decreased in the first quarter 2015 due to milder weather experienced in Alabama Power's service territory as compared to the corresponding period in 2014. For the first quarter 2015, the resulting decreases were 2.4% and 1.7% for residential and commercial sales revenue, respectively.

Fuel and other cost recovery revenues decreased in the first quarter 2015 when compared to the corresponding period in 2014 primarily due to a decrease in KWH generation and the average cost of natural gas. 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.

Wholesale Revenues – Non-Affiliates

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(20)	(23.5)

Wholesale revenues from sales to non-affiliates will vary depending on the market prices of available 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 have a significant impact on net income.

In the first quarter 2015, wholesale revenues from sales to non-affiliates were $65 million compared to $85 million for the corresponding period in 2014. The decrease was primarily due to a 9.0% decrease in KWH sales and a 15.9% decrease in the price of energy. In 2014, Alabama Power's fuel diversity led to increased sales to non-affiliates due to higher than normal natural gas prices. In 2015, lower natural gas prices and decreased availability of hydro generation, due to less rainfall, resulted in lower sales of Alabama Power's generation to non-affiliates.

40

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Affiliates

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(54)	(78.3)

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

In the first quarter 2015, wholesale revenues from sales to affiliates were $15 million compared to $69 million for the corresponding period in 2014. The decrease was primarily due to a 69.1% decrease in KWH sales and a 30.9% decrease in the price of energy. In 2014, Alabama Power's fuel diversity led to increased sales to affiliates due to higher than normal natural gas prices. In 2015, lower natural gas prices and decreased availability of hydro generation, due to less rainfall, resulted in lower sales of Alabama Power's generation to affiliates.

Fuel and Purchased Power Expenses

	First Quarter 2015 vs. First Quarter 2014
	(change in millions)			(% change)
Fuel	$	(122	)	(28.2)
Purchased power – non-affiliates	(16		)	(28.1)
Purchased power – affiliates	4			8.2
Total fuel and purchased power expenses	$	(134	)

In the first quarter 2015, total fuel and purchased power expenses were $404 million compared to $538 million for the corresponding period in 2014. The decrease was primarily due to a $69 million decrease in the average cost of fuel, a $53 million decrease related to the volume of KWHs generated, and a $37 million decrease in the average cost of purchased power, partially offset by a $25 million increase in the volume of KWHs purchased.

Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. Alabama Power, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate ECR" in Item 8 of the Form 10-K for additional information.

41

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	First Quarter 2015	First Quarter 2014
Total generation (billions of KWHs)	15	16
Total purchased power (billions of KWHs)	2	2
Sources of generation (percent) —
Coal	47	53
Nuclear	26	23
Gas	19	15
Hydro	8	9
Cost of fuel, generated (cents per net KWH) —
Coal	2.89	3.40
Nuclear	0.80	0.87
Gas	3.03	4.19
Average cost of fuel, generated (cents per net KWH)(a)	2.33	2.89
Average cost of purchased power (cents per net KWH)(b)	4.60	6.41

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

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

Fuel

In the first quarter 2015, fuel expense was $310 million compared to $432 million for the corresponding period in 2014. The decrease was primarily due to a 27.6% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, a 20.6% decrease in the volume of KWHs generated by coal, and a 15.1% decrease in the average cost of coal generation. This was partially offset by a 22.6% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall and a 6.7% increase in the volume of KWHs generated by natural gas.

Purchased Power – Non-Affiliates

In the first quarter 2015, purchased power expense from non-affiliates was $41 million compared to $57 million for the corresponding period in 2014. The decrease was related to a 33.1% decrease in the average cost per KWH purchased as a result of lower natural gas prices, partially offset by a 7.3% increase in the amount of energy purchased due to decreased availability of hydro generation as a result of less rainfall in the first quarter of 2015 as compared to the corresponding period during 2014.

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 first quarter 2015, purchased power expense from affiliates was $53 million compared to $49 million for the corresponding period in 2014. The increase was related to a 35.6% increase in the amount of energy purchased primarily due to the availability of Southern Company's lower cost generation sources and the decreased availability of hydro generation as a result of less rainfall. This increase was partially offset by a 20.2% decrease in the average cost per KWH purchased due to lower natural gas prices.

42

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Other Operations and Maintenance Expenses

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$74	22.8

In the first quarter 2015, other operations and maintenance expenses were $399 million compared to $325 million for the corresponding period in 2014. The increase was primarily due to the implementation of an accounting order in 2014 allowing the deferral of non-nuclear outage costs. Alabama Power deferred approximately $25 million of non-nuclear outage expenditures in the first quarter 2014. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Cost of Removal Accounting Order" in Item 8 of the Form 10-K for additional information. In addition, there was an increase of $23 million in steam production primarily due to scheduled outage costs and a $10 million increase in employee benefits including pension costs. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

Depreciation and Amortization

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(17)	(9.7)

In the first quarter 2015, depreciation and amortization was $158 million compared to $175 million for the corresponding period in 2014. The decrease was primarily due to a decrease in depreciation rates related to steam, transmission, distribution, and environmental assets effective January 1, 2015, as authorized by the FERC, partially offset by increases in plant in service.

Allowance for Equity Funds Used During Construction

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$5	50.0

In the first quarter 2015, AFUDC equity was $15 million compared to $10 million for the corresponding period in 2014. The increase was primarily due to additional capital expenditures for steam environmental, steam generation, and nuclear production.

Income Taxes

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(14)	(11.0)

In the first quarter 2015, income taxes were $113 million compared to $127 million for the corresponding period in 2014. The decrease was primarily due to lower pre-tax earnings.

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,

43

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. Changes in regional and global economic conditions may impact sales for Alabama Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and 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. 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

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations" and – "Retail Regulatory Matters – Environmental Accounting Order" of Alabama Power in Item 7 of the Form 10-K and "Retail Regulatory Matters – Environmental Accounting Order" herein for additional information regarding Alabama Power's plan for compliance with environmental statutes and regulations.

Coal Combustion Residuals

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

On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 14, 2015 as the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this timeand will depend on Alabama Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Alabama Power expects to record incremental asset retirement obligations of approximately $330 million to $350 million related to the CCR Rule in the second quarter 2015.

FERC Matters

Alabama Power has 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 operating companies (including Alabama Power) and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including Alabama Power's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating

44

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

companies and in some adjacent areas. To retain market-based rate authority, the FERC has directed the traditional operating companies (including Alabama Power) and Southern Power, within 60 days, 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. Alabama Power is evaluating the order. 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, rate energy cost recovery, and natural disaster reserve rate. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 1 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and Note 3 under "Retail Regulatory Matters" 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.

Rate CNP

In March 2015, the Emerging Issues Task Force unanimously recommended to allow the normal purchases and normal sales exception for physical forward transactions in nodal energy markets. The Financial Accounting Standards Board (FASB) proposed new accounting guidance reflecting the recommendation on April 23, 2015. This guidance is subject to a public comment period before the FASB issues a final accounting standard. The ultimate outcome of this matter cannot be determined at this time.

Environmental Accounting Order

In April 2015, as part of its environmental compliance strategy, Alabama Power retired Plant Gorgas Units 6 and 7. These units represented 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Additionally, in April 2015, Alabama Power ceased using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. No later than April 2016, Alabama Power expects to cease using coal at Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. Alabama Power is continuing to evaluate its plans for Plant Barry Unit 3 (225 MWs), which is currently unavailable for generation.

In accordance with an accounting order from the Alabama PSC, Alabama Power will transfer the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on Alabama Power's financial statements.

Rate CNP Compliance (Formerly Known As Rate CNP Environmental)

See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" in Item 8 of the Form 10-K for additional information regarding Alabama Power's development of a revised cost recovery mechanism.

On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. Alabama Power incurred $14 million of non-environmental compliance costs during the first quarter 2015 and will be limited to recovery of $50 million for the year. Customer rates will not be impacted before January 2016; therefore, the modification will increase the under-recovered position for Rate CNP Compliance during the year.

45

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Matters

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

The ultimate outcome of such pending or potential litigation against Alabama Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Alabama Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on 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, Contingent Obligations, and Pension and Other Postretirement Benefits.

Recently Issued Accounting Standards

In May 2014, the FASB issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition. On April 29, 2015, the FASB issued an exposure draft proposing the standard be effective for fiscal years beginning after December 15, 2017. Alabama Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Alabama Power currently reflects unamortized debt issuance costs in other deferred charges and assets on its balance sheet. Upon adoption, the reclassification will not 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 March 31, 2015. 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

46

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Net cash provided from operating activities totaled $290 million for the first three months of 2015, a decrease of $62 million as compared to the first three months of 2014. The decrease in net cash provided from operating activities was primarily due to the timing of fossil fuel stock purchases and payments of accounts payable, partially offset by the timing of payments and refunds associated with bonus depreciation. Net cash used for investing activities totaled $313 million for the first three months of 2015 primarily due to gross property additions related to distribution, environmental, transmission, steam generation, and nuclear fuel. Net cash provided from financing activities totaled $145 million for the first three months of 2015 primarily due to the issuance of long-term debt, partially offset by the redemption of long-term debt and a payment of common stock dividends. Fluctuations in cash flow from financing activities vary period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2015 include an increase of $280 million in securities due within one year, $163 million in property, plant, and equipment, primarily due to additions to distribution, environmental, transmission, steam generation, and nuclear fuel and $122 million in cash and cash equivalents. Other significant changes include decreases of $170 million in other accounts payable due to property tax payments and $110 million in prepaid expenses associated with an income tax refund.

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 $1.1 billion will be required through March 31, 2016 to fund maturities of long-term debt and announced redemptions of preferred and preference stock.

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

47

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 Alabama Power's debt due within one year and the periodic use of short-term debt as a funding source primarily to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business.

At March 31, 2015, Alabama Power had approximately $395 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2015 were as follows:

Expires										Executable Term Loans				Due Within One Year
2015		2016		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)						(in millions)				(in millions)				(in millions)
$	228	$	50	$	1,030	$	1,308	$	1,308	$	58	$	—	$	58	$	170

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 contain covenants that limit debt levels and contain cross default provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross default provisions to other indebtedness would trigger an event of default if Alabama Power defaulted on indebtedness or guarantee obligations over a specified threshold. 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.

A portion of the unused credit with banks is allocated to provide liquidity support to Alabama Power's variable rate pollution control revenue bonds and commercial paper borrowings. As of March 31, 2015, Alabama Power had $864 million of outstanding variable rate pollution control revenue bonds requiring liquidity support. In addition, at March 31, 2015, Alabama Power had $200 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to March 31, 2015, $80 million of these fixed rate pollution control revenue bonds were purchased and are being held by Alabama Power and currently are not required to be remarketed within the next 12 months.

In addition, Alabama Power 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 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 at March 31, 2015			Short-term Debt During the Period(*)
	Amount Outstanding		Weighted Average Interest Rate	Average Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
Commercial Paper	$	—	—%	$	29	0.2%	$	100

(*) Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2015.

48

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 below BBB- and/or Baa3. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At March 31, 2015, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $366 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.

Financing Activities

In March 2015, Alabama Power issued $550 million aggregate principal amount of Series 2015A 3.750% Senior Notes due March 1, 2045. The proceeds were used to redeem $250 million aggregate principal amount of Series DD 5.65% Senior Notes due March 15, 2035 and for general corporate purposes, including Alabama Power's continuous construction program.

Subsequent to March 31, 2015, Alabama Power purchased and held $80 million aggregate principal amount of Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Barry Plant Project), Series 2007-B. Alabama Power may reoffer these bonds to the public at a later date.

Also subsequent to March 31, 2015, Alabama Power issued $175 million additional aggregate principal amount of its Series 2015A 3.750% Senior Notes due March 1, 2045 (Additional Series 2015A Senior Notes) and $250 million aggregate principal amount of its Series 2015B 2.800% Senior Notes due April 1, 2025 (Series 2015B Senior Notes). A portion of the proceeds of the Additional Series 2015A Senior Notes and the Series 2015B Senior Notes will be used for the announced redemption on May 15, 2015 of 6.48 million shares ($162 million aggregate stated capital) of Alabama Power's 5.20% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, 4.0 million shares ($100 million aggregate stated capital) of Alabama Power's 5.30% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and 6.0 million shares ($150 million aggregate stated capital) of Alabama Power's 5.625% Series Preference Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and the remaining net proceeds will be used for general corporate purposes, including Alabama Power's continuous construction program.

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

49

GEORGIA POWER COMPANY

50

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2015			2014
	(in millions)
Operating Revenues:
Retail revenues	$	1,814		$	2,050
Wholesale revenues, non-affiliates	68			109
Wholesale revenues, affiliates	8			21
Other revenues	88			89
Total operating revenues	1,978			2,269
Operating Expenses:
Fuel	526			752
Purchased power, non-affiliates	60			79
Purchased power, affiliates	149			184
Other operations and maintenance	474			427
Depreciation and amortization	216			208
Taxes other than income taxes	99			103
Total operating expenses	1,524			1,753
Operating Income	454			516
Other Income and (Expense):
Allowance for equity funds used during construction	15			6
Interest expense, net of amounts capitalized	(89		)	(84		)
Other income (expense), net	—			(2		)
Total other income and (expense)	(74		)	(80		)
Earnings Before Income Taxes	380			436
Income taxes	140			166
Net Income	240			270
Dividends on Preferred and Preference Stock	4			4
Net Income After Dividends on Preferred and Preference Stock	$	236		$	266

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2015			2014
	(in millions)
Net Income	$	240		$	270
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(9) and $-, respectively	(14		)	—
Total other comprehensive income (loss)	(14		)	—
Comprehensive Income	$	226		$	270

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

51

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended March 31,
	2015			2014
	(in millions)
Operating Activities:
Net income	$	240		$	270
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	256			250
Deferred income taxes	(7		)	96
Allowance for equity funds used during construction	(15		)	(6		)
Retail fuel cost over recovery — long-term	—			(44		)
Deferred expenses	33			33
Pension, postretirement, and other employee benefits	6			(4		)
Other, net	(2		)	(10		)
Changes in certain current assets and liabilities —
-Receivables	166			(83		)
-Fossil fuel stock	67			257
-Prepaid income taxes	170			(11		)
-Other current assets	(13		)	(12		)
-Accounts payable	(261		)	(28		)
-Accrued taxes	(217		)	(166		)
-Accrued compensation	(81		)	(38		)
-Retail fuel cost over recovery — short-term	—			(14		)
-Other current liabilities	21			9
Net cash provided from operating activities	363			499
Investing Activities:
Property additions	(422		)	(460		)
Nuclear decommissioning trust fund purchases	(161		)	(175		)
Nuclear decommissioning trust fund sales	155			173
Change in construction payables, net of joint owner portion	37			28
Prepaid long-term service agreements	(9		)	(44		)
Other investing activities	(5		)	(2		)
Net cash used for investing activities	(405		)	(480		)
Financing Activities:
Increase (decrease) in notes payable, net	434			(749		)
Proceeds —
Capital contributions from parent company	11			12
FFB loan	—			1,000
Short-term borrowings	250			—
Payment of preferred and preference stock dividends	(4		)	(4		)
Payment of common stock dividends	(259		)	(238		)
FFB loan issuance costs	—			(49		)
Other financing activities	(1		)	(3		)
Net cash provided from (used for) financing activities	431			(31		)
Net Change in Cash and Cash Equivalents	389			(12		)
Cash and Cash Equivalents at Beginning of Period	24			30
Cash and Cash Equivalents at End of Period	$	413		$	18
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $6 and $3 capitalized for 2015 and 2014, respectively)	$	79		$	71
Income taxes, net	(34		)	11
Noncash transactions — Accrued property additions at end of period	177			229

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

52

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2015			At December 31, 2014
	(in millions)
Current Assets:
Cash and cash equivalents	$	413		$	24
Receivables —
Customer accounts receivable	642			553
Unbilled revenues	174			201
Joint owner accounts receivable	47			121
Other accounts and notes receivable	70			61
Affiliated companies	16			18
Accumulated provision for uncollectible accounts	(7		)	(6		)
Fossil fuel stock, at average cost	372			439
Materials and supplies, at average cost	443			438
Vacation pay	91			91
Prepaid income taxes	86			278
Other regulatory assets, current	142			136
Other current assets	85			74
Total current assets	2,574			2,428
Property, Plant, and Equipment:
In service	31,425			31,083
Less accumulated provision for depreciation	11,326			11,222
Plant in service, net of depreciation	20,099			19,861
Other utility plant, net	197			211
Nuclear fuel, at amortized cost	555			563
Construction work in progress	4,193			4,031
Total property, plant, and equipment	25,044			24,666
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	60			58
Nuclear decommissioning trusts, at fair value	804			789
Miscellaneous property and investments	37			38
Total other property and investments	901			885
Deferred Charges and Other Assets:
Deferred charges related to income taxes	696			698
Deferred under recovered regulatory clause revenues	62			197
Other regulatory assets, deferred	1,796			1,753
Other deferred charges and assets	443			403
Total deferred charges and other assets	2,997			3,051
Total Assets	$	31,516		$	31,030

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

53

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At March 31, 2015			At December 31, 2014
	(in millions)
Current Liabilities:
Securities due within one year	$	1,600		$	1,154
Notes payable	840			156
Accounts payable —
Affiliated	364			451
Other	469			555
Customer deposits	256			253
Other accrued taxes	116			332
Accrued interest	100			96
Accrued vacation pay	62			63
Accrued compensation	54			153
Liabilities from risk management activities	52			32
Other current liabilities	388			225
Total current liabilities	4,301			3,470
Long-term Debt	8,393			8,683
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,471			5,507
Deferred credits related to income taxes	104			106
Accumulated deferred investment tax credits	193			196
Employee benefit obligations	891			903
Asset retirement obligations	1,223			1,223
Other deferred credits and liabilities	268			255
Total deferred credits and other liabilities	8,150			8,190
Total Liabilities	20,844			20,343
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	6,218			6,196
Retained earnings	3,812			3,835
Accumulated other comprehensive loss	(22		)	(8		)
Total common stockholder's equity	10,406			10,421
Total Liabilities and Stockholder's Equity	$	31,516		$	31,030

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

54

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2015 vs. FIRST QUARTER 2014

OVERVIEW

Georgia Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area 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, Georgia Power is currently constructing Plant Vogtle Units 3 and 4 and will own a 45.7% interest in these two nuclear generating units to increase its generation diversity and meet future supply needs. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.

Georgia Power continues to focus on several key performance indicators. These indicators include 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

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(30)	(11.3)

Georgia Power's net income after dividends on preferred and preference stock for the first quarter 2015 was $236 million compared to $266 million for the corresponding period in 2014. The decrease was primarily due to higher non-fuel operations and maintenance expenses and milder weather in the first quarter 2015 as compared to the corresponding period in 2014, partially offset by an increase in retail base revenues effective January 1, 2015 as authorized under the 2013 ARP.

Retail Revenues

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(236)	(11.5)

In the first quarter 2015, retail revenues were $1.81 billion compared to $2.05 billion for the corresponding period in 2014.

55

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:

	First Quarter 2015
	(in millions)			(% change)
Retail – prior year	$	2,050
Estimated change resulting from –
Rates and pricing	29			1.4
Sales growth	16			0.8
Weather	(16		)	(0.8	)
Fuel cost recovery	(265		)	(12.9	)
Retail – current year	$	1,814		(11.5	)%

Revenues associated with changes in rates and pricing increased in the first quarter 2015 when compared to the corresponding period in 2014 primarily due to base tariff increases approved under the 2013 ARP and increases in collections for financing costs related to the construction of Plant Vogtle Units 3 and 4 through the NCCR tariff, which were both effective January 1, 2015, partially offset by lower contributions from market-driven rates from commercial and industrial customers. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans" in Item 8 of the Form 10-K for additional information.

Revenues attributable to changes in sales increased in the first quarter 2015 when compared to the corresponding period in 2014. Weather-adjusted residential KWH sales increased 1.0%, weather-adjusted commercial KWH sales increased 0.9%, and weather-adjusted industrial KWH sales increased 4.2% in the first quarter 2015. An increase of approximately 26,000 residential customers since March 31, 2014 contributed to the increase in weather-adjusted residential KWH sales. Increased customer usage and an increase of approximately 2,700 customers since March 31, 2014 contributed to the increase in weather-adjusted commercial sales. Increased demand in the paper, textile, and stone, clay, and glass sectors was the main contributor to the increase in weather-adjusted industrial KWH sales, partially offset by a decrease in the chemicals sector.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased $265 million in the first quarter 2015 when compared to the corresponding period in 2014 primarily due to lower natural gas, coal, and nuclear fuel costs and lower energy sales resulting from milder weather in the first quarter 2015 as compared to the corresponding period in 2014. 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.

Wholesale Revenues – Non-Affiliates

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(41)	(37.6)

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

56

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 of energy.

In the first quarter 2015, wholesale revenues from sales to non-affiliates were $68 million compared to $109 million for the corresponding period in 2014 primarily related to a $33 million decrease in energy revenues and an $8 million decrease in capacity revenues. The decrease in energy revenues was primarily due to decreased demand resulting from milder weather in the first quarter 2015 as compared to the corresponding period in 2014. The decrease in capacity revenues reflects the expiration of wholesale contracts in December 2014.

Wholesale Revenues – Affiliates

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(13)	(61.9)

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

In the first quarter 2015, wholesale revenues from sales to affiliates were $8 million compared to $21 million for the corresponding period in 2014. The decrease was due to lower demand resulting from milder weather in the first quarter 2015 as compared to the corresponding period in 2014.

Fuel and Purchased Power Expenses

	First Quarter 2015 vs. First Quarter 2014
	(change in millions)			(% change)
Fuel	$	(226	)	(30.1	)
Purchased power – non-affiliates	(19		)	(24.1	)
Purchased power – affiliates	(35		)	(19.0	)
Total fuel and purchased power expenses	$	(280	)

In the first quarter 2015, total fuel and purchased power expenses were $735 million compared to $1.02 billion in the corresponding period in 2014. The decrease in the first quarter 2015 was primarily due to a $237 million decrease in the average cost of fuel related to lower natural gas, coal and nuclear fuel prices and the average cost of purchased power due to lower natural gas prices and an $82 million decrease in the volume of KWHs generated due to milder weather as compared to the corresponding period in 2014 resulting in lower customer demand, partially offset by a $39 million increase in the volume of KWHs purchased due to lower natural gas prices.

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.

57

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	First Quarter 2015	First Quarter 2014
Total generation (billions of KWHs)	17	18
Total purchased power (billions of KWHs)	6	5
Sources of generation (percent) —
Coal	34	48
Nuclear	22	20
Gas	42	29
Hydro	2	3
Cost of fuel, generated (cents per net KWH) —
Coal	4.71	5.03
Nuclear	0.54	0.91
Gas	2.63	4.39
Average cost of fuel, generated (cents per net KWH)	2.86	3.99
Average cost of purchased power (cents per net KWH)(*)	4.39	5.75

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

Fuel

In the first quarter 2015, fuel expense was $526 million compared to $752 million in the corresponding period in 2014. The decrease was primarily due to a 28.3% decrease in the average cost of fuel per KWH generated and a 35.5% decrease in the volume of KWHs generated by coal, partially offset by a 30.9% increase in the volume of KWHs generated by natural gas.

Purchased Power – Non-Affiliates

In the first quarter 2015, purchased power expense from non-affiliates was $60 million compared to $79 million in the corresponding period in 2014. The decrease was primarily due to a 21.5% 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 first quarter 2015, purchased power expense from affiliates was $149 million compared to $184 million in the corresponding period in 2014. The decrease was due to a 22.8% decrease in the average cost per KWH purchased primarily resulting from lower natural gas prices, partially offset by a 14.3% increase in the volume of KWHs purchased as Georgia Power's units generally dispatched at a higher cost than other Southern Company system resources.

Energy purchases from affiliates will vary depending on the 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.

58

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$47	11.0

In the first quarter 2015, other operations and maintenance expenses were $474 million compared to $427 million in the corresponding period in 2014. The increase was primarily due to increases of $19 million in employee compensation and benefits including pension costs, $10 million in customer accounts, service, and sales costs primarily related to customer incentive and demand-side management costs, $7 million in transmission and distribution costs primarily related to overhead line maintenance, and $6 million in scheduled outage-related costs. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

Allowance for Equity Funds Used During Construction

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$9	150.0

In the first quarter 2015, AFUDC equity was $15 million compared to $6 million in the corresponding period in 2014. The increase was primarily due to an increase in construction related to ongoing environmental and transmission projects.

Income Taxes

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(26)	(15.7)

In the first quarter 2015, income taxes were $140 million compared to $166 million for the corresponding period in 2014. The decrease in income taxes was primarily due to lower pre-tax earnings and an increase in non-taxable AFUDC equity.

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. Changes in regional and global economic conditions may impact sales for Georgia Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and 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.

59

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. 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

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plans" of Georgia Power in Item 7 of the Form 10-K and "Retail Regulatory Matters – Integrated Resource Plan" herein for additional information on planned unit retirements and fuel conversions at Georgia Power.

Coal Combustion Residuals

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – 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 April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 14, 2015 as the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this timeand will depend on Georgia Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Georgia Power expects to record incremental asset retirement obligations of approximately $10 million to $20 million related to the CCR Rule in the second quarter 2015.

FERC Matters

Georgia Power has 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 operating companies (including Georgia Power) and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including Georgia Power's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC has directed the traditional operating companies (including Georgia Power) and Southern Power, within 60 days, 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. Georgia Power is evaluating the order. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management (DSM) tariffs, ECCR

60

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

tariffs, and Municipal Franchise Fee (MFF) 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 3 to the financial statements of Georgia Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.

Renewables Development

As part of the Georgia Power Advanced Solar Initiative program, Georgia Power executed ten PPAs that were approved by the Georgia PSC in 2014 and provide for the purchase of energy from 515 MWs of solar capacity. These PPAs are expected to commence in December 2015 and 2016 and have terms ranging from 20 to 30 years. As a result of certain acquisitions by Southern Power, Georgia Power expects that 229 MWs of the 515 MWs will be purchased from solar facilities owned or under development by Southern Power.

Integrated Resource Plan

To comply with the April 16, 2015 effective date of the MATS rule, Plant Branch Units 1, 3, and 4 (1,266 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) were retired on April 15, 2015. In addition, operations were discontinued at Plant Mitchell Unit 3 (155 MWs) and its decertification will be requested in connection with the triennial Integrated Resource Plan in 2016. The switch to natural gas as the primary fuel is complete at Plant Yates Unit 7 and is underway at Plant Yates Unit 6. Plant Yates Unit 7 was returned to service on May 4, 2015 and Plant Yates Unit 6 is expected to return to service in mid-2015.

Fuel Cost Recovery

Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. Georgia Power continues to be allowed to adjust its fuel cost recovery rates prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million. On January 20, 2015, the Georgia PSC approved the deferral of Georgia Power's next fuel case filing until at least June 30, 2015.

Fuel cost recovery revenues as recorded on the financial statements 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 Georgia Power's revenues or net income, but will affect cash flow. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information.

Nuclear Construction

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" of Georgia Power in Item 7 and 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 additional information regarding the construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, and pending litigation.

In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement (Vogtle 3 and 4 Agreement) with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is 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. The Contractor's liability to the Vogtle Owners for schedule and performance liquidated damages and warranty claims is 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

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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%.

Certain payment obligations of Westinghouse and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.) under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group Inc. (a subsidiary of Chicago Bridge & Iron Company, N.V.), respectively. 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. 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 NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. 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 are expected as construction proceeds.

In 2012, the Vogtle Owners and the Contractor began negotiations regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Also in 2012, Georgia Power and the other Vogtle Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against Georgia Power and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. On March 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit affirmed the District Court's decision. The portion of additional costs claimed by the Contractor in its initial complaint that would be attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately $425 million (in 2008 dollars). The Contractor also asserted it is entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. In May 2014, the Contractor filed an amended counterclaim to the suit pending in the U.S. District Court for the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations; however, the Contractor has subsequently asserted related minimum damages (based on Georgia Power's ownership interest) of $113 million. The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these allegations, any of which could be substantial. Georgia Power has not agreed to the proposed cost or to any changes to the guaranteed substantial completion dates or that the Vogtle Owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power intends to vigorously defend the positions of the Vogtle Owners. Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule. During such negotiations the parties may reach a mutually acceptable compromise of their positions.

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 certified construction capital costs to be borne by Georgia Power increase by 5% 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. Georgia Power's eighth VCM report filed in 2013 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 and the fourth

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quarter 2018 for Plant Vogtle Units 3 and 4, respectively. In 2013, the Georgia PSC approved a stipulation (2013 Stipulation) entered into by Georgia Power and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. The Georgia PSC has approved eleven VCM reports covering the periods through June 30, 2014, including construction capital costs incurred, which through that date totaled $2.8 billion.

On January 29, 2015, Georgia Power announced it was notified by the Contractor of the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4, which would incrementally delay the previously disclosed estimated in-service dates by 18 months (from the fourth quarter of 2017 to the second quarter of 2019 for Unit 3 and from the fourth quarter of 2018 to the second quarter of 2020 for Unit 4).

Georgia Power does not believe that the Contractor's revised forecast reflects all efforts that may be possible to mitigate the Contractor's delay. In addition, Georgia Power believes that, pursuant to the Vogtle 3 and 4 Agreement, the Contractor is responsible for the Contractor's costs related to the Contractor's delay (including any related construction and mitigation costs, which could be material) and that the Vogtle Owners are entitled to recover liquidated damages for the Contractor's delay beyond the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. Consistent with the Contractor's position in the pending litigation described above, Georgia Power expects the Contractor to contest any claims for liquidated damages and to assert that the Vogtle Owners are responsible for additional costs related to the Contractor's delay.

On February 27, 2015, Georgia Power filed its twelfth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2014, which requested approval for an additional $0.2 billion of construction capital costs incurred during that period. The twelfth VCM report also reflected the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 as well as additional estimated owner-related costs, which include approximately $10 million per month expected to result from the Contractor's proposed 18-month delay, including property taxes, oversight costs, compliance costs, and other operational readiness costs. No Contractor costs related to the Contractor's proposed 18-month delay were included in the twelfth VCM report. Additionally, while Georgia Power has not agreed to any change to the guaranteed substantial completion dates, the twelfth VCM report included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast, to include the estimated 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.

Georgia Power will continue to incur financing costs of approximately $30 million per month until Plant Vogtle Units 3 and 4 are placed in service. The twelfth VCM report estimated financing costs during the construction period to total approximately $2.5 billion.

On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report. Pursuant to this 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, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.

Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, 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 issues are expected to 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.

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As construction continues, the risk remains that ongoing challenges with Contractor performance including additional challenges in its fabrication, assembly, delivery, and installation of 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.

Additional claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) are also likely to arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement, but also may be resolved through litigation.

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.

The ultimate outcome of such pending or potential litigation against Georgia Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Georgia Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Georgia Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board (FASB) issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition. On April 29, 2015, the FASB issued an exposure draft proposing the standard be effective for fiscal years beginning after December 15, 2017. Georgia Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

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On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Georgia Power currently reflects unamortized debt issuance costs in other deferred charges and assets on its balance sheet. Upon adoption, the reclassification will not 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 March 31, 2015. 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 $363 million for the first three months of 2015 compared to $499 million for the corresponding period in 2014. The decrease was primarily due to lower operating revenues, partially offset by increased fuel cost recovery. Net cash used for investing activities totaled $405 million for the first three months of 2015 compared to $480 million for the corresponding period in 2014 primarily related to installation of equipment to comply with environmental standards, construction of transmission and distribution facilities, and purchases of nuclear fuel. Net cash provided from financing activities totaled $431 million for the first three months of 2015 compared to $31 million used for financing activities in the corresponding period in 2014. The increase in cash provided from financing activities is primarily due to an increase in short-term debt borrowings. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2015 include increases of $378 million in property, plant, and equipment, $684 million in short-term debt, and $389 million in cash and cash equivalents.

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 $1.6 billion will be required through March 31, 2016 to fund maturities of long-term debt. See "Sources of Capital" 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; changes in environmental statutes and regulations; the outcome of any legal challenges to 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

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"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, 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 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 costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K 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.

Eligible project costs incurred through March 31, 2015 would allow for borrowings of up to $2.1 billion under the FFB Credit Facility. Through March 31, 2015, Georgia Power has borrowed $1.2 billion under the FFB Credit Facility, leaving $0.9 billion of available borrowing ability.

As of March 31, 2015, Georgia Power's current liabilities exceeded current assets by $1.7 billion primarily due to approximately $2.4 billion of long-term debt due within one year and notes payable. In 2015, Georgia Power expects to utilize borrowings through the FFB as the primary source of long-term borrowed funds. Georgia Power also intends to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and 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 March 31, 2015, Georgia Power had approximately $413 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2015 were as follows:

Expires								Due Within One Year
2016		2018		Total		Unused		Term Out		No Term Out
(in millions)				(in millions)				(in millions)
$	150	$	1,600	$	1,750	$	1,736	$	—	$	150

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 variable rate pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2015 was approximately $865 million. In addition, at March 31, 2015, Georgia Power had $118 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to March 31, 2015, $65

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million of these fixed rate pollution control revenue bonds were purchased and are being held by Georgia Power and currently are not required to be remarketed within the next 12 months.

Georgia Power's credit arrangements contain covenants that limit debt levels and contain cross default provisions to other indebtedness (including guarantee obligations) of Georgia Power. Such cross default provisions to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness or guarantee obligations over a specified threshold. Georgia 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, Georgia Power expects to renew or replace its credit arrangements, as needed, prior to expiration.

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 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 March 31, 2015				Short-term Debt During the Period(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
Commercial paper	$	590	0.3	%	$	272	0.3	%	$	678
Short-term bank debt	250		0.8	%	3		0.8	%	250
Total	$	840	0.4	%	$	275	0.3	%

(*) Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2015.

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, interest rate derivatives, and construction of new generation. The maximum potential collateral requirements under these contracts at March 31, 2015 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	24
Below BBB- and/or Baa3	1,424

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.

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Additionally, a credit rating downgrade could impact Georgia Power's access to the short-term debt market and the variable rate pollution control revenue bond market.

Financing Activities

In March 2015, Georgia Power entered into a three-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $250 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes.

Subsequent to March 31, 2015, Georgia Power purchased and held $65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008. Georgia Power may reoffer these bonds to the public at a later date.

Also subsequent to March 31, 2015, Georgia Power redeemed $125 million aggregate principal amount of its Series Y 5.80% Senior Notes due April 15, 2035; as a result, Georgia Power reclassified the outstanding principal balance to securities due within one year at March 31, 2015.

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 March 31,
	2015			2014
	(in millions)
Operating Revenues:
Retail revenues	$	293		$	303
Wholesale revenues, non-affiliates	25			36
Wholesale revenues, affiliates	22			53
Other revenues	17			15
Total operating revenues	357			407
Operating Expenses:
Fuel	110			168
Purchased power, non-affiliates	25			15
Purchased power, affiliates	9			7
Other operations and maintenance	93			84
Depreciation and amortization	20			32
Taxes other than income taxes	28			27
Total operating expenses	285			333
Operating Income	72			74
Other Income and (Expense):
Allowance for equity funds used during construction	4			2
Interest expense, net of amounts capitalized	(13		)	(13		)
Other income (expense), net	(1		)	(1		)
Total other income and (expense)	(10		)	(12		)
Earnings Before Income Taxes	62			62
Income taxes	23			23
Net Income	39			39
Dividends on Preference Stock	2			2
Net Income After Dividends on Preference Stock	$	37		$	37

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2015		2014
	(in millions)
Net Income	$	39	$	39
Other comprehensive income (loss)	—		—
Comprehensive Income	$	39	$	39

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 Three Months Ended March 31,
	2015			2014
	(in millions)
Operating Activities:
Net income	$	39		$	39
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	22			34
Deferred income taxes	27			14
Allowance for equity funds used during construction	(4		)	(2		)
Other, net	11			2
Changes in certain current assets and liabilities —
-Receivables	12			(25		)
-Fossil fuel stock	(2		)	46
-Prepaid income taxes	3			10
-Other current assets	2			1
-Accounts payable	(28		)	6
-Accrued taxes	5			9
-Accrued compensation	(16		)	(5		)
-Other current liabilities	10			13
Net cash provided from operating activities	81			142
Investing Activities:
Property additions	(84		)	(79		)
Cost of removal, net of salvage	(5		)	(3		)
Other investing activities	(3		)	(1		)
Net cash used for investing activities	(92		)	(83		)
Financing Activities:
Increase (decrease) in notes payable, net	40			(75		)
Proceeds — Common stock issued to parent	20			50
Payment of preference stock dividends	(2		)	(2		)
Payment of common stock dividends	(33		)	(31		)
Other financing activities	2			—
Net cash provided from (used for) financing activities	27			(58		)
Net Change in Cash and Cash Equivalents	16			1
Cash and Cash Equivalents at Beginning of Period	39			22
Cash and Cash Equivalents at End of Period	$	55		$	23
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $2 and $1 capitalized for 2015 and 2014, respectively)	$	3		$	5
Income taxes, net	(8		)	(6		)
Noncash transactions — Accrued property additions at end of period	41			33

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

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GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2015			At December 31, 2014
	(in millions)
Current Assets:
Cash and cash equivalents	$	55		$	39
Receivables —
Customer accounts receivable	79			73
Unbilled revenues	52			58
Under recovered regulatory clause revenues	53			57
Other accounts and notes receivable	9			8
Affiliated companies	1			10
Accumulated provision for uncollectible accounts	(2		)	(2		)
Fossil fuel stock, at average cost	104			101
Materials and supplies, at average cost	54			56
Other regulatory assets, current	77			74
Prepaid expenses	38			40
Other current assets	2			2
Total current assets	522			516
Property, Plant, and Equipment:
In service	4,405			4,495
Less accumulated provision for depreciation	1,236			1,296
Plant in service, net of depreciation	3,169			3,199
Other utility plant, net	79			—
Construction work in progress	474			465
Total property, plant, and equipment	3,722			3,664
Other Property and Investments	15			15
Deferred Charges and Other Assets:
Deferred charges related to income taxes	59			56
Other regulatory assets, deferred	423			416
Other deferred charges and assets	37			41
Total deferred charges and other assets	519			513
Total Assets	$	4,778		$	4,708

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

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Liabilities and Stockholder's Equity	At March 31, 2015			At December 31, 2014
	(in millions)
Current Liabilities:
Securities due within one year	$	23		$	—
Notes payable	150			110
Accounts payable —
Affiliated	68			87
Other	49			56
Customer deposits	35			35
Other accrued taxes	14			9
Accrued interest	21			11
Accrued compensation	7			23
Deferred capacity expense, current	22			22
Liabilities from risk management activities	37			37
Other current liabilities	24			23
Total current liabilities	450			413
Long-term Debt	1,347			1,370
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	836			800
Employee benefit obligations	120			121
Other cost of removal obligations	218			235
Other regulatory liabilities, deferred	45			49
Deferred capacity expense	158			163
Other deferred credits and liabilities	120			101
Total deferred credits and other liabilities	1,497			1,469
Total Liabilities	3,294			3,252
Preference Stock	147			147
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — March 31, 2015: 5,642,717 shares
— December 31, 2014: 5,442,717 shares	503			483
Paid-in capital	563			560
Retained earnings	272			267
Accumulated other comprehensive loss	(1		)	(1		)
Total common stockholder's equity	1,337			1,309
Total Liabilities and Stockholder's Equity	$	4,778		$	4,708

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

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FIRST QUARTER 2015 vs. FIRST QUARTER 2014

OVERVIEW

Gulf Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area 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. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Gulf Power for the foreseeable future.

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.

RESULTS OF OPERATIONS

Net Income

Gulf Power's net income after dividends on preference stock for the first quarter 2015 and the corresponding period in 2014 was $37 million. Net income for the first quarter 2015 was positively impacted by a reduction in depreciation expense, as authorized by the Florida PSC, which was largely offset by higher operations and maintenance expenses.

Retail Revenues

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(10)	(3.3)

In the first quarter 2015, retail revenues were $293 million compared to $303 million for the corresponding period in 2014.

Details of the changes in retail revenues were as follows:

	First Quarter 2015
	(in millions)			(% change)
Retail – prior year	$	303
Estimated change resulting from –
Rates and pricing	4			1.3
Sales decline	(2		)	(0.7	)
Weather	—			—
Fuel and other cost recovery	(12		)	(3.9	)
Retail – current year	$	293		(3.3	)%

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

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"Revenues" and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's retail base rate case and cost recovery clauses, including Gulf Power's fuel cost recovery, purchased power capacity recovery, environmental cost recovery, and energy conservation cost recovery clauses.

Revenues associated with changes in rates and pricing increased in the first quarter 2015 when compared to the corresponding period in 2014 primarily due to an increase in retail base rates effective in January 2015 and higher revenues associated with an increase in the environmental and energy conservation cost recovery clause rates effective in January 2015.

Revenues attributable to changes in sales decreased in the first quarter 2015 when compared to the corresponding period in 2014. Weather-adjusted KWH energy sales to residential and commercial customers decreased 5.2% and 2.0%, respectively, due to lower customer usage, partially offset by customer growth. KWH energy sales to industrial customers decreased 2.5% primarily due to increased customer co-generation.

Fuel and other cost recovery revenues decreased in the first quarter 2015 when compared to the corresponding period in 2014 primarily due to lower revenues associated with recoverable fuel costs for decreased generation and purchased power costs, partially offset by higher revenues associated with increased recoverable costs under Gulf Power's purchased power capacity cost recovery clause.

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

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(11)	(30.6)

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 first quarter 2015, wholesale revenues from sales to non-affiliates were $25 million compared to $36 million for the corresponding period in 2014. The decrease was primarily due to a 59.7% decrease in KWH sales resulting from lower sales under the Plant Scherer Unit 3 long-term sales agreements due to a planned outage and lower natural gas prices that led to increased customer generation.

Wholesale Revenues – Affiliates

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(31)	(58.5)

Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by

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the FERC. These transactions do not have a significant impact on earnings since the revenue related to these energy sales generally offsets the cost of energy sold.

In the first quarter 2015, wholesale revenues from sales to affiliates were $22 million compared to $53 million for the corresponding period in 2014. The decrease was primarily due to a 28.5% decrease in the price of energy sold to affiliates due to lower pool interchange rates resulting from lower natural gas prices and a 40.8% decrease in KWH sales that resulted from more planned outages for Gulf Power generation resources.

Fuel and Purchased Power Expenses

	First Quarter 2015 vs. First Quarter 2014
	(change in millions)			(% change)
Fuel	$	(58	)	(34.5	)
Purchased power – non-affiliates	10			66.7
Purchased power – affiliates	2			28.6
Total fuel and purchased power expenses	$	(46	)

In the first quarter 2015, total fuel and purchased power expenses were $144 million compared to $190 million for the corresponding period in 2014. The decrease was primarily the result of a $39 million decrease in the volume of KWHs generated and purchased due to more planned outages for Gulf Power's generation and a resource contracted under a PPA and a $7 million decrease due to the lower average cost of fuel and purchased power.

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

	First Quarter 2015	First Quarter 2014
Total generation (millions of KWHs)	2,236	2,962
Total purchased power (millions of KWHs)	1,259	1,430
Sources of generation (percent) –
Coal	59	70
Gas	41	30
Cost of fuel, generated (cents per net KWH) –
Coal	3.98	4.31
Gas	3.95	3.66
Average cost of fuel, generated (cents per net KWH)	3.97	4.11
Average cost of purchased power (cents per net KWH)(*)	4.36	4.79

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

Fuel

In the first quarter 2015, fuel expense was $110 million compared to $168 million for the corresponding period in 2014. The decrease was primarily due to a 24.5% decrease in the volume of KWHs generated due to more planned outages for Gulf Power's generation and a resource contracted under a PPA in the first quarter 2015.

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Purchased Power – Non-Affiliates

In the first quarter 2015, purchased power expense from non-affiliates was $25 million compared to $15 million for the corresponding period in 2014. The increase was primarily due to an increase in the average cost per KWH purchased, which included a $16 million increase in capacity costs associated with a scheduled rate increase for an existing PPA, partially offset by the expiration of another PPA in mid-2014. The increase was partially offset by a 25.2% decrease in the volume of KWHs purchased due to a planned outage for a resource contracted under a PPA.

Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy 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 first quarter 2015, purchased power expense from affiliates was $9 million compared to $7 million for the corresponding period in 2014. The increase was primarily due to an 87.8% increase in the volume of KWHs purchased due to more planned outages for Gulf Power's generation and a resource contracted under a PPA, partially offset by a 33.2% decrease in the average cost per KWH 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

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$9	10.7

In the first quarter 2015, other operations and maintenance expenses were $93 million compared to $84 million for the corresponding period in 2014. The increase was primarily due to increases of $7 million in routine and planned maintenance expense at generation facilities and $2 million in employee compensation and benefits including pension costs. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

Depreciation and Amortization

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(12)	(37.5)

In the first quarter 2015, depreciation and amortization was $20 million compared to $32 million for the corresponding period in 2014. As authorized by the Florida PSC in a settlement agreement, Gulf Power recorded a $19.6 million reduction in depreciation expense in the first quarter 2015 as compared to $6.2 million in the corresponding period in 2014. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Retail Base Rate Case" of Gulf Power in Item 7 and 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

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$2	100.0

In the first quarter 2015, AFUDC equity was $4 million compared to $2 million for the corresponding period in 2014. The increase was primarily due to increased construction related to environmental control projects at generation and transmission facilities.

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 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. Changes in regional and global economic conditions may impact sales for Gulf Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and 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.

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 other 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 co-ownership of a unit with Georgia Power at Plant Scherer and consist of both capacity and energy sales. Capacity revenues represent the majority of Gulf Power's wholesale earnings. Gulf Power currently has long-term sales agreements for 100% of Gulf Power's ownership of that unit through 2015 and 41% through 2019. These capacity revenues represented 82% of total wholesale capacity revenues for 2014. Gulf Power is actively pursuing replacement wholesale contracts but the expiration of current contracts could have a material negative impact on Gulf Power's earnings. In the event some portion of Gulf Power's ownership in Plant Scherer is not subject to a replacement long-term wholesale contract, the proportionate amount of the unit may be sold into the power pool or into the wholesale market.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be 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. 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

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DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" and "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Statutes and Regulations

Coal Combustion Residuals

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

On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 14, 2015 as the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this timeand will depend on Gulf Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Gulf Power expects to record incremental asset retirement obligations of approximately $70 million to $80 million related to the CCR Rule in the second quarter 2015.

FERC Matters

Gulf Power has 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 operating companies (including Gulf Power) and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including Gulf Power's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC has directed the traditional operating companies (including Gulf Power) and Southern Power, within 60 days, 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. Gulf Power is evaluating the order. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

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

Retail Base Rate Case

In December 2013, the Florida PSC approved a settlement agreement that provides Gulf Power may reduce depreciation expense and record a regulatory asset up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation expense reduction may not exceed the amount necessary for the ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Gulf Power recognized a $19.6 million reduction in depreciation expense in the first three months of 2015.

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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 preliminarily approved on April 16, 2015, three energy purchase agreements totaling 120 MWs of utility-scale solar generation located at three military installations in northwest Florida. These contracts are expected to begin in 2016 with a term of 25 years each. The Florida PSC preliminarily approved on May 5, 2015, an energy purchase agreement for up to 178 MWs of wind generation in central Oklahoma. The agreement is expected to begin by the end of 2015 with a term of 20 years. Purchases under these agreements will be for energy only and are expected to be recovered through Gulf Power's fuel cost recovery mechanism. The ultimate outcome of these matters cannot be determined at this time.

Other Matters

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

The ultimate outcome of such pending or potential litigation against Gulf Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Gulf Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Gulf Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board (FASB) issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition. On April 29, 2015, the FASB issued an exposure draft proposing the standard be effective for fiscal years beginning after December 15, 2017. Gulf Power

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continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Gulf Power currently reflects unamortized debt issuance costs in other deferred charges and assets on its balance sheet. Upon adoption, the reclassification will not 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 March 31, 2015. 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 $81 million for the first three months of 2015 compared to $142 million for the corresponding period in 2014. The $61 million decrease in net cash was primarily due to decreases in cash flows related to the timing of fossil fuel stock purchases and decreases in accounts payable, partially offset by increases in the recovery of fuel costs. Net cash used for investing activities totaled $92 million in the first three months of 2015 primarily due to property additions related to steam generation and transmission. Net cash provided from financing activities totaled $27 million for the first three months of 2015 primarily due to an increase in notes payable and the issuance of common stock, partially offset by the payment of common stock dividends. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2015 include increases of $58 million in net property, plant, and equipment, $40 million in notes payable, $36 million in accumulated deferred income tax liabilities, and the reclassification of $23 million of long-term debt to debt due within one year.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, derivative obligations, preference stock dividends, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $23 million will be required through March 31, 2016 to fund the repayment of debt due within one year.

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.

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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, 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 cash needs, which can fluctuate significantly due to the seasonality of the business. Gulf Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet short-term liquidity needs, including its commercial paper program which is supported by bank credit facilities.

At March 31, 2015, Gulf Power had approximately $55 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2015 were as follows:

Expires										Executable Term Loans				Due Within One Year
2015		2016		2017		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)						(in millions)				(in millions)				(in millions)
$	45	$	200	$	30	$	275	$	275	$	50	$	—	$	50	$	195

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 default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of Gulf Power. Such cross default provisions to other indebtedness would trigger an event of default if Gulf Power defaulted on indebtedness or guarantee obligations over a specified threshold. 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.

Most of the unused credit arrangements with banks is allocated to provide liquidity support to Gulf Power's variable rate pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2015 was approximately $69 million. In addition, at March 31, 2015, Gulf Power had $78 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 operating companies. Proceeds from such issuances for the benefit of Gulf Power are loaned directly to Gulf Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.

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Details of short-term borrowings were as follows:

	Short-term Debt at March 31, 2015			Short-term Debt During the Period(*)
	Amount Outstanding		Weighted Average Interest Rate	Average Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
Commercial paper	$	150	0.3%	$	110	0.3%	$	150

(*) Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2015.

Gulf Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, 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, and energy price risk management. The maximum potential collateral requirements under these contracts at March 31, 2015 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	74
Below BBB- and/or Baa3	447

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, any credit rating downgrade could impact Gulf Power's ability to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.

Market Price Risk

Gulf Power's market risk exposure relative to interest rate changes for the first quarter 2015 has not changed materially compared to the December 31, 2014 reporting period. Gulf Power's exposure to market volatility in commodity fuel prices and prices of electricity with respect to its wholesale generating capacity is limited because its long-term sales 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. Gulf Power currently has long-term sales agreements for 100% of its wholesale capacity through 2015 and 41% through 2019. These capacity revenues represented 82% of total wholesale capacity revenues for 2014. Gulf Power is actively pursuing replacement wholesale contracts but the expiration of current contracts could have a material negative impact on Gulf Power's earnings. In the event some portion of Gulf Power's ownership in Plant Scherer is not subject to a replacement long-term wholesale contract, the proportionate amount of the unit may be sold into the power pool or into the wholesale market. 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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities

In January 2015, Gulf Power issued 200,000 shares of common stock to Southern Company and realized proceeds of $20 million. The proceeds were used to repay a portion of Gulf Power's short-term debt and for other general corporate purposes, including Gulf Power's continuous construction program.

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.

84

MISSISSIPPI POWER COMPANY

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MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)

	For the Three Months Ended March 31,
	2015			2014
	(in millions)
Operating Revenues:
Retail revenues	$	167		$	207
Wholesale revenues, non-affiliates	77			97
Wholesale revenues, affiliates	27			23
Other revenues	5			4
Total operating revenues	276			331
Operating Expenses:
Fuel	114			147
Purchased power, non-affiliates	2			11
Purchased power, affiliates	2			9
Other operations and maintenance	73			66
Depreciation and amortization	27			23
Taxes other than income taxes	25			20
Estimated loss on Kemper IGCC	9			380
Total operating expenses	252			656
Operating Income (Loss)	24			(325		)
Other Income and (Expense):
Allowance for equity funds used during construction	28			38
Interest expense, net of amounts capitalized	(11		)	(12		)
Other income (expense), net	(2		)	(3		)
Total other income and (expense)	15			23
Earnings (Loss) Before Income Taxes	39			(302		)
Income taxes (benefit)	4			(130		)
Net Income (Loss)	35			(172		)
Dividends on Preferred Stock	—			—
Net Income (Loss) After Dividends on Preferred Stock	$	35		$	(172	)

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

	For the Three Months Ended March 31,
	2015		2014
	(in millions)
Net Income (Loss)	$	35	$	(172	)
Other comprehensive income (loss)	—		—
Comprehensive Income (Loss)	$	35	$	(172	)

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

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CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended March 31,
	2015			2014
	(in millions)
Operating Activities:
Net income (loss)	$	35		$	(172	)
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	26			24
Deferred income taxes	141			(124		)
Allowance for equity funds used during construction	(28		)	(38		)
Regulatory assets associated with Kemper IGCC	(27		)	(13		)
Estimated loss on Kemper IGCC	9			380
Other, net	11			8
Changes in certain current assets and liabilities —
-Receivables	17			(14		)
-Fossil fuel stock	4			37
-Prepaid income taxes	44			(33		)
-Other current assets	(3		)	(5		)
-Accounts payable	(22		)	15
-Accrued taxes	(54		)	(55		)
-Accrued interest	9			8
-Accrued compensation	(20		)	(2		)
-Over recovered regulatory clause revenues	22			(18		)
-Mirror CWIP	40			34
Net cash provided from operating activities	204			32
Investing Activities:
Property additions	(213		)	(324		)
Construction payables	(14		)	(31		)
Other investing activities	(6		)	(6		)
Net cash used for investing activities	(233		)	(361		)
Financing Activities:
Proceeds —
Capital contributions from parent company	76			1
Interest-bearing refundable deposit	—			75
Other long-term debt issuances	—			250
Short-term borrowings	30			—
Redemptions — Other long-term debt	(75		)	—
Payment of preferred stock dividends	—			—
Return of capital	—			(55		)
Other financing activities	(1		)	(2		)
Net cash provided from financing activities	30			269
Net Change in Cash and Cash Equivalents	1			(60		)
Cash and Cash Equivalents at Beginning of Period	133			145
Cash and Cash Equivalents at End of Period	$	134		$	85
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $17 and $17, net of $18 and $14 capitalized for 2015 and 2014, respectively)	$	(1	)	$	3
Income taxes, net	(180		)	26
Noncash transactions — Accrued property additions at end of period	100			132

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 March 31, 2015			At December 31, 2014
	(in millions)
Current Assets:
Cash and cash equivalents	$	134		$	133
Receivables —
Customer accounts receivable	38			43
Unbilled revenues	33			35
Other accounts and notes receivable	13			11
Affiliated companies	40			51
Accumulated provision for uncollectible accounts	(1		)	(1		)
Fossil fuel stock, at average cost	96			100
Materials and supplies, at average cost	64			62
Other regulatory assets, current	74			73
Prepaid income taxes	162			191
Other current assets	6			6
Total current assets	659			704
Property, Plant, and Equipment:
In service	4,396			4,378
Less accumulated provision for depreciation	1,194			1,173
Plant in service, net of depreciation	3,202			3,205
Construction work in progress	2,361			2,161
Total property, plant, and equipment	5,563			5,366
Other Property and Investments	6			5
Deferred Charges and Other Assets:
Deferred charges related to income taxes	243			226
Other regulatory assets, deferred	419			385
Other deferred charges and assets	57			71
Total deferred charges and other assets	719			682
Total Assets	$	6,947		$	6,757

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 March 31, 2015			At December 31, 2014
	(in millions)
Current Liabilities:
Securities due within one year	$	3		$	778
Notes Payable	30			—
Interest-bearing refundable deposit	275			275
Accounts payable —
Affiliated	80			86
Other	148			178
Accrued taxes —
Accrued income taxes	185			142
Other accrued taxes	29			84
Accrued interest	86			76
Accrued compensation	6			26
Over recovered regulatory clause liabilities	23			1
Mirror CWIP	311			271
Other current liabilities	61			61
Total current liabilities	1,237			1,978
Long-term Debt	2,328			1,630
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	397			285
Accumulated deferred investment tax credits	282			283
Employee benefit obligations	148			148
Asset retirement obligations	49			48
Other cost of removal obligations	168			166
Other regulatory liabilities, deferred	65			64
Other deferred credits and liabilities	43			38
Total deferred credits and other liabilities	1,152			1,032
Total Liabilities	4,717			4,640
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	2,690			2,612
Accumulated deficit	(524		)	(559		)
Accumulated other comprehensive loss	(7		)	(7		)
Total common stockholder's equity	2,197			2,084
Total Liabilities and Stockholder's Equity	$	6,947		$	6,757

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

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2015 vs. FIRST QUARTER 2014

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 maintain 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 (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).

Mississippi Power's current cost estimate for the Kemper IGCC in total is approximately $6.22 billion, which includes approximately $4.94 billion of costs subject to the construction cost cap. Mississippi Power does not intend to seek any rate recovery or joint owner contributions for any related costs that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $9 million ($6 million after tax) in the first quarter 2015. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.06 billion ($1.27 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through March 31, 2015.

Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC project in service in August 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities. The in-service date for the remainder of the Kemper IGCC is currently expected to occur in the first half of 2016. The current cost estimate includes costs through March 31, 2016. As a result of the additional factors that have the potential to impact start-up and operational readiness activities for this first-of-a-kind technology as described herein, the risk of further schedule extensions and/or cost increases, which could be material, remains.

For additional information on the Kemper IGCC, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein.

On February 12, 2015, the Mississippi Supreme Court (Court) issued its decision in a legal challenge filed by Thomas A. Blanton with respect to the Mississippi PSC's March 2013 order that authorized the collection of $156 million annually (2013 MPSC Rate Order) to be recorded as Mirror CWIP. The Court reversed the 2013 MPSC Rate Order, deemed the 2013 Settlement Agreement (defined below) between Mississippi Power and the

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Mississippi PSC unenforceable due to a lack of public notice for the related proceedings, and directed the Mississippi PSC to enter an order requiring Mississippi Power to refund the Mirror CWIP amounts collected pursuant to the 2013 MPSC Rate Order. As of March 31, 2015, $294 million had been collected by Mississippi Power. On March 12, 2015, Mississippi Power and the Mississippi PSC filed motions for rehearing. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Mississippi Supreme Court Decision" herein for additional information.

Mississippi Power also expects to seek rate recovery through alternate means, which could include a traditional rate case. On May 1, 2015, Mississippi Power notified the Mississippi PSC of its plans to file a rate request in May 2015.

As of March 31, 2015, Mississippi Power's current liabilities exceeded current assets by approximately $578 million primarily due to $275 million of refundable deposits from SMEPA and the potential refund of approximately $311 million in Mirror CWIP, which includes associated carrying costs. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Proposed Sale of Undivided Interest to SMEPA" and " – Rate Recovery of Kemper IGCC Costs – 2015 Mississippi Supreme Court Decision" herein for additional information. In addition, Mississippi Power has $900 million in bank term loans that mature on April 1, 2016. Mississippi Power intends to utilize operating cash flows and lines of credit, bank term loans, and commercial paper, as market conditions permit, as well as, under certain circumstances, equity contributions and/or loans from Southern Company, to fund Mississippi Power's short-term capital needs.

Mississippi Power continues to focus on several key performance indicators, including the construction and start-up 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. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding revisions to the cost estimate for the Kemper IGCC and the Court's decision that have negatively impacted Mississippi Power's actual performance on net income after dividends on preferred stock, one of its key performance indicators, for 2015, as compared to the target.

RESULTS OF OPERATIONS

Net Income (Loss)

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$207	N/M

N/M – Not meaningful

Mississippi Power's net income after dividends on preferred stock for the first quarter 2015 was $35 million compared to a net loss after dividends on preferred stock of $172 million for the corresponding period in 2014. The increase was primarily related to a lower pre-tax charge of $9 million ($6 million after tax) in the first quarter 2015 compared to a pre-tax charge of $380 million ($235 million after tax) in the first quarter 2014 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 DOE Grants and excluding the Cost Cap Exceptions. The increase was partially offset by a decrease in AFUDC equity, increases in non-fuel operations and maintenance expenses, and a decrease in retail revenues primarily resulting from the Court's decision.

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Retail Revenues

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(40)	(19.3)

In the first quarter 2015, retail revenues were $167 million compared to $207 million for the corresponding period in 2014.

Details of the changes in retail revenues were as follows:

	First Quarter 2015
	(in millions)			(% change)
Retail – prior year	$	207
Estimated change resulting from –
Rates and pricing	(4		)	(1.9	)
Sales decline	(4		)	(1.9	)
Weather	(1		)	(0.5	)
Fuel and other cost recovery	(31		)	(15.0	)
Retail – current year	$	167		(19.3	)%

Revenues associated with changes in rates and pricing decreased in the first quarter 2015 when compared to the corresponding period in 2014 primarily due to not recognizing revenues associated with the Kemper IGCC cost recovery in 2015 as a result of the Court's decision, partially offset by $1 million in net revenues for the new energy efficiency cost recovery rate, which began in the fourth quarter 2014.

See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and "Retail Regulatory Matters – Performance Evaluation Plan" 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 first quarter 2015 when compared to the corresponding period in 2014. Weather-adjusted KWH sales to residential and commercial customers decreased 1.9% and 3.5%, respectively, in the first quarter 2015 due to lower customer usage. KWH sales to industrial customers increased 3.5% in the first quarter 2015 due to increased usage by larger customers.

In the first quarter 2015, Mississippi Power updated its 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 2014 KWH sales among customer classes that is consistent with the actual allocation in 2015. Without this adjustment, first quarter 2015 weather-adjusted residential KWH sales decreased 9.9%, weather-adjusted commercial KWH sales decreased 9.3%, and industrial KWH sales increased 2.3% as compared to the corresponding period in 2014.

Fuel and other cost recovery revenues decreased in the first quarter 2015 when compared to the corresponding period in 2014, 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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(20)	(20.6)

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 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. Mississippi Power serves 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 for additional information.

In the first quarter 2015, wholesale revenues from sales to non-affiliates were $77 million compared to $97 million for the corresponding period in 2014. The decrease was primarily due to a decrease in energy revenues resulting from lower market prices.

Wholesale Revenues – Affiliates

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$4	17.4

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

In the first quarter 2015, wholesale revenues from sales to affiliates were $27 million compared to $23 million for the corresponding period in 2014. The increase was due to a $4 million increase in energy revenues primarily due to a $14 million increase associated with higher natural gas generation, partially offset by a $10 million decrease associated with lower natural gas prices.

Fuel and Purchased Power Expenses

	First Quarter 2015 vs. First Quarter 2014
	(change in millions)			(% change)
Fuel	$	(33	)	(22.4)
Purchased power – non-affiliates	(9		)	(81.8)
Purchased power – affiliates	(7		)	(77.8)
Total fuel and purchased power expenses	$	(49	)

In the first quarter 2015, total fuel and purchased power expenses were $118 million compared to $167 million for the corresponding period in 2014. The decrease was due to a $42 million decrease in the average cost of fuel and

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

purchased power and an $11 million decrease in the volume of KWHs purchased, partially offset by a $4 million increase in the volume of KWHs generated.

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

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

	First Quarter 2015	First Quarter 2014
Total generation (millions of KWHs)(*)	4,345	4,043
Total purchased power (millions of KWHs)	114	258
Sources of generation (percent)(*) –
Coal	22	46
Gas	78	54
Cost of fuel, generated (cents per net KWH) –
Coal	3.25	4.23
Gas(*)	2.68	3.59
Average cost of fuel, generated (cents per net KWH)(*)	2.82	3.91
Average cost of purchased power (cents per net KWH)(*)	3.54	7.90

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

Fuel

In the first quarter 2015, fuel expense was $114 million compared to $147 million for the corresponding period in 2014. The decrease was primarily due to a 27.9% decrease in the average cost of fuel per KWH generated primarily due to higher gas-fired generation at lower natural gas prices, partially offset by a 7.3% increase in the volume of KWHs generated resulting from the availability of lower cost Mississippi Power units. The 7.3% increase in volume included an increase in gas-fired generation of 60.4%, partially offset by a decrease in coal-fired generation of 47.3%.

Purchased Power - Non-Affiliates

In the first quarter 2015, purchased power expense from non-affiliates was $2 million compared to $11 million for the corresponding period in 2014. The decrease was primarily the result of an 80.0% decrease in the volume of KWHs purchased due to milder weather and a 33.5% decrease in the average cost per KWH purchased as a result of lower natural gas prices.

Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy 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 first quarter 2015, purchased power expense from affiliates was $2 million compared to $9 million for the corresponding period in 2014. The decrease was primarily due to a 52.1% decrease in the average cost per KWH purchased as a result of lower natural gas prices and a 41.7% decrease in the volume of KWHs purchased due to milder weather.

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, as approved by the FERC.

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Other Operations and Maintenance Expenses

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$7	10.6

In the first quarter 2015, other operations and maintenance expenses were $73 million compared to $66 million for the corresponding period in 2014. The increase was primarily due to a $4 million increase in advertising and employee compensation and benefits including pension costs and a $3 million increase in customer accounting primarily due to uncollectible expenses and customer incentives.

See Note (F) to the Condensed Financial Statements under "Retirement Benefits" herein for additional information.

Depreciation and Amortization

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$4	17.4

In the first quarter 2015, depreciation and amortization was $27 million compared to $23 million for the corresponding period in 2014. The increase was primarily due to a $2 million increase in depreciation related to increases in generation and transmission plant in service, a $1 million increase resulting from a lower regulatory deferral associated with the purchase of Plant Daniel Units 3 and 4, and a $1 million increase in amortization primarily resulting from the lower Kemper IGCC regulatory deferrals in 2015.

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

Taxes Other Than Income Taxes

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$5	25.0

In the first quarter 2015, taxes other than income taxes were $25 million compared to $20 million for the corresponding period in 2014. The increase was primarily due to an increase in ad valorem taxes related to Kemper IGCC assets in service.

Estimated Loss on Kemper IGCC

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(371)	(97.6)

In the first quarter 2015 and the first quarter 2014, estimated probable losses on the Kemper IGCC of $9 million and $380 million, respectively, were recorded to 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 DOE Grants and excluding the Cost Cap Exceptions.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Allowance for Equity Funds Used During Construction

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(10)	(26.3)

In the first quarter 2015, AFUDC equity was $28 million compared to $38 million for the corresponding period in 2014. The decrease was primarily due to placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014. 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 regarding the Kemper IGCC.

Income Taxes (Benefit)

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$134	N/M

N/M – Not meaningful

In the first quarter 2015, income taxes (benefit) were $4 million compared to $(130) million for the corresponding period in 2014. The change primarily reflects a reduction in tax benefits related to the estimated probable losses on the construction of the Kemper IGCC recorded in 2014.

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 prevail against legal challenges associated with the Kemper IGCC, and recover its prudently-incurred costs in a timely manner during a time of increasing costs, and the completion and subsequent operation of the Kemper IGCC and the Plant Daniel scrubber project 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, new energy contracts 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. Changes in regional and global economic conditions may impact sales for Mississippi Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through market-based contracts. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced

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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.

On April 23, 2015, Mississippi Power made the decision to retire its coal-fired generation at Plant Watson Units 1 and 2 (150 MWs) by July 1, 2015, based on an economic analysis of expected environmental compliance costs. The net book value, at March 31, 2015, of these two units was approximately $2 million excluding the reserve for cost of removal. Mississippi Power expects to recover through its rates the remaining book value of the retired units and certain costs associated with the retirements; however, recovery will be considered by the Mississippi PSC in future rate proceedings.

Environmental Statutes and Regulations

See Note 3 to the financial statements of Mississippi Power under "Other Matters – Sierra Club Settlement Agreement" in Item 8 of the Form 10-K for additional information.

Coal Combustion Residuals

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

On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 14, 2015 as the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this timeand will depend on Mississippi Power's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. Based on initial estimates, Mississippi Power expects to record incremental asset retirement obligations (ARO) of approximately $75 million to $85 million related to the CCR Rule in the second quarter 2015.

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, 2015, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC to forgo the Municipal and Rural Associations cost-based electric tariff increase reflected in the filing by, among other things, increasing the accrual of AFUDC in lieu of including CWIP in rate base. The settlement agreement, if accepted by the FERC, provides that the additional accrual of AFUDC is effective April 1, 2015. The additional resulting AFUDC is projected to be approximately $12 million annually, of which $9 million relates to the Kemper IGCC. In addition, a settlement agreement entered into in 2014 and approved by the FERC allowed for an adjustment to the wholesale revenue requirement in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. A regulatory asset account was recorded as a result of a portion of the Kemper IGCC being placed in service prior to the projected date. The March 31, 2015 settlement agreement provides that the regulatory asset will be amortized over nine months, beginning April 1, 2015. The ultimate outcome of this matter cannot be determined at this time.

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Market-Based Rate Authority

Mississippi Power has 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 operating companies (including Mississippi Power) and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional operating companies' (including Mississippi Power's) and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. To retain market-based rate authority, the FERC has directed the traditional operating companies (including Mississippi Power) and Southern Power, within 60 days, 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. Mississippi Power is evaluating the order. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as the Kemper IGCC, 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" and "Integrated Coal Gasification Combined Cycle" herein for additional information.

Renewables

Subsequent to March 31, 2015, Mississippi Power entered into separate PPAs for three solar facilities for a combined total of approximately 105 MWs. Mississippi Power would purchase all of the energy produced by the solar facilities for the 25-year term of the contracts. If approved by the Mississippi PSC, the projects are expected to be in service by the end of 2016 and the resulting energy purchases will be recovered through Mississippi Power's fuel cost recovery mechanism. The ultimate outcome of this matter cannot be determined at this time.

Performance Evaluation Plan

On March 17, 2015, Mississippi Power submitted its annual PEP lookback filing for 2014, which indicated no surcharge or refund. On March 26, 2015, the Mississippi PSC suspended the filing to allow more time for review.

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

Ad Valorem Tax Adjustment

On April 23, 2015, Mississippi Power filed its annual ad valorem tax adjustment factor filing for 2015, which requested an annual rate decrease of 0.35%, or $2 million in annual retail revenues, primarily due to a decrease in average millage rates.

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

Integrated Coal Gasification Combined Cycle

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and 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 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 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 using natural gas in August 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, for which the in-service date is currently expected to occur in the first half of 2016. Recovery of the costs subject to the cost cap and the Cost Cap Exceptions remain 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 decision), and actual costs incurred as of March 31, 2015, as adjusted for the Court's decision, are as follows:

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Cost Category	2010 Project Estimate(f)		Current Estimate		Actual Costs at March 31, 2015
	(in billions)
Plant Subject to Cost Cap(a)	$	2.40	$	4.94	$	4.37
Lignite Mine and Equipment	0.21		0.23		0.23
CO2 Pipeline Facilities	0.14		0.11		0.10
AFUDC(b)(c)	0.17		0.64		0.48
Combined Cycle and Related Assets Placed in   Service – Incremental(d)	—		0.02		—
General Exceptions	0.05		0.10		0.08
Deferred Costs(c)(e)	—		0.18		0.14
Total Kemper IGCC(a)(c)	$	2.97	$	6.22	$	5.40

(a) The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and 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" for additional information.

(b) Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate includes an approximately $9 million increase in AFUDC related to a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.

(c) Amounts in the Current Estimate reflect estimated costs through March 31, 2016.

(d) Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information.

(e) The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities."

(f) The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO₂ pipeline facilities which was approved in 2011 by the Mississippi PSC.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of March 31, 2015, $3.27 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $2.06 billion), $2 million in other property and investments, $52 million in fossil fuel stock, $35 million in materials and supplies, $174 million in other regulatory assets, $12 million in other deferred charges and assets, and $24 million in AROs in the balance sheet, with $1 million previously expensed.

Mississippi Power does not intend to seek any rate recovery or joint owner contributions for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $9 million ($6 million after tax) in the first quarter 2015. This amount is in addition to charges totaling $868 million ($536 million after tax), $1.10 billion ($681 million after tax), and $78 million ($48 million after tax) in 2014, 2013, and 2012, respectively. The increases to the cost estimate in the first quarter 2015 primarily reflected costs related to additional labor costs in support of start-up and operational readiness activities. The current estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 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. Any further extension of the in-service date with respect to the Kemper IGCC 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 $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees, which are being deferred as regulatory assets and are estimated to total approximately $6 million per month.

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Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). 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 DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of operations and these changes could be material.

Rate Recovery of Kemper IGCC Costs

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 the evaluation of the Rate Mitigation Plan (defined below) and any alternative 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 Settlement Agreement

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, established 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. The 2013 Settlement Agreement also allowed Mississippi Power to secure alternate financing for costs not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. The Court found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. See "2015 Mississippi Supreme Court Decision" herein for additional information.

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's intent under the 2013 Settlement Agreement was to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs, which include carrying costs from the estimated in-service date until securitization is finalized and other costs not included in the Rate Mitigation Plan as approved by the Mississippi PSC. The Court's decision did not impact Mississippi Power's ability to utilize alternate financing through securitization, the 2012 MPSC CPCN Order, or the February 2013 legislation. See "2015 Mississippi Supreme Court Decision" herein for additional information.

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2013 MPSC Rate Order

Consistent with the terms of the 2013 Settlement Agreement, 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). For the period from March 2013 through March 31, 2015, $294 million had been collected primarily to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service. Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. 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. Mississippi Power will continue to record AFUDC and collect and defer the approved rates through the in-service date until directed to do otherwise by the Mississippi PSC.

In August 2014, Mississippi Power provided an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment. Mississippi Power's analysis requested, among other things, confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued collection of rates as prescribed by the 2013 MPSC Rate Order, with the current recognition as revenue of the related equity return on all assets placed in service and the deferral of all remaining rate collections under the 2013 MPSC Rate Order to a regulatory liability account. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which would discontinue the collection of, and require the refund of, all amounts previously collected under the 2013 MPSC Rate Order.

In addition, Mississippi Power's August 2014 filing with the Mississippi PSC requested confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC and the deferral of operating costs for the combined cycle as regulatory assets. Under Mississippi Power's proposal, non-incremental costs that would have been incurred whether or not the combined cycle was placed in service would be included in a regulatory asset and would continue to be subject to the $2.88 billion cost cap. Additionally, incremental costs that would not have been incurred if the combined cycle had not gone into service would be included in a regulatory asset and would not be subject to the cost cap because these costs are incurred to support operation of the combined cycle. All energy revenues associated with the combined cycle variable operating and maintenance expenses would be credited to this regulatory asset. See "Regulatory Assets and Liabilities" for additional information. Any action by the Mississippi PSC that is inconsistent with the treatment requested by Mississippi Power could have a material impact on the results of operations, financial condition, and liquidity of Mississippi Power.

2015 Mississippi Supreme Court Decision

On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order filed by Thomas A. Blanton. 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. The Court's ruling remands the matter to the Mississippi PSC to (1) fix by order the rates that were in existence prior to the 2013 MPSC Rate Order, (2) fix no rate increases until the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts collected under the 2013 MPSC Rate Order. Through March 31, 2015, Mississippi Power had collected $294 million through rates under the 2013 MPSC Rate Order. Any required refunds would also include carrying costs. The Court's decision will become legally effective upon the issuance of a mandate to the Mississippi PSC. Absent specific instruction from the Court, the Mississippi PSC will determine the method and timing of the refund. On March 12, 2015, Mississippi Power and the Mississippi PSC filed motions for rehearing. If the Court denies the motions, it would issue the mandate to the Mississippi PSC no later than seven days following such decision.

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Rate Mitigation Plan

In 2013, Mississippi Power, in compliance with the 2013 MPSC Rate Order, filed a revision to the proposed rate recovery plan with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020 (Rate Mitigation Plan), which is still under review by the Mississippi PSC. The revenue requirements set forth in the Rate Mitigation Plan assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation, which currently requires that the related long-term asset be placed in service in 2015.In the Rate Mitigation Plan, Mississippi Power proposed recovery of an annual revenue requirement of approximately $156 million of Kemper IGCC-related operational costs and rate base amounts, including plant costs equal to the $2.4 billion certificated cost estimate. The 2013 MPSC Rate Order, which increased rates beginning in March 2013, was integral to the Rate Mitigation Plan, which contemplates amortization of the regulatory liability balance at the in-service date to be used to mitigate customer rate impacts through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Rate Mitigation Plan, Mississippi Power proposed annual rate recovery to remain the same from 2014 through 2020, with the proposed revenue requirement approximating the forecasted cost of service for the period 2014 through 2020. Under Mississippi Power's proposal, to the extent the actual annual cost of service differs from the approved forecast for certain items, the difference would be deferred as a regulatory asset or liability, subject to accrual of carrying costs, and would be included in the next year's rate recovery calculation. If any deferred balance remains at the end of 2020, the Mississippi PSC would review the amount and, if approved, determine the appropriate method and period of disposition. See "Regulatory Assets and Liabilities" herein for additional information.

To the extent that refunds of amounts collected under the 2013 MPSC Rate Order are required on a schedule different from the amortization schedule proposed in the Rate Mitigation Plan, the customer billing impacts proposed under the Rate Mitigation Plan would no longer be viable. See "2015 Mississippi Supreme Court Decision" herein for additional information.

In addition to current estimated costs at March 31, 2015 of $6.22 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.

Mississippi Power also expects to seek rate recovery through alternate means, which could include a traditional rate case. On May 1, 2015, Mississippi Power notified the Mississippi PSC of its plans to file a rate request in May 2015.

Prudence Reviews

The Mississippi PSC's review of Kemper IGCC costs is ongoing. In August 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the Mississippi Public Utilities Staff (MPUS). The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues and Mississippi Power is working to reach a mutually acceptable resolution. As a result of the Court's decision, Mississippi Power intends to request that the Mississippi PSC reconsider its prudence review schedule. See "2015 Mississippi Supreme Court Decision" herein for additional information.

Regulatory Assets and Liabilities

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

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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. As of March 31, 2015, the regulatory asset balance associated with the Kemper IGCC was $174 million. The projected balance at March 31, 2016 is estimated to total approximately $266 million. The amortization period for any such costs approved for recovery remains subject to approval by the Mississippi PSC.

The 2013 MPSC Rate Order approved 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. On February 12, 2015, the Court ordered the Mississippi PSC to refund Mirror CWIP and to fix by order the rates that were in existence prior to the 2013 MPSC Rate Order. Mississippi Power is deferring the collections under the approved rates in the Mirror CWIP regulatory liability until otherwise directed by the Mississippi PSC. Mississippi Power is also accruing carrying costs on the unamortized balance of the Mirror CWIP regulatory liability for the benefit of retail customers. As of March 31, 2015, the balance of the Mirror CWIP regulatory liability, including carrying costs, was $311 million.

See "2015 Mississippi Supreme Court Decision" herein for additional information.

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

Lignite Mine and CO₂ Pipeline Facilities

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

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

In addition, Mississippi Power has constructed and will operate the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery. Mississippi Power has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop will purchase 30% of the CO₂ captured from the Kemper IGCC. The agreements with Denbury and Treetop provide termination rights in the event that Mississippi Power does not satisfy its contractual obligation with respect to deliveries of captured CO₂ by May 11, 2015. While Mississippi Power has received no indication from either Denbury or Treetop of their intent to terminate their respective agreements, any termination or material modification of these agreements could result in a material reduction in future chemical product sales revenues and could have a material financial impact on Mississippi Power to the extent Mississippi Power is not able to enter into other similar contractual arrangements.

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

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Proposed Sale of Undivided Interest to SMEPA

In 2010, Mississippi Power and SMEPA entered into an asset purchase agreement (APA) whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In 2012, the Mississippi PSC approved the sale and transfer of the 17.5% undivided interest in the Kemper IGCC to SMEPA. Later in 2012, Mississippi Power and SMEPA signed an amendment to the APA whereby SMEPA reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC. In March 2013, Mississippi Power and SMEPA signed an amendment to the APA whereby they agreed to amend a 2011 power supply agreement between the parties to reduce the capacity amounts to be received by SMEPA by half (approximately 75 MWs) at the sale and transfer of the undivided interest in the Kemper IGCC to SMEPA. Capacity revenues under the 2011 power supply agreement were $4 million in the first quarter 2015 and $17 million in 2014.

By letter agreement dated October 6, 2014, Mississippi Power and SMEPA agreed in principle on certain issues related to SMEPA's proposed purchase of a 15% undivided interest in the Kemper IGCC. The parties agreed to further amend the APA as follows: (1) Mississippi Power agreed to cap at $2.88 billion the portion of the purchase price payable for development and construction costs, net of the Cost Cap Exceptions, title insurance reimbursement, and AFUDC and/or carrying costs through the Closing Commitment Date (defined below); (2) SMEPA agreed to close the purchase within 180 days after the date of the execution of the amended APA or before the Kemper IGCC in-service date, whichever occurs first (Closing Commitment Date), subject only to satisfaction of certain conditions; and (3) AFUDC and/or carrying costs will continue to be accrued on the capped development and construction costs, the Cost Cap Exceptions, and any operating costs, net of revenues until the amended APA is executed by both parties, and thereafter AFUDC and/or carrying costs and payment of interest on SMEPA's deposited money will be suspended and waived provided closing occurs by the Closing Commitment Date. The letter agreement also provided for certain post-closing adjustments to address any differences between the actual and the estimated amounts of post-in-service date costs (both expenses and capital) and revenue credits for those portions of the Kemper IGCC previously placed in service.

By letter dated December 18, 2014, SMEPA notified Mississippi Power that SMEPA decided not to extend the December 31, 2014 estimated closing date in the APA or revise the APA to include the contemplated amendments; however, both parties agree that the APA will remain in effect until closing or until either party gives notice of termination.

The closing of this transaction is also conditioned upon execution of a joint ownership and operating agreement, the absence of material adverse effects, receipt of all construction permits, and appropriate regulatory approvals, as well as SMEPA's receipt of Rural Utilities Service (RUS) funding. In 2012, SMEPA received a conditional loan commitment from RUS for the purchase.

In 2012, in January 2014, and in October 2014, Mississippi Power received $150 million, $75 million, and $50 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied to the purchase. While the expectation is that these amounts will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposits upon the termination of the APA or within 15 days of a request by SMEPA for a full or partial refund. Accordingly, the deposits have been presented as a current liability in the balance sheet and as financing proceeds in the statement of cash flow. Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any refund of the deposits to SMEPA.

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

Income Tax Matters

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

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Section 174 Research and Experimental Deduction

Southern Company, on behalf of Mississippi Power, reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. Due to the uncertainty related to this tax position, Mississippi Power had unrecognized tax benefits totaling approximately $211 million at March 31, 2015. See Note 5 to the financial statements of Mississippi Power under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" and "Unrecognized Tax Benefits," respectively, herein for additional information. The ultimate outcome of this tax matter cannot be determined at this time.

Other Matters

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

The ultimate outcome of such pending or potential litigation against Mississippi Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Mississippi Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Mississippi Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

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, Contingent Obligations, Unbilled Revenues, Pension and Other Postretirement Benefits, and AFUDC.

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

During 2015, 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 DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery or any joint owner contributions for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the 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 $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

106

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 $2.06 billion ($1.27 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through March 31, 2015.

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 DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of operations and these changes could be material. Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).

Mississippi Power's revised cost estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 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. Any further extension of the in-service date with respect to the Kemper IGCC 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 $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting fees and legal fees which are being deferred as regulatory assets and are estimated to total approximately $6 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 MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board (FASB) issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition. On April 29, 2015, the FASB issued an exposure draft proposing the standard be effective for fiscal years beginning after December 15, 2017. Mississippi Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

On April 7, 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Mississippi Power currently reflects unamortized debt issuance costs in other deferred charges and assets on its balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Mississippi Power.

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Earnings for the three months ended March 31, 2015 and 2014 were negatively affected by revisions to the cost estimate for the Kemper IGCC and the Court's decision to reverse the 2013 MPSC Rate Order; however, Mississippi Power's financial condition remained stable as a result of the financing activities described herein. Mississippi Power's cash requirements primarily consist of funding debt maturities, including $900 million maturing April 1, 2016, ongoing operations and capital expenditures, as well as the potential requirement to refund amounts collected under the 2013 MPSC Rate Order and associated carrying costs ($311 million through March 31, 2015) and the SMEPA deposits ($275 million at March 31, 2015). See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Proposed Sale of Undivided Interest to SMEPA" and "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" and " – 2015 Mississippi Supreme Court Decision" herein for additional information. For the three-year period from 2015 through 2017, 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, including the Plant Daniel scrubber project, to add environmental equipment for existing generating units, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities. See "Sources of Capital" herein for additional information.

Through March 31, 2015, Mississippi Power has incurred non-recoverable cash expenditures of $1.49 billion and is expected to incur approximately $567 million in additional non-recoverable cash expenditures through completion of the Kemper IGCC.

During the first three months of 2015, Mississippi Power received $75 million in equity contributions from Southern Company. Subsequent to March 31, 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. Mississippi Power intends to utilize operating cash flows and lines of credit, bank term loans, and commercial paper, as market conditions permit, as well as, under certain circumstances, equity contributions and/or loans from Southern Company, to fund Mississippi Power's short-term capital needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $204 million for the first three months of 2015, an increase of $172 million as compared to the corresponding period in 2014. The increase in cash provided from operating activities is primarily due to R&E tax deductions and bonus depreciation reducing tax payments, an increase in fuel recovery, and Mirror CWIP, net of the Kemper IGCC regulatory deferral, partially offset by the timing of payments for accounts payable and fuel purchases. See Notes (B) and Note (G) to the Condensed Financial Statements herein for additional information. Net cash used for investing activities totaled $233 million for the first three months of 2015 primarily due to gross property additions related to the Kemper IGCC and the Plant Daniel scrubber project. Net cash provided from financing activities totaled $30 million for the first three months of 2015 primarily due to capital contributions from Southern Company and short-term borrowings, partially offset by redemptions of long-term debt. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2015 include a decrease in securities due within one year of $775 million and an increase in long-term debt of $698 million, primarily due to refinancing or replacing maturing debt. See "Sources of Capital" herein for additional information. Total property, plant, and equipment

108

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

increased $197 million, other regulatory assets, deferred increased $34 million, and the Mirror CWIP regulatory liability increased $40 million primarily due to the Kemper IGCC. See "Integrated Coal Gasification Combined Cycle" herein for additional information. Additional changes included a decrease in prepaid income taxes of $29 million, a decrease in other accrued taxes of $55 million primarily due to ad valorem tax payments, and increases in accumulated deferred income taxes, a portion of which is reflected in other deferred charges and assets, and accrued income taxes of $95 million and $43 million, respectively, primarily due to R&E tax deductions and the related reserve. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" and Note (G) to the Condensed Financial Statements herein for additional information. Total common stockholder's equity increased $113 million primarily due to the receipt of $75 million in capital contributions from Southern Company and due to net income for the quarter.

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. Mississippi Power has no long-term debt maturing at or prior to March 31, 2016. Approximately $900 million in bank term loans are scheduled to mature on April 1, 2016. See "Sources of Capital" 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 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

Except as described herein, Mississippi Power plans to obtain the funds required for construction and other purposes from operating cash flows, security issuances, term loans, and/or short-term debt, as well as, under certain circumstances, equity contributions and/or loans from Southern Company. Operating cash flows would be adversely impacted by $156 million annually with the removal of rates implemented under the 2013 MPSC Rate Order. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which may include 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 Mississippi Supreme Court Decision" of Mississippi Power in Item 7 of the Form 10-K and herein for additional information.

Mississippi Power received $245 million of DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of DOE Grants is expected to be received for commercial operation of the Kemper IGCC. 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.

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

As of March 31, 2015, Mississippi Power's current liabilities exceeded current assets by approximately $578 million primarily due to refundable deposits from SMEPA and the potential Mirror CWIP refund. Subsequent to March 31, 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016. Mississippi Power intends to utilize operating cash flows and lines of credit, bank term loans, and commercial paper, as market conditions permit, as well as, under certain circumstances, equity contributions and/or loans from Southern Company, to fund Mississippi Power's short-term capital needs.

At March 31, 2015, Mississippi Power had approximately $134 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2015 were as follows:

Expires								Executable Term Loans				Due Within One Year
2015		2016		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)				(in millions)				(in millions)				(in millions)
$	135	$	165	$	300	$	270	$	25	$	40	$	65	$	235

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 contain covenants that limit debt levels and typically contain 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 specified threshold. Mississippi Power is currently 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 renew or replace its credit arrangements, as needed prior to expiration.

A portion of the $270 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's variable rate pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2015 was approximately $40 million.

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

110

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of short-term borrowings were as follows:

	Short-term Debt at March 31, 2015			Short-term Debt During the Period(*)
	Amount Outstanding		Weighted Average Interest Rate	Average Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
Short-term bank debt	$	30	1.2%	$	7	1.2%	$	30

(*)    Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2015.

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 could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- and/or Baa3. These contracts are for physical electricity sales, fuel transportation and storage, and energy price risk management. At March 31, 2015, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 equaled approximately $281 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, any credit rating downgrade could impact Mississippi Power's ability to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.

Financing Activities

In March 2015, Mississippi Power repaid at maturity a $75 million bank term loan.

Subsequent to March 31, 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes, including Mississippi Power's ongoing construction program. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.

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

111

SOUTHERN POWER COMPANY

AND SUBSIDIARY COMPANIES

112

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2015			2014
	(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	232		$	278
Wholesale revenues, affiliates	114			72
Other revenues	2			1
Total operating revenues	348			351
Operating Expenses:
Fuel	138			125
Purchased power, non-affiliates	16			28
Purchased power, affiliates	10			29
Other operations and maintenance	52			53
Depreciation and amortization	59			51
Taxes other than income taxes	6			6
Total operating expenses	281			292
Operating Income	67			59
Other Income and (Expense):
Interest expense, net of amounts capitalized	(22		)	(22		)
Earnings Before Income Taxes	45			37
Income taxes	12			3
Net Income	33			34
Less: Net income attributable to noncontrolling interests	—			1
Net Income Attributable to Southern Power Company	$	33		$	33

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2015		2014
	(in millions)
Net Income	$	33	$	34
Other comprehensive income (loss)	—		—
Less: Comprehensive income attributable to noncontrolling interests	—		1
Comprehensive Income Attributable to Southern Power Company	$	33	$	33

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

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended March 31,
	2015			2014
	(in millions)
Operating Activities:
Net income	$	33		$	34
Adjustments to reconcile net income to net cash provided from (used for) operating activities —
Depreciation and amortization, total	60			53
Deferred income taxes	(54		)	(14		)
Investment tax credits	—			26
Amortization of investment tax credits	(4		)	(2		)
Deferred revenues	(20		)	(20		)
Other, net	3			3
Changes in certain current assets and liabilities —
-Receivables	2			21
-Fossil fuel stock	6			2
-Prepaid income taxes	(2		)	15
-Other current assets	—			(1		)
-Accounts payable	(25		)	2
-Accrued taxes	(4		)	6
-Accrued interest	(15		)	(15		)
-Other current liabilities	1			—
Net cash provided from (used for) operating activities	(19		)	110
Investing Activities:
Property additions	(38		)	(5		)
Change in construction payables	17			1
Payments pursuant to long-term service agreements	(16		)	(10		)
Other investing activities	(1		)	(1		)
Net cash used for investing activities	(38		)	(15		)
Financing Activities:
Increase in notes payable, net	38			—
Payment of common stock dividends	(33		)	(33		)
Other financing activities	—			(2		)
Net cash provided from (used for) financing activities	5			(35		)
Net Change in Cash and Cash Equivalents	(52		)	60
Cash and Cash Equivalents at Beginning of Period	75			69
Cash and Cash Equivalents at End of Period	$	23		$	129
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $- and $- capitalized for 2015 and 2014, respectively)	$	36		$	36
Income taxes, net	79			(44		)
Noncash transactions — Accrued property additions at end of period	16			5

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

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2015		At December 31, 2014
	(in millions)
Current Assets:
Cash and cash equivalents	$	23	$	75
Receivables —
Customer accounts receivable	71		77
Other accounts receivable	14		15
Affiliated companies	37		34
Fossil fuel stock, at average cost	16		22
Materials and supplies, at average cost	59		58
Prepaid service agreements — current	10		8
Prepaid income taxes	21		19
Deferred income taxes, current	379		306
Other prepaid expenses	10		8
Assets from risk management activities	—		5
Total current assets	640		627
Property, Plant, and Equipment:
In service	5,658		5,657
Less accumulated provision for depreciation	1,093		1,035
Plant in service, net of depreciation	4,565		4,622
Construction work in progress	48		11
Total property, plant, and equipment	4,613		4,633
Other Property and Investments:
Goodwill	2		2
Other intangible assets, net of amortization of $9 and $8 at March 31, 2015 and December 31, 2014, respectively	46		47
Total other property and investments	48		49
Deferred Charges and Other Assets:
Prepaid long-term service agreements	137		124
Other deferred charges and assets — affiliated	13		5
Other deferred charges and assets — non-affiliated	113		112
Total deferred charges and other assets	263		241
Total Assets	$	5,564	$	5,550

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

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At March 31, 2015		At December 31, 2014
	(in millions)
Current Liabilities:
Securities due within one year	$	525	$	525
Notes payable	233		195
Accounts payable —
Affiliated	69		78
Other	32		30
Accrued income taxes	65		72
Accrued interest	15		30
Other current liabilities	19		17
Total current liabilities	958		947
Long-term Debt	1,095		1,095
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	882		863
Accumulated deferred investment tax credits	596		601
Deferred capacity revenues — affiliated	5		15
Other deferred credits and liabilities — affiliated	—		1
Other deferred credits and liabilities — non-affiliated	16		18
Total deferred credits and other liabilities	1,499		1,498
Total Liabilities	3,552		3,540
Redeemable Noncontrolling Interest	40		39
Common Stockholder's Equity:
Common stock, par value $.01 per share —
Authorized — 1,000,000 shares
Outstanding — 1,000 shares	—		—
Paid-in capital	1,176		1,176
Retained earnings	574		573
Accumulated other comprehensive income	3		3
Total common stockholder's equity	1,753		1,752
Noncontrolling Interest	219		219
Total Stockholders' Equity	1,972		1,971
Total Liabilities and Stockholders' Equity	$	5,564	$	5,550

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

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FIRST QUARTER 2015 vs. FIRST QUARTER 2014

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 primarily with investor owned utilities, independent power producers, municipalities, and electric cooperatives. In general, Southern Power has constructed or acquired new generating capacity only after entering into long-term PPAs for the new facilities.

During the first quarter 2015, Southern Power entered into agreements to acquire an approximately 299-MW wind facility located in Oklahoma, and approximately 199 MWs of additional solar facilities: the Decatur County and Butler Solar Projects, both located in Georgia. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.

To evaluate operating results and to ensure Southern Power's ability to meet its contractual commitments to customers, Southern Power focuses on several key performance indicators, including peak season equivalent forced outage rate (Peak Season EFOR), contract availability, and net income. Peak Season EFOR defines the hours during peak demand times when Southern Power's generating units are not available due to forced outages (a low metric is optimal). Contract availability measures the percentage of scheduled hours delivered. Net income is the primary measure of Southern Power's financial performance.

RESULTS OF OPERATIONS

Net Income

Net income attributable to Southern Power for the first quarter 2015 and 2014 was $33 million. Increases in depreciation and income taxes were offset by a decrease in purchased power expenses.

Wholesale Revenues–Non-Affiliates

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(46)	(16.5)

Wholesale revenues from sales to non-affiliates will vary depending on the energy demand of those customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Increases and decreases in revenues 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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Details of the changes in wholesale revenues from non-affiliates were as follows:

	First Quarter  2015
	(in millions)			(% change)
Wholesale Revenues – Non-Affiliates, prior year	$	278
Change resulting from -
Capacity	(7		)	(2.5	)
Energy	(39		)	(14.0	)
Wholesale Revenues – Non-Affiliates, current year	$	232		(16.5	)%

The decrease in capacity was primarily the result of contract expirations. The decrease in energy revenues reflects a 20.8% decrease in the average price of energy and a 20.0% decrease in non-affiliate KWH sales for the first quarter 2015. This was primarily due to lower fuel revenues, reduced load, and contract expirations, partially offset by an increase in energy revenues from new solar PPAs.

Wholesale Revenues–Affiliates

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$42	58.3

Wholesale revenues from sales to affiliate companies will vary depending on demand and the availability and cost of generating resources at each company. Sales to affiliate companies that are not covered by PPAs are made in accordance with the IIC, as approved by the FERC.

Wholesale revenues from affiliates for the first quarter 2015 were $114 million compared to $72 million for the corresponding period in 2014. The increase was primarily the result of a $38 million increase in energy revenues from sales under the IIC as a result of lower natural gas prices.

Fuel and Purchased Power Expenses

	First Quarter 2015 vs. First Quarter 2014
	(change in millions)			(% change)
Fuel	$	13		10.4
Purchased power – non-affiliates	(12		)	(42.9)
Purchased power – affiliates	(19		)	(65.5)
Total fuel and purchased power expenses	$	(18	)

Southern Power PPAs for natural gas-fired generation generally provide that the purchasers are responsible for substantially all of the cost of fuel. Consequently, any increase or decrease in fuel cost is generally accompanied by an increase or decrease in related fuel revenue 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 market or sold to affiliates under the IIC.

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 Company, affiliate-owned generation, or external purchases.

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In the first quarter 2015, total fuel and purchased power expenses were $164 million compared to $182 million for the corresponding period in 2014. The decrease was the result of a $97 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas prices, partially offset by a $79 million net increase in the volume of KWHs generated and purchased primarily due to increased demand resulting from lower natural gas prices.

Fuel

In the first quarter 2015, fuel expense was $138 million compared to $125 million for the corresponding period in 2014. The increase was due to an 88.4% increase in the volume of KWHs generated primarily due to increased demand resulting from lower natural gas prices, partially offset by a 41.1% decrease in the average cost of natural gas per KWH generated.

Purchased Power

In the first quarter 2015, purchased power expense was $26 million compared to $57 million for the corresponding period in 2014. The decrease was the result of a 52.8% decrease in the volume of KWHs purchased and a 5.5% decrease in the average cost per KWH of purchased power primarily due to lower natural gas prices.

Other Operations and Maintenance Expenses

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$(1)	(1.9)

In the first quarter 2015, other operations and maintenance expenses were $52 million compared to $53 million for the corresponding period in 2014. The decrease was primarily due to a $7 million decrease as a result of lower outage costs, largely offset by a $6 million increase in expenses associated with labor, maintenance, support services, and new plants placed in service in 2014.

Depreciation and Amortization

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$8	15.7

In the first quarter 2015, depreciation and amortization was $59 million compared to $51 million for the corresponding period in 2014. The increase was primarily related to solar facilities placed in service in 2014.

Income Taxes

First Quarter 2015 vs. First Quarter 2014
(change in millions)	(% change)
$9	N/M

N/M – Not meaningful

In the first quarter 2015, income taxes were $12 million compared to $3 million for the corresponding period in 2014. The increase was primarily due to beneficial changes impacting 2014 state income taxes and higher pre-tax earnings in 2015, partially offset by increased federal income tax benefits related to ITCs in 2015.

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

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FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. The level of Southern Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power's competitive wholesale business. These factors include: Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Power's market areas; the successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its acquisition and value creation strategy, including successfully expanding investments in renewable energy projects, and to construct generating facilities, including the impact of federal ITCs.

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

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 2015, Southern Power Company acquired or contracted to acquire the following projects in accordance with its overall growth strategy, which are included in Southern Power's capital program estimates for 2015.

Kay County Wind Facility

On February 24, 2015, Southern Power Company, through its wholly-owned subsidiary Southern Renewable Energy, Inc., entered into a purchase agreement with Kay Wind Holdings, LLC, a wholly-owned subsidiary of Apex Clean Energy Holdings, LLC, the developer of the project, to acquire all of the outstanding membership interests of Kay Wind, LLC (Kay Wind) for approximately $492 million, with potential purchase price adjustments based on performance testing. Kay Wind is constructing and owns an approximately 299-MW wind facility in Kay County, Oklahoma. The wind facility is expected to begin commercial operation in late 2015, and the entire output of the facility is contracted under separate 20-year PPAs with Westar Energy, Inc. and Grand River Dam Authority. In March 2015, Kay Wind obtained the necessary financing for the construction of the facility, and the acquisition is expected to close in the fourth quarter 2015. The completion of the acquisition is subject to Kay Wind achieving certain construction and project milestones, and various other customary conditions to closing. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements of Southern Powerin Item 8 of the Form 10-K for additional information.

Lost Hills-Blackwell Solar Facilities

On April 15, 2015, Southern Power Company, through its subsidiary Southern Renewable Partnerships, LLC (SRP), acquired 100% of the class A membership interests of Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell) from a wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project, for approximately $74 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of Lost Hills Blackwell for approximately $34 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from Lost Hills Blackwell. In addition, Southern Power Company is

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

entitled to substantially all of the federal tax benefits with respect to the transaction. Lost Hills Blackwell constructed and owns the approximately 20-MW Lost Hills and the approximately 12-MW Blackwell solar facilities in Kern County, California. These solar facilities began commercial operation on April 17, 2015, and their entire output is contracted under PPAs, initially to the City of Roseville and then to Pacific Gas and Electric Company, that together extend approximately 29 years.

North Star Solar Facility

On April 30, 2015, Southern Power Company, through its subsidiary SRP, acquired 100% of the class A membership interests of NS Solar Holdings, LLC (North Star) from a wholly-owned subsidiary of First Solar, the developer of the project, for approximately $208 million.Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of North Star for approximately $99 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from North Star. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. North Star is constructing and owns the approximately 60-MW North Star solar facility in Fresno County, California, which is expected to begin commercial operation in June 2015. The entire output of the project is contracted under a 20-year PPA with Pacific Gas and Electric Company. The ultimate outcome of this matter cannot be determined at this time.

Construction Projects

During 2015, Southern Power Company commenced or plans to commence the following construction projects in accordance with its overall growth strategy, which are included in Southern Power's capital program estimates for 2015. The ultimate outcome of these matters cannot be determined at this time.

Decatur County Solar Projects

On February 19, 2015, Southern Power Company acquired all of the outstanding membership interests of Decatur Parkway Solar Project, LLC and Decatur County Solar Project, LLC from TradeWind Energy, Inc. as part of Southern Power's plans to build two solar photovoltaic facilities: the Decatur Parkway Solar Project and the Decatur County Solar Project. These two projects, approximately 80 MWs and 19 MWs, respectively, will be constructed on separate sites in Decatur County, Georgia. Construction of the Decatur Parkway Solar Project commenced in February 2015, while construction of the Decatur County Solar Project is expected to commence in June 2015. Both projects are expected to begin commercial operation in late 2015, and the entire output of each project is contracted to Georgia Power. The Decatur Parkway Solar Project is contracted under a 25-year PPA and the Decatur County Solar Project is contracted under a separate 20-year PPA. Construction costs incurred through March 31, 2015 were $32 million. The total estimated cost of the facilities is expected to be between $200 million and $220 million, which includes the acquisition price for all of the outstanding membership interests of Decatur Parkway Solar Project, LLC and Decatur County Solar Project, LLC from TradeWind Energy, Inc.

Butler Solar Project

On March 12, 2015, Southern Power Company entered into a purchase agreement with CERSM, LLC and Community Energy, Inc. to acquire all of the outstanding membership interests of Butler Solar LLC as part of Southern Power's plans to build an approximately 100-MW solar photovoltaic facility in Taylor County, Georgia. Construction of the project is expected to commence in July 2015, with commercial operation expected to begin in December 2016. The entire output of the project is contracted to Georgia Power under a 30-year PPA. The total estimated cost of the facility is expected to be between $220 million and $230 million, which includes the acquisition price for all of the outstanding membership interests of Butler Solar LLC from CERSM, LLC and Community Energy, Inc. The acquisition is expected to close later in May 2015, and is subject to customary conditions to closing.

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Pawpaw Solar Project

On April 22, 2015, Southern Power Company entered into a purchase agreement with Longview Solar, LLC to acquire all of the outstanding membership interests of LS – Pawpaw, LLC as part of Southern Power's plans to build an approximately 30-MW solar photovoltaic facility in Taylor County, Georgia. Construction of the project is expected to commence in June 2015, with commercial operation expected to begin in December 2015. The entire output of the project is contracted to Georgia Power under a 30-year PPA. The total estimated cost of the facility is expected to be between $65 million and $75 million, which includes the acquisition price for all of the outstanding membership interests of LS – Pawpaw, LLC from Longview Solar, LLC. Theacquisitionis expected to close later in May 2015, and is subject to customary conditions to closing.

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 with investor-owned utilities, independent power purchasers, municipalities, and electric cooperatives.

Taking into account the PPAs and capacity from the acquisitions and construction projects discussed herein, together with various new PPAs relating to Southern Power's existing fleet, the coverage ratio of its available capacity for the next five years and the next 10 years has not changed materially as of March 31, 2015 from the period ended December 31, 2014.

FERC Matters

Southern Power has 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 operating companies and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional 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 operating companies and in some adjacent areas. To retain market-based rate authority, the FERC has directed the traditional operating companies and Southern Power, within 60 days, 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. Southern Power is evaluating the order. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

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

The ultimate outcome of such pending or potential litigation against Southern Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein or in Note 3 to the financial statements of Southern Power in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on 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

In May 2014, the Financial Accounting Standards Board (FASB) issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition. On April 29, 2015, the FASB issued an exposure draft proposing the standard be effective for fiscal years beginning after December 15, 2017. Southern Power continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

On February 18, 2015, the FASB issued Accounting Standards Update (ASU) 2015-02, Amendments to the Consolidation Analysis, which makes certain changes to both the variable interest model and the voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. This ASU is effective for fiscal years beginning after December 15, 2015. Southern Power is currently evaluating these requirements. The ultimate impact of this ASU has not yet been determined.

On April 7, 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Power currently reflects unamortized debt issuance costs in other deferred charges and assets – non-affiliated on its balance sheet. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of Southern Power.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power's financial condition remained stable at March 31, 2015. 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 used for operating activities totaled $19 million for the first three months of 2015, a change of $129 million as compared to $110 million of net cash provided from operating activities for the first three months of 2014. The decrease in cash provided from operating activities was primarily due to an increase in unutilized federal ITCs created during the 2014 tax year that were repaid in the first three months of 2015 primarily due to bonus depreciation, as well as a reduction in accounts payable. The federal ITCs carried forward are expected to be utilized during the 2015 tax year. Net cash used for investing activities totaled $38 million for the first three months of 2015 primarily due to expenditures related to the construction of new solar facilities and payments pursuant to long-term service agreements. Net cash provided from financing activities totaled $5 million for the first three months of 2015 primarily due to the issuance of commercial paper, partially offset by the payment of common stock dividends. Fluctuations in cash flow from financing activities vary year to year based on capital needs and the

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maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2015 include a $37 million increase in CWIP primarily due to the construction of the Decatur County solar projects. Other significant changes include a $54 million change in accumulated deferred income taxes, net of current deferred income tax items, primarily as a result of the timing and amount of ITCs utilized, partially offset by property related changes. Southern Power Company's notes payable for commercial paper increased by $38 million.

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, purchase commitments, and unrecognized tax benefits. Approximately $525 million will be required to fund maturities of long-term debt due July 15, 2015. There are no other scheduled maturities of long-term debt through March 31, 2016.

The capital program is subject to periodic review and revision. These amounts include estimates for potential plant acquisitions and new construction as well as ongoing capital improvements and work to be performed under long-term service agreements. 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 be approximately $1.4 billion for 2015, which includes approximately $1.3 billion for acquisitions and/or construction of new generating facilities. See Note (I) to the Condensed Financial Statements herein for additional information. Actual capital costs may vary from these estimates because of changes in factors such as: business conditions; environmental statutes and regulations; FERC rules and regulations; load projections; legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital.

Sources of Capital

Southern 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, 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 March 31, 2015, Southern Power's current liabilities exceeded current assets by $318 million due to the long-term debt maturing in 2015 and the use of short-term debt as a funding source, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. In 2015, Southern Power expects to utilize the capital markets and commercial paper markets as the source of funds for the majority of its maturities.

To meet liquidity and capital resource requirements, Southern Power had at March 31, 2015 cash and cash equivalents of approximately $23 million and Southern Power Company had a committed credit facility of $500 million (Facility) expiring in 2018, of which $488 million is unused.

The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65% and contains a cross default provision that is restricted only to the indebtedness of Southern Power. Southern Power Company is currently in compliance with all covenants in the Facility.

Proceeds from this Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. 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.

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Southern Power Company's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes.

Details of short-term borrowings were as follows:

	Commercial Paper at the End of the Period				Commercial Paper During the Period(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
March 31, 2015:	$	233	0.6	%	$	156	0.5	%	$	234

(*) Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2015.

Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, 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. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management.

The maximum potential collateral requirements under these contracts at March 31, 2015 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and Baa2	$	9
At BBB- and/or Baa3	310
Below BBB- and/or Baa3	1,077

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, any credit rating downgrade could impact Southern Power's ability to access capital markets, particularly the short-term debt market.

In addition, Southern Power has a PPA that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power Company'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

Southern Power did not issue or redeem any securities during the three months ended March 31, 2015.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Power Company 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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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	127
B	Contingencies and Regulatory Matters	128
C	Fair Value Measurements	146
D	Stockholders' Equity	151
E	Financing	153
F	Retirement Benefits	155
G	Effective Tax Rate and Unrecognized Tax Benefits	157
H	Derivatives	157
I	Acquisitions	166
J	Segment and Related Information	169

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, 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, 2014 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 three-month periods ended March 31, 2015 and 2014. 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.

On February 6, 2015, Gulf Power announced plans to retire its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) by March 31, 2016. In connection with this retirement, Gulf Power reclassified the net carrying value of these units from plant in service, net of depreciation, to other utility plant, net at March 31, 2015. Gulf Power expects to recover through its rates the remaining book value of the retired units and certain costs associated with the retirements; however, recovery will be considered by the Florida PSC in future rate proceedings.

Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board (FASB) issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition. On April 29, 2015, the FASB issued an exposure draft proposing the standard be effective for fiscal years beginning after December 15, 2017. The registrants continue to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

On February 18, 2015, the FASB issued Accounting Standards Update (ASU) 2015-02, Amendments to the Consolidation Analysis, which makes certain changes to both the variable interest model and the voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. This ASU is effective for fiscal years beginning after December 15, 2015. Southern Power is currently evaluating these requirements. The ultimate impact of this ASU on Southern Power has not yet been determined.

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On April 7, 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Company currently reflects unamortized debt issuance costs in unamortized debt issuance expense on its balance sheet. The traditional operating companies and Southern Power currently reflect unamortized debt issuance costs in other deferred charges and assets on their balance sheets. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of any registrant.

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.

On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 14, 2015 as the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this timeand will depend on the traditional operating companies' ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges.

In the second quarter 2015, Southern Company and the traditional operating companies expect to record incremental asset retirement obligations (ARO) related to the CCR Rule in amounts currently estimated to fall within the following ranges:

	Low		High
	(in millions)
Southern Company	$	525	$	575
Alabama Power	$	330	$	350
Georgia Power	$	10	$	20
Gulf Power	$	70	$	80
Mississippi Power	$	75	$	85

(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 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.

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(UNAUDITED)

Environmental Matters

New Source Review Actions

As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Alabama Power and Georgia Power alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including units co-owned by Gulf Power and Mississippi Power. These civil actions seek penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against Georgia Power (including claims related to a unit co-owned by Gulf Power) has been administratively closed in the U.S. District Court for the Northern District of Georgia since 2001. The case against Alabama Power (including claims involving a unit co-owned by Mississippi Power) has been actively litigated in the U.S. District Court for the Northern District of Alabama, resulting in a settlement in 2006 of the alleged NSR violations at Plant Miller; voluntary dismissal of certain claims by the EPA; and a grant of summary judgment for Alabama Power on all remaining claims and dismissal of the case with prejudice in 2011. In 2013, the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment in favor of Alabama Power, and the case has been transferred back to the U.S. District Court for the Northern District of Alabama for further proceedings.

Southern Company and each traditional operating company believe each such traditional operating company complied with applicable laws and regulations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of these matters cannot be determined at this time.

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 properties. The traditional 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 March 31, 2015 was $27 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 parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional cleanup and claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites are anticipated.

Georgia Power and numerous other entities have been designated by the EPA as PRPs at the Ward Transformer Superfund site located in Raleigh, North Carolina. In 2011, the EPA issued a Unilateral Administrative Order (UAO) to Georgia Power and 22 other parties, ordering specific remedial action of certain areas at the site. Later in 2011, Georgia Power filed a response with the EPA stating it has sufficient cause to believe it is not a liable party under CERCLA. The EPA notified Georgia Power in 2011 that it is considering enforcement options against Georgia Power and other non-complying UAO recipients. If the EPA pursues enforcement actions and the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party's failure to comply with the UAO.

In addition to the EPA's action at this site, Georgia Power, along with many other parties, was sued in a private action by several existing PRPs for cost recovery related to the removal action. In 2013, the U.S. District Court for

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(UNAUDITED)

the Eastern District of North Carolina Western Division granted Georgia Power's summary judgment motion ruling that Georgia Power has no liability in the private action. On March 20, 2015, the U.S. Court of Appeals for the Fourth Circuit affirmed the lower court's ruling. The plaintiffs may seek review by the U.S. Supreme Court.

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. See Note 1 to the financial statements of Georgia Power under "Environmental Remediation Recovery" in Item 8 of the Form 10-K for additional information regarding the regulatory treatment.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $47 million as of March 31, 2015. 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.

In 2003, Mississippi Power and numerous other entities were designated by the Texas Commission on Environmental Quality (TCEQ) as PRPs at a site that was owned by an electric transformer company that handled Mississippi Power's transformers. The TCEQ approved the final site remediation plan in 2013 and, in March 2014, the impacted utilities, including Mississippi Power, agreed to commence remediation actions on the site. Mississippi Power's environmental remediation liability was $0.5 million as of March 31, 2015 and is expected to be recovered through the ECO Plan.

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, Georgia Power, Gulf Power, and Mississippi Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.

Nuclear Fuel Disposal Cost Litigation

Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.

In December 2014, the Court of Federal Claims entered a judgment in favor of Georgia Power and Alabama Power in the second spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. Georgia Power recovered approximately $18 million, based on its ownership interests, and Alabama Power recovered approximately $26 million. The judgment amounts were paid on March 19, 2015. In March 2015, Georgia Power credited the award to accounts where the original costs were charged and reduced rate base, fuel, and cost of service for the benefit of customers. The final outcome of this matter for Alabama Power cannot be determined at this time; however, no material impact on Southern Company's or Alabama Power's net income is expected as the damage amounts collected from the government are expected to be used for the benefit of customers.

In March 2014, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of March 31, 2015 for any potential recoveries from

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(UNAUDITED)

the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.

FERC Matters

Municipal and Rural Associations Tariff

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

On March 31, 2015, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC to forgo the Municipal and Rural Associations cost-based electric tariff increase reflected in the filing by, among other things, increasing the accrual of AFUDC in lieu of including CWIP in rate base. The settlement agreement, if accepted by the FERC, provides that the additional accrual of AFUDC is effective April 1, 2015. The additional resulting AFUDC is projected to be approximately $12 million annually, of which $9 million relates to the Kemper IGCC. In addition, a settlement agreement entered into in 2014 and approved by the FERC allowed for an adjustment to the wholesale revenue requirement in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. A regulatory asset account was recorded as a result of a portion of the Kemper IGCC being placed in service prior to the projected date. The March 31, 2015 settlement agreement provides that the regulatory asset will be amortized over nine months, beginning April 1, 2015. The ultimate outcome of this matter cannot be determined at this time.

Market-Based Rate Authority

The traditional 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 operating companies and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional 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 operating companies and in some adjacent areas. To retain market-based rate authority, the FERC has directed the traditional operating companies and Southern Power, within 60 days, 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 operating companies and Southern Power are evaluating the order. The ultimate outcome of this matter cannot be determined at this time.

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(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 recovery balance of each regulatory clause follows:

Regulatory Clause	Balance Sheet Line Item	March 31, 2015		December 31, 2014
		(in millions)
Rate CNP Compliance – Under*	Deferred under recovered regulatory clause revenues	$	25	$	2
	Under recovered regulatory clause revenues, current	16		47
Rate CNP PPA – Under	Deferred under recovered regulatory clause revenues	62		29
	Under recovered regulatory clause revenues, current	—		27
Retail Energy Cost Recovery – Over	Deferred over recovered regulatory clause revenues	81		47
Natural Disaster Reserve	Other regulatory liabilities, deferred	82		84

* Formerly Known As Rate CNP Environmental

Rate CNP

In March 2015, the Emerging Issues Task Force unanimously recommended to allow the normal purchases and normal sales exception for physical forward transactions in nodal energy markets. The FASB proposed new accounting guidance reflecting the recommendation on April 23, 2015. This guidance is subject to a public comment period before the FASB issues a final accounting standard. The ultimate outcome of this matter cannot be determined at this time.

Rate CNP Compliance(Formerly Known As Rate CNP Environmental)

See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" and of Alabama Power under "Retail Regulatory Matters – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" in Item 8 of the Form 10-K for additional information regarding Alabama Power's development of a revised cost recovery mechanism.

On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. Alabama Power incurred $14 million of non-environmental compliance costs during the first quarter 2015 and will be limited to recovery of $50 million for the year. Customer rates will not be impacted before January 2016; therefore, the modification will increase the under-recovered position for Rate CNP Compliance during the year.

Georgia Power

Integrated Resource Plan

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

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(UNAUDITED)

To comply with the April 16, 2015 effective date of the MATS rule, Plant Branch Units 1, 3, and 4 (1,266 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) were retired on April 15, 2015. In addition, operations were discontinued at Plant Mitchell Unit 3 (155 MWs) and its decertification will be requested in connection with the triennial Integrated Resource Plan in 2016. The switch to natural gas as the primary fuel is complete at Plant Yates Unit 7 and is underway at Plant Yates Unit 6. Plant Yates Unit 7 was returned to service on May 4, 2015 and Plant Yates Unit 6 is expected to return to service in mid-2015.

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 March 31, 2015, Georgia Power's under recovered fuel balance totaled $151 million and is included in current assets and other deferred charges and assets on Southern Company's and Georgia Power's Condensed Balance Sheets herein. As of December 31, 2014, Georgia Power's under recovered fuel balance totaled $199 million and is included in current assets and other deferred charges and assets on Southern Company's and Georgia Power's Condensed Balance Sheets herein. On January 20, 2015, the Georgia PSC approved the deferral of Georgia Power's next fuel case filing until at least June 30, 2015.

Fuel cost recovery revenues as recorded on the financial statements 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, and pending litigation.

In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement (Vogtle 3 and 4 Agreement) with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is 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. The Contractor's liability to the Vogtle Owners for schedule and performance liquidated damages and warranty claims is 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%.

Certain payment obligations of Westinghouse and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.) under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group Inc. (a subsidiary of Chicago Bridge & Iron Company, N.V.), respectively. 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. 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

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(UNAUDITED)

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 NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. 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 are expected as construction proceeds.

In 2012, the Vogtle Owners and the Contractor began negotiations regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Also in 2012, Georgia Power and the other Vogtle Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against Georgia Power and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. On March 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit affirmed the District Court's decision. The portion of additional costs claimed by the Contractor in its initial complaint that would be attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately $425 million (in 2008 dollars). The Contractor also asserted it is entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. In May 2014, the Contractor filed an amended counterclaim to the suit pending in the U.S. District Court for the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations; however, the Contractor has subsequently asserted related minimum damages (based on Georgia Power's ownership interest) of $113 million. The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these allegations, any of which could be substantial. Georgia Power has not agreed to the proposed cost or to any changes to the guaranteed substantial completion dates or that the Vogtle Owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power intends to vigorously defend the positions of the Vogtle Owners. Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule. During such negotiations the parties may reach a mutually acceptable compromise of their positions.

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 certified construction capital costs to be borne by Georgia Power increase by 5% 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. Georgia Power's eighth VCM report filed in 2013 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 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. In 2013, the Georgia PSC approved a stipulation (2013 Stipulation) entered into by Georgia Power and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. The Georgia PSC has approved eleven VCM reports covering the periods through June 30, 2014, including construction capital costs incurred, which through that date totaled $2.8 billion.

On January 29, 2015, Georgia Power announced it was notified by the Contractor of the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4, which would incrementally delay the previously disclosed estimated in-service dates by 18 months (from the fourth quarter of 2017 to the second quarter of 2019 for Unit 3 and from the fourth quarter of 2018 to the second quarter of 2020 for Unit 4).

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(UNAUDITED)

Georgia Power does not believe that the Contractor's revised forecast reflects all efforts that may be possible to mitigate the Contractor's delay. In addition, Georgia Power believes that, pursuant to the Vogtle 3 and 4 Agreement, the Contractor is responsible for the Contractor's costs related to the Contractor's delay (including any related construction and mitigation costs, which could be material) and that the Vogtle Owners are entitled to recover liquidated damages for the Contractor's delay beyond the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. Consistent with the Contractor's position in the pending litigation described above, Georgia Power expects the Contractor to contest any claims for liquidated damages and to assert that the Vogtle Owners are responsible for additional costs related to the Contractor's delay.

On February 27, 2015, Georgia Power filed its twelfth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2014, which requested approval for an additional $0.2 billion of construction capital costs incurred during that period. The twelfth VCM report also reflected the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 as well as additional estimated owner-related costs, which include approximately $10 million per month expected to result from the Contractor's proposed 18-month delay, including property taxes, oversight costs, compliance costs, and other operational readiness costs. No Contractor costs related to the Contractor's proposed 18-month delay were included in the twelfth VCM report. Additionally, while Georgia Power has not agreed to any change to the guaranteed substantial completion dates, the twelfth VCM report included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast, to include the estimated 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.

Georgia Power will continue to incur financing costs of approximately $30 million per month until Plant Vogtle Units 3 and 4 are placed in service. The twelfth VCM report estimated financing costs during the construction period to total approximately $2.5 billion.

On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report. Pursuant to this 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, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.

Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, 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 issues are expected to 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 ongoing challenges with Contractor performance including additional challenges in its fabrication, assembly, delivery, and installation of 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.

Additional claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) are also likely to arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement, but also may be resolved through litigation.

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(UNAUDITED)

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 December 2013, the Florida PSC approved a settlement agreement that provides Gulf Power may reduce depreciation expense and record a regulatory asset up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation expense reduction may not exceed the amount necessary for the ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Gulf Power recognized a $19.6 million reduction in depreciation expense in the first three months of 2015.

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 recovery balance of each regulatory clause follows:

Recovery Clause	Balance Sheet Location	March 31, 2015		December 31, 2014
		(in millions)
Fuel Cost Recovery – Under	Under recovered regulatory clause revenues	$	32	$	40
Purchased Power Capacity Recovery – Under	Under recovered regulatory clause revenues	3		—
Environmental Cost Recovery – Under	Under recovered regulatory clause revenues	12		10
Energy Conservation Cost Recovery – Under	Under recovered regulatory clause revenues	1		3

Mississippi Power

Performance Evaluation Plan

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's base rates.

On March 17, 2015, Mississippi Power submitted its annual PEP lookback filing for 2014, which indicated no surcharge or refund. On March 26, 2015, the Mississippi PSC suspended the filing to allow more time for review.

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

System Restoration Rider

See Note 1 to the financial statements of Mississippi Power under "Provision for Property Damage" in Item 8 of the Form 10-K for additional information.

On February 2, 2015, Mississippi Power submitted its 2015 System Restoration Rider (SRR) rate filing with the Mississippi PSC, which proposed that the 2015 SRR rate remain level at zero and Mississippi Power be allowed to accrue $3 million to the property damage reserve in 2015. On March 3, 2015, the Mississippi PSC suspended the filing to allow more time for review.

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

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(UNAUDITED)

Environmental Compliance Overview Plan

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for information on Mississippi Power's annual environmental filing with the Mississippi PSC.

In 2012, the Mississippi PSC approved Mississippi Power's request for a CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which are scheduled to be placed in service in September and November 2015, respectively. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Power's portion being $330 million, excluding AFUDC. Mississippi Power's portion of the cost is expected to be recovered through the ECO Plan following the scheduled completion of the project in December 2015. As of March 31, 2015, total project expenditures were $570 million, of which Mississippi Power's portion was $290 million, excluding AFUDC of $22 million.

On February 25, 2015, Mississippi Power submitted its annual ECO filing for 2015, which indicated an annual increase in revenues of approximately $8 million. The filing is under review by the Mississippi PSC.

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 fuel cost recovery.

At March 31, 2015, the amount of over-recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $15 million compared to under-recovered retail fuel costs of $2 million at December 31, 2014.

Ad Valorem Tax Adjustment

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

On April 23, 2015, Mississippi Power filed its annual ad valorem tax adjustment factor filing for 2015, which requested an annual rate decrease of 0.35%, or $2 million in annual retail revenues, primarily due to a decrease in average millage rates.

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

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Kemper IGCC Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC.

The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power Initiative Round 2 (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 using natural gas in August 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, for which the in-service date is currently expected to occur in the first half of 2016. Recovery of the Kemper IGCC 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) remain 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), and actual costs incurred as of March 31, 2015, as adjusted for the Court's decision, are as follows:

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(UNAUDITED)

Cost Category	2010 Project Estimate(f)		Current Estimate		Actual Costs at March 31, 2015
	(in billions)
Plant Subject to Cost Cap(a)	$	2.40	$	4.94	$	4.37
Lignite Mine and Equipment	0.21		0.23		0.23
CO2 Pipeline Facilities	0.14		0.11		0.10
AFUDC(b)(c)	0.17		0.64		0.48
Combined Cycle and Related Assets Placed in Service – Incremental(d)	—		0.02		—
General Exceptions	0.05		0.10		0.08
Deferred Costs(c)(e)	—		0.18		0.14
Total Kemper IGCC(a)(c)	$	2.97	$	6.22	$	5.40

(a) The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and 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" for additional information.

(b) Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate includes an approximately $9 million increase in AFUDC related to a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.

(c) Amounts in the Current Estimate reflect estimated costs through March 31, 2016.

(d) Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information.

(e) The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities."

(f) The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificatedestimate for the CO₂ pipeline facilities which was approved in 2011 by the Mississippi PSC.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of March 31, 2015, $3.27 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $2.06 billion), $2 million in other property and investments, $52 million in fossil fuel stock, $35 million in materials and supplies, $174 million in other regulatory assets, $12 million in other deferred charges and assets, and $24 million in AROs in the balance sheet, with $1 million previously expensed.

Mississippi Power does not intend to seek any rate recovery or joint owner contributions for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $9 million ($6 million after tax) in the first quarter 2015. This amount is in addition to charges totaling $868 million ($536 million after tax), $1.10 billion ($681 million after tax), and $78 million ($48 million after tax) in 2014, 2013, and 2012, respectively. Southern Company recorded pre-tax charges to income for revisions to the cost estimate of $868 million ($536 million after tax) and $1.2 billion ($729 million after tax) in 2014 and 2013, respectively. The increases to the cost estimate in the first quarter 2015 primarily reflected costs related to additional labor costs in support of start-up and operational readiness activities. The current estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 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. Any further extension of the in-service date with respect to the Kemper IGCC 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 $13 million per month, as well as carrying

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(UNAUDITED)

costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees, which are being deferred as regulatory assets and are estimated to total approximately $6 million per month.

Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). 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 DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and Mississippi Power's statements of operations and these changes could be material.

Rate Recovery of Kemper IGCC Costs

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 the evaluation of the Rate Mitigation Plan (defined below) and any alternative 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 Settlement Agreement

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, established 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. The 2013 Settlement Agreement also allowed Mississippi Power to secure alternate financing for costs not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. The Court found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. See "2015 Mississippi Supreme Court Decision" herein for additional information.

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's intent under the 2013 Settlement Agreement was to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs, which include carrying costs from the estimated in-service date until securitization is finalized and other costs not included in the Rate Mitigation Plan as

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

approved by the Mississippi PSC. The Court's decision did not impact Mississippi Power's ability to utilize alternate financing through securitization, the 2012 MPSC CPCN Order, or the February 2013 legislation. See "2015 Mississippi Supreme Court Decision" herein for additional information.

2013 MPSC Rate Order

Consistent with the terms of the 2013 Settlement Agreement, 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). For the period from March 2013 through March 31, 2015, $294 million had been collected primarily to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service. Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. 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. Mississippi Power will continue to record AFUDC and collect and defer the approved rates through the in-service date until directed to do otherwise by the Mississippi PSC.

In August 2014, Mississippi Power provided an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment. Mississippi Power's analysis requested, among other things, confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued collection of rates as prescribed by the 2013 MPSC Rate Order, with the current recognition as revenue of the related equity return on all assets placed in service and the deferral of all remaining rate collections under the 2013 MPSC Rate Order to a regulatory liability account. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which would discontinue the collection of, and require the refund of, all amounts previously collected under the 2013 MPSC Rate Order.

In addition, Mississippi Power's August 2014 filing with the Mississippi PSC requested confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC and the deferral of operating costs for the combined cycle as regulatory assets. Under Mississippi Power's proposal, non-incremental costs that would have been incurred whether or not the combined cycle was placed in service would be included in a regulatory asset and would continue to be subject tothe $2.88 billion cost cap. Additionally, incremental costs that would not have been incurred if the combined cycle had not gone into service would be included in a regulatory asset and would not be subject to the cost cap because these costs are incurred to support operation of the combined cycle. All energy revenues associated with the combined cycle variable operating and maintenance expenses would be credited to this regulatory asset. See "Regulatory Assets and Liabilities" for additional information. Any action by the Mississippi PSC that is inconsistent with the treatment requested by Mississippi Power could have a material impact on the results of operations, financial condition, and liquidity of Southern Company and Mississippi Power.

2015 Mississippi Supreme Court Decision

On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order filed by Thomas A. Blanton. 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. The Court's ruling remands the matter to the Mississippi PSC to (1) fix by order the rates that were in existence prior to the 2013 MPSC Rate Order, (2) fix no rate increases until the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts collected under the 2013 MPSC Rate Order. Through March 31, 2015, Mississippi Power had collected $294 million through rates under the 2013 MPSC Rate Order. Any required refunds would also include carrying costs. The Court's decision will become legally effective upon the issuance of a mandate to the Mississippi PSC. Absent specific instruction from the Court, the

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(UNAUDITED)

Mississippi PSC will determine the method and timing of the refund. On March 12, 2015, Mississippi Power and the Mississippi PSC filed motions for rehearing. If the Court denies the motions, it would issue the mandate to the Mississippi PSC no later than seven days following such decision.

Rate Mitigation Plan

In 2013, Mississippi Power, in compliance with the 2013 MPSC Rate Order, filed a revision to the proposed rate recovery plan with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020 (Rate Mitigation Plan), which is still under review by the Mississippi PSC. The revenue requirements set forth in the Rate Mitigation Plan assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation, which currently requires that the related long-term asset be placed in service in 2015.In the Rate Mitigation Plan, Mississippi Power proposed recovery of an annual revenue requirement of approximately $156 million of Kemper IGCC-related operational costs and rate base amounts, including plant costs equal to the $2.4 billion certificated cost estimate. The 2013 MPSC Rate Order, which increased rates beginning in March 2013, was integral to the Rate Mitigation Plan, which contemplates amortization of the regulatory liability balance at the in-service date to be used to mitigate customer rate impacts through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Rate Mitigation Plan, Mississippi Power proposed annual rate recovery to remain the same from 2014 through 2020, with the proposed revenue requirement approximating the forecasted cost of service for the period 2014 through 2020. Under Mississippi Power's proposal, to the extent the actual annual cost of service differs from the approved forecast for certain items, the difference would be deferred as a regulatory asset or liability, subject to accrual of carrying costs, and would be included in the next year's rate recovery calculation. If any deferred balance remains at the end of 2020, the Mississippi PSC would review the amount and, if approved, determine the appropriate method and period of disposition. See "Regulatory Assets and Liabilities" herein for additional information.

To the extent that refunds of amounts collected under the 2013 MPSC Rate Order are required on a schedule different from the amortization schedule proposed in the Rate Mitigation Plan, the customer billing impacts proposed under the Rate Mitigation Plan would no longer be viable. See "2015 Mississippi Supreme Court Decision" herein for additional information.

In addition to current estimated costs at March 31, 2015 of $6.22 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.

Mississippi Power also expects to seek rate recovery through alternate means, which could include a traditional rate case. On May 1, 2015, Mississippi Power notified the Mississippi PSC of its plans to file a rate request in May 2015.

Prudence Reviews

The Mississippi PSC's review of Kemper IGCC costs is ongoing. In August 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the Mississippi Public Utilities Staff (MPUS). The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues and Mississippi Power is working to reach a mutually acceptable resolution. As a result of the Court's decision, Mississippi Power intends to request that the Mississippi PSC reconsider its prudence review schedule. See "2015 Mississippi Supreme Court Decision" herein for additional information.

Regulatory Assets and Liabilities

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

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(UNAUDITED)

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. As of March 31, 2015, the regulatory asset balance associated with the Kemper IGCC was $174 million. The projected balance at March 31, 2016 is estimated to total approximately $266 million. The amortization period for any such costs approved for recovery remains subject to approval by the Mississippi PSC.

The 2013 MPSC Rate Order approved 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. On February 12, 2015, the Court ordered the Mississippi PSC to refund Mirror CWIP and to fix by order the rates that were in existence prior to the 2013 MPSC Rate Order. Mississippi Power is deferring the collections under the approved rates in the Mirror CWIP regulatory liability until otherwise directed by the Mississippi PSC. Mississippi Power is also accruing carrying costs on the unamortized balance of the Mirror CWIP regulatory liability for the benefit of retail customers. As of March 31, 2015, the balance of the Mirror CWIP regulatory liability, including carrying costs, was $311 million.

See "2015 Mississippi Supreme Court Decision" herein for additional information.

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

Lignite Mine and CO₂ Pipeline Facilities

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

In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managing the mining operations. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See 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 has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop will purchase 30% of the CO₂ captured from the Kemper IGCC. The agreements with Denbury and Treetop provide termination rights in the event that Mississippi Power does not satisfy its contractual obligation with respect to deliveries of captured CO₂ by May 11, 2015. While Mississippi Power has received no indication from either Denbury or Treetop of their intent to terminate their respective agreements, any termination or material modification of these agreements could result in a material reduction in future chemical product sales revenues and could have a material financial impact on Mississippi Power to the extent Mississippi Power is not able to enter into other similar contractual arrangements.

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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Proposed Sale of Undivided Interest to SMEPA

In 2010, Mississippi Power and SMEPA entered into an asset purchase agreement (APA) whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In 2012, the Mississippi PSC approved the sale and transfer of the 17.5% undivided interest in the Kemper IGCC to SMEPA. Later in 2012, Mississippi Power and SMEPA signed an amendment to the APA whereby SMEPA reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC. In March 2013, Mississippi Power and SMEPA signed an amendment to the APA whereby they agreed to amend a 2011 power supply agreement between the parties to reduce the capacity amounts to be received by SMEPA by half (approximately 75 MWs) at the sale and transfer of the undivided interest in the Kemper IGCC to SMEPA. Capacity revenues under the 2011 power supply agreement were $4 million in the first quarter 2015 and $17 million in 2014.

By letter agreement dated October 6, 2014, Mississippi Power and SMEPA agreed in principle on certain issues related to SMEPA's proposed purchase of a 15% undivided interest in the Kemper IGCC. The parties agreed to further amend the APA as follows: (1) Mississippi Power agreed to cap at $2.88 billion the portion of the purchase price payable for development and construction costs, net of the Cost Cap Exceptions, title insurance reimbursement, and AFUDC and/or carrying costs through the Closing Commitment Date (defined below); (2) SMEPA agreed to close the purchase within 180 days after the date of the execution of the amended APA or before the Kemper IGCC in-service date, whichever occurs first (Closing Commitment Date), subject only to satisfaction of certain conditions; and (3) AFUDC and/or carrying costs will continue to be accrued on the capped development and construction costs, the Cost Cap Exceptions, and any operating costs, net of revenues until the amended APA is executed by both parties, and thereafter AFUDC and/or carrying costs and payment of interest on SMEPA's deposited money will be suspended and waived provided closing occurs by the Closing Commitment Date. The letter agreement also provided for certain post-closing adjustments to address any differences between the actual and the estimated amounts of post-in-service date costs (both expenses and capital) and revenue credits for those portions of the Kemper IGCC previously placed in service.

By letter dated December 18, 2014, SMEPA notified Mississippi Power that SMEPA decided not to extend the December 31, 2014 estimated closing date in the APA or revise the APA to include the contemplated amendments; however, both parties agree that the APA will remain in effect until closing or until either party gives notice of termination.

The closing of this transaction is also conditioned upon execution of a joint ownership and operating agreement, the absence of material adverse effects, receipt of all construction permits, and appropriate regulatory approvals, as well as SMEPA's receipt of Rural Utilities Service (RUS) funding. In 2012, SMEPA received a conditional loan commitment from RUS for the purchase.

In 2012, in January 2014, and in October 2014, Mississippi Power received $150 million, $75 million, and $50 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied to the purchase. While the expectation is that these amounts will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposits upon the termination of the APA or within 15 days of a request by SMEPA for a full or partial refund. Accordingly, the deposits have been presented as a current liability in the balance sheet and as financing proceeds in the statement of cash flow. Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any refund of the deposits to SMEPA. The ultimate outcome of these matters cannot be determined at this time.

Investment Tax Credits

The IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Through March 31, 2015, Mississippi Power had recorded tax benefits totaling $276 million for the Phase II credits, of which approximately $207 million had been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%of the CO₂ produced by the

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(UNAUDITED)

Kemper IGCC during operations in accordance with the Internal Revenue Code. Mississippi Power currently expects to place the Kemper IGCC in service in the first half of 2016. In addition, a portion of the Phase II tax credits will be subject to recapture upon completion of SMEPA's proposed purchase of an undivided interest in the Kemper IGCC as described above. The ultimate outcome of this matter cannot be determined at this time.

Section 174 Research and Experimental Deduction

Southern Company, on behalf of Mississippi Power, reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. Due to the uncertainty related to this tax position, Southern Company and Mississippi Power had unrecognized tax benefits totaling approximately $211 million at March 31, 2015. See Note 5 to the financial statements of Southern Company and Mississippi Power under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Note (G) herein under "Unrecognized Tax Benefits" for additional information. The ultimate outcome of this matter cannot be determined at this time.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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(C) FAIR VALUE MEASUREMENTS

As of March 31, 2015, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:

	Fair Value Measurements Using
As of March 31, 2015:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives	$	—	$	7	$	—	$	7
Interest rate derivatives	—		8		—		8
Nuclear decommissioning trusts(a)	632		937		4		1,573
Cash equivalents	863		—		—		863
Other investments	9		—		1		10
Total	$	1,504	$	952	$	5	$	2,461
Liabilities:
Energy-related derivatives	$	—	$	225	$	—	$	225
Interest rate derivatives	—		46		—		46
Total	$	—	$	271	$	—	$	271
Alabama Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Nuclear decommissioning trusts(b)
Domestic equity	393		90		—		483
Foreign equity	36		65		—		101
U.S. Treasury and government agency securities	—		34		—		34
Corporate bonds	10		113		—		123
Mortgage and asset backed securities	—		18		—		18
Other	—		6		4		10
Cash equivalents	287		—		—		287
Total	$	726	$	327	$	4	$	1,057
Liabilities:
Energy-related derivatives	$	—	$	59	$	—	$	59
Interest rate derivatives	—		14		—		14
Total	$	—	$	73	$	—	$	73

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

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	Fair Value Measurements Using
As of March 31, 2015:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in millions)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	6	$	—	$	6
Interest rate derivatives	—		6		—		6
Nuclear decommissioning trusts(b) (c)
Domestic equity	182		2		—		184
Foreign equity	—		126		—		126
U.S. Treasury and government agency securities	—		86		—		86
Municipal bonds	—		92		—		92
Corporate bonds	—		192		—		192
Mortgage and asset backed securities	—		107		—		107
Other	11		6		—		17
Cash equivalents	406		—		—		406
Total	$	599	$	623	$	—	$	1,222
Liabilities:
Energy-related derivatives	$	—	$	24	$	—	$	24
Interest rate derivatives	—		31		—		31
Total	$	—	$	55	$	—	$	55
Gulf Power
Assets:
Cash equivalents	$	18	$	—	$	—	$	18
Liabilities:
Energy-related derivatives	—		90		—		90
Mississippi Power
Assets:
Cash equivalents	$	110	$	—	$	—	$	110
Liabilities:
Energy-related derivatives	—		52		—		52
Southern Power
Assets:
Cash equivalents	$	3	$	—	$	—	$	3

(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 March 31, 2015, approximately $50 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan and pledged to creditors under the funds' managers' securities lending program.

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(UNAUDITED)

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 financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally, implied volatility of interest rate options. See Note (H) herein for additional information on how these derivatives are used.

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' judgment, are also obtained when available.

Investments in private equity and real estate within Alabama Power's nuclear decommissioning trusts are generally classified as Level 3, as the underlying assets typically do not have observable inputs. The fund manager values these assets using various inputs and techniques depending on the nature of the underlying investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.

"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.

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(UNAUDITED)

As of March 31, 2015, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:

As of March 31, 2015:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Foreign equity funds	$	126	None	Monthly	5 days
Equity - commingled funds	65		None	Daily/Monthly	Daily/7 days
Debt - commingled funds	16		None	Daily	5 days
Other - commingled funds	6		None	Daily	Not applicable
Other - money market funds	11		None	Daily	Not applicable
Trust-owned life insurance	118		None	Daily	15 days
Cash equivalents:
Money market funds	863		None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Equity - commingled funds	$	65	None	Daily/Monthly	Daily/7 days
Debt - commingled funds	16		None	Daily	5 days
Trust-owned life insurance	118		None	Daily	15 days
Cash equivalents:
Money market funds	287		None	Daily	Not applicable
Georgia Power
Nuclear decommissioning trusts:
Foreign equity funds	$	126	None	Monthly	5 days
Other - commingled funds	6		None	Daily	Not applicable
Other - money market funds	11		None	Daily	Not applicable
Cash equivalents:
Money market funds	406		None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds	$	18	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds	$	110	None	Daily	Not applicable
Southern Power
Cash equivalents:
Money market funds	$	3	None	Daily	Not applicable

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (the Funds) to comply with the NRC's regulations. The foreign equity fund in Georgia Power's nuclear decommissioning trusts seeks to provide long-term capital appreciation. In pursuing this investment objective, the foreign equity fund primarily invests in a diversified portfolio of equity securities of foreign companies, including those in emerging markets. These equity securities may include, but are not limited to, common stocks, preferred stocks, real estate investment trusts, convertible securities, depositary receipts (including American depositary receipts, European depositary receipts, and global depositary receipts), and rights and warrants to buy common stocks. Georgia Power may withdraw all or a portion of its investment on the last business day of each month subject to a minimum

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(UNAUDITED)

withdrawal of $1 million, provided that a minimum investment of $10 million remains. If notices of withdrawal exceed 20% of the aggregate value of the foreign equity fund, then the foreign equity fund's board may refuse to permit the withdrawal of all such investments and may scale down the amounts to be withdrawn pro rata and may further determine that any withdrawal that has been postponed will have priority on the subsequent withdrawal date.

The other-commingled funds and other-money market funds in Georgia Power's nuclear decommissioning trusts are invested primarily in a diversified portfolio of high-quality, short-term, liquid debt securities. The funds represent cash collateral received under the Funds' managers' securities lending program and/or excess cash held within each separate investment account.The primary objective of the funds is to provide a high level of current income consistent with stability of principal and liquidity. The funds invest primarily in, but not limited to, commercial paper, floating and variable rate demand notes, debt securities issued or guaranteed by the U.S. government or its agencies or instrumentalities, time deposits, repurchase agreements, municipal obligations, notes, and other high-quality short-term liquid debt securities that mature in 90 days or less. Redemptions are available on a same day basis up to the full amount of the investment in the fund. See Note 1 to the financial statements of Southern Company and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

Alabama Power's nuclear decommissioning trusts include investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trusts invest in the TOLI in order to minimize the impact of taxes on the portfolios and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trusts do not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. These commingled funds, along with other equity and debt commingled funds held in Alabama Power's nuclear decommissioning trusts, primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities may include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection. See Note 1 to the financial statements of Southern Company and Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. For the three months ended March 31, 2015, the change in fair value of the funds, including reinvested interest and dividends reduced by the funds' expenses, increased by $65 million at Southern Company. For the three months ended March 31, 2015, Alabama Power recorded an increase in fair value of $47 million as an increase in regulatory liabilities. Georgia Power recorded an increase in fair value of $18 million as a reduction of its regulatory asset related to its ARO.

The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the investment in the money market funds.

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(UNAUDITED)

As of March 31, 2015, 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:
Southern Company	$	24,241	$	26,350
Alabama Power	$	6,922	$	7,696
Georgia Power	$	9,801	$	10,733
Gulf Power	$	1,370	$	1,501
Mississippi Power	$	2,251	$	2,323
Southern Power	$	1,621	$	1,789

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 offered to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power.

(D) STOCKHOLDERS' EQUITY

Earnings per Share

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

	Three Months Ended March 31, 2015	Three Months Ended March 31, 2014
	(in millions)
As reported shares	910	890
Effect of options and performance share award units	5	3
Diluted shares	915	893

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for the three months ended March 31, 2015 and were 17 million for the three months ended March 31, 2014.

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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 Interest
	(in thousands)			(in millions)
Balance at December 31, 2014	908,502	(725	)	$	19,949		$	756	$	221	$	20,926
Net income after dividends on preferred and preference stock	—	—		508			—		—		508
Other comprehensive income (loss)	—	—		(15		)	—		—		(15		)
Stock issued	3,094	—		112			—		—		112
Stock-based compensation	—	—		53			—		—		53
Stock repurchased, at cost	—	(2,599	)	(115		)	—		—		(115		)
Cash dividends on common stock	—	—		(478		)	—		—		(478		)
Other	—	(11	)	3			—		—		3
Balance at March 31, 2015	911,596	(3,335	)	$	20,017		$	756	$	221	$	20,994
Balance at December 31, 2013	892,733	(5,647	)	$	19,008		$	756	$	—	$	19,764
Net income after dividends on preferred and preference stock	—	—		351			—		—		351
Other comprehensive income (loss)	—	—		2			—		—		2
Treasury stock re-issued	—	2,404		111			—		—		111
Stock issued	1,340	—		53			—		—		53
Stock repurchased, at cost	—	—		(4		)	—		—		(4		)
Cash dividends on common stock	—	—		(451		)	—		—		(451		)
Other	—	(18	)	—			—		—		—
Balance at March 31, 2014	894,073	(3,261	)	$	19,070		$	756	$	—	$	19,826

Stock Repurchased

On March 2, 2015, Southern Company announced a program to repurchase up to 20 million shares of Southern Company common stock to offset all or a portion of the incremental shares issued under its employee and director equity compensation plans, including through stock option exercises, until December 31, 2017. Under this program, approximately 2.6 million shares have been repurchased through March 31, 2015 at a total cost of approximately $115 million. Pursuant to board approval, Southern Company may repurchase shares through open market purchases or privately negotiated transactions, including accelerated or other share repurchase programs, in accordance with applicable securities laws.

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(UNAUDITED)

(E) FINANCING

Bank Credit Arrangements

Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional operating companies' variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2015 was approximately $1.8 billion (comprised of approximately $864 million at Alabama Power, $865 million at Georgia Power, $69 million at Gulf Power, and $40 million at Mississippi Power). In addition, at March 31, 2015, the traditional operating companies had approximately $396 million (comprised of approximately $200 million at Alabama Power, $118 million at Georgia Power, and $78 million at Gulf Power) of fixed rate pollution control revenue bonds outstanding that were required to be remarketed 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 for additional information. Subsequent to March 31, 2015, $80 million and $65 million of these fixed rate pollution control revenue bonds were purchased and are being held by Alabama Power and Georgia Power, respectively, and currently are not required to be remarketed within the next 12 months. See "Financing Activities" herein for additional information.

The following table outlines the committed credit arrangements by company as of March 31, 2015:

	Expires												Executable Term Loans				Due Within One Year
Company	2015		2016		2017		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)								(in millions)				(in millions)				(in millions)
Southern Company	$	—	$	—	$	—	$	1,000	$	1,000	$	1,000	$	—	$	—	$	—	$	—
Alabama Power	228		50		—		1,030		1,308		1,308		58		—		58		170
Georgia Power	—		150		—		1,600		1,750		1,736		—		—		—		150
Gulf Power	45		200		30		—		275		275		50		—		50		195
Mississippi Power	135		165		—		—		300		270		25		40		65		235
Southern Power	—		—		—		500		500		488		—		—		—		—
Other	70		—		—		—		70		70		20		—		20		50
Total	$	478	$	565	$	30	$	4,130	$	5,203	$	5,147	$	153	$	40	$	193	$	800

Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration.

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(UNAUDITED)

Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first three months of 2015:

Company(a)	Senior Note Issuances		Senior Note Redemptions		Other Long-Term Debt Redemptions and Maturities(b)
	(in millions)
Alabama Power	$	550	$	250	$	—
Georgia Power	—		—		3
Mississippi Power	—		—		76
Other	—		—		4
Total	$	550	$	250	$	83

(a) Southern Company, Gulf Power, and Southern Power did not issue or redeem any long-term debt during the first three months of 2015.

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

Alabama Power

In March 2015, Alabama Power issued $550 million aggregate principal amount of Series 2015A 3.750% Senior Notes due March 1, 2045. The proceeds were used to redeem $250 million aggregate principal amount of Series DD 5.65% Senior Notes due March 15, 2035 and for general corporate purposes, including Alabama Power's continuous construction program.

Subsequent to March 31, 2015, Alabama Power purchased and held $80 million aggregate principal amount of Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Barry Plant Project), Series 2007-B. Alabama Power may reoffer these bonds to the public at a later date.

Also subsequent to March 31, 2015, Alabama Power issued $175 million additional aggregate principal amount of its Series 2015A 3.750% Senior Notes due March 1, 2045 (Additional Series 2015A Senior Notes) and $250 million aggregate principal amount of its Series 2015B 2.800% Senior Notes due April 1, 2025 (Series 2015B Senior Notes). A portion of the proceeds of the Additional Series 2015A Senior Notes and the Series 2015B Senior Notes will be used for the announced redemption on May 15, 2015 of 6.48 million shares ($162 million aggregate stated capital) of Alabama Power's 5.20% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, 4.0 million shares ($100 million aggregate stated capital) of Alabama Power's 5.30% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and 6.0 million shares ($150 million aggregate stated capital) of Alabama Power's 5.625% Series Preference Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and the remaining net proceeds will be used for general corporate purposes, including Alabama Power's continuous construction program.

Georgia Power

Subsequent to March 31, 2015, Georgia Power purchased and held $65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008. Georgia Power may reoffer these bonds to the public at a later date.

Mississippi Power

Subsequent to March 31, 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes, including Mississippi Power's ongoing construction program.

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(UNAUDITED)

Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.

(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, 2015. 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 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 months ended March 31, 2015 and 2014 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended March 31, 2015
Service cost	$	64		$	15		$	18		$	3		$	3
Interest cost	111			26			38			5			5
Expected return on plan assets	(181		)	(45		)	(63		)	(8		)	(8		)
Amortization:
Prior service costs	6			2			3			—			—
Net (gain)/loss	54			14			19			3			3
Net cost	$	54		$	12		$	15		$	3		$	3
Three Months Ended March 31, 2014
Service cost	$	53		$	12		$	16		$	3		$	3
Interest cost	109			26			38			5			5
Expected return on plan assets	(161		)	(42		)	(57		)	(7		)	(7		)
Amortization:
Prior service costs	6			1			3			—			—
Net (gain)/loss	28			8			10			1			1
Net cost	$	35		$	5		$	10		$	2		$	2

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(UNAUDITED)

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power
	(in millions)
Three Months Ended March 31, 2015
Service cost	$	6		$	1		$	2		$	—	$	—
Interest cost	19			5			8			1		1
Expected return on plan assets	(15		)	(6		)	(6		)	—		—
Amortization:
Prior service costs	1			1			—			—		—
Net (gain)/loss	5			—			3			—		—
Net cost	$	16		$	1		$	7		$	1	$	1
Three Months Ended March 31, 2014
Service cost	$	5		$	1		$	2		$	—	$	—
Interest cost	20			5			8			1		1
Expected return on plan assets	(15		)	(6		)	(6		)	—		—
Amortization:
Prior service costs	1			1			—			—		—
Net (gain)/loss	1			—			—			—		—
Net cost	$	12		$	1		$	4		$	1	$	1

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(UNAUDITED)

(G) EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS

Effective Tax Rate

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

Southern Company

Southern Company's effective tax rate is typically lower than the statutory rate due to its employee stock plans' dividend deduction and non-taxable AFUDC equity.

Southern Company's effective tax rate was 34.3% for the three months ended March 31, 2015 compared to 32.3% for the corresponding period in 2014. The effective tax rate increase was due to higher net income and beneficial changes that impacted 2014 state income taxes.

Mississippi Power

Mississippi Power's effective tax rate was 10.0% for the three months ended March 31, 2015 compared to (43.0)% for the corresponding period in 2014. The increase was primarily due to higher net income, partially offset by a decrease in non-taxable AFUDC equity related to the construction of the Kemper IGCC.

Southern Power

Southern Power's effective tax rate was 25.8% for the three months ended March 31, 2015 compared to 8.5% for the corresponding period in 2014. The increase was primarily due to beneficial changes that impacted 2014 state income taxes, which was partially offset by increased federal income tax benefits related to ITCs in the current year.

Unrecognized Tax Benefits

Southern Company reduced tax payments for 2014, and included in its 2013 consolidated federal income tax return deductions for R&E expenditures related to the Kemper IGCC. The Kemper IGCC is based on first-of-a-kind technology, and Mississippi Power and Southern Company believe that a significant portion of the plant costs qualify as deductible R&E 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, Mississippi Power and Southern Company had related unrecognized tax benefits of approximately $211 million and associated interest of $3 million at March 31, 2015.

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

(H) DERIVATIVES

Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. 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) herein 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.

Energy-Related Derivatives

The traditional 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 operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs,

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(UNAUDITED)

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 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 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.

To mitigate residual risks relative to movements in electricity prices, the traditional operating companies and Southern Power may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the traditional operating companies and Southern Power may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

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 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 and 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 March 31, 2015, 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	241	2020	2017
Alabama Power	54	2018	—
Georgia Power	44	2017	—
Gulf Power	92	2020	—
Mississippi Power	49	2018	—
Southern Power	2	—	2017

In addition to the volumes discussed in the above table, the traditional 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 4 million mmBtu for Southern Company, 3 million mmBtu for Georgia Power, and 1 million mmBtu for Southern Power.

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(UNAUDITED)

For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending March 31, 2016 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.

At March 31, 2015, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date	Fair Value Gain (Loss) at March 31, 2015
	(in millions)					(in millions)
Cash Flow Hedges of Forecasted Debt
Alabama Power	$	200	3-month LIBOR	2.93%	October 2025	$	(14	)
Georgia Power	350		3-month LIBOR	2.57%	May 2025	(17		)
Georgia Power	350		3-month LIBOR	2.57%	November 2025	(13		)
Cash Flow Hedges of Existing Debt
Georgia Power	250		3-month LIBOR + 0.32%	0.75%	March 2016	—
Georgia Power	200		3-month LIBOR + 0.40%	1.01%	August 2016	—
Fair Value Hedges on Existing Debt
Southern Company	250		1.30%	3-month LIBOR + 0.17%	August 2017	1
Georgia Power	250		5.40%	3-month LIBOR + 4.02%	June 2018	2
Georgia Power	200		4.25%	3-month LIBOR + 2.46%	December 2019	4
Total	$	2,050				$	(37	)

The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending March 31, 2016 are immaterial for all registrants. Southern Company and certain subsidiaries have deferred gains and losses that are expected to be amortized into earnings through 2037.

159

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Derivative Financial Statement Presentation and Amounts

At March 31, 2015, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at March 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	$	6	$	1	$	5	$	—	$	—
Other deferred charges and assets	1		—		1		—		—
Total derivatives designated as hedging instruments for regulatory purposes	$	7	$	1	$	6	$	—	$	—	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	7	$	—	$	5	$	—	$	—	$	—
Other deferred charges and assets	1		—		1		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	8	$	—	$	6	$	—	$	—	$	—
Total asset derivatives	$	15	$	1	$	12	$	—	$	—	$	—

Liability Derivatives at March 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 liabilities(*)	$	117	$	33	$	21	$	37	$	26
Other deferred credits and liabilities	108		26		3		53		26
Total derivatives designated as hedging instruments for regulatory purposes	$	225	$	59	$	24	$	90	$	52	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current liabilities(*)	$	45	$	14	$	31	$	—	$	—	$	—
Other deferred credits and liabilities	1		—		—		—		—		—
Total derivatives designed as hedging instruments in cash flow and fair value hedges	$	46	$	14	$	31	$	—	$	—	$	—
Total liability derivatives	$	271	$	73	$	55	$	90	$	52	$	—

(*) Georgia Power and Gulf Power include current liabilities related to derivatives designated as hedging instruments in "Liabilities from risk management activities."

160

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At December 31, 2014, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at December 31, 2014
	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	$	7	$	1	$	6	$	—	$	—
Other deferred charges and assets	—		—		1		—		—
Total derivatives designated as hedging instruments for regulatory purposes	$	7	$	1	$	7	$	—	$	—	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	7	$	—	$	5	$	—	$	—	$	—
Other deferred charges and assets	1		—		1		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	8	$	—	$	6	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets(*)	$	6	$	—	$	—	$	—	$	—	$	5
Total asset derivatives	$	21	$	1	$	13	$	—	$	—	$	5

(*) Southern Power includes current assets related to derivatives not designated as hedging instruments in "Assets from risk management activities."

161

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Liability Derivatives at December 31, 2014
	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 liabilities(*)	$	118	$	32	$	23	$	37	$	26
Other deferred credits and liabilities	79		21		4		35		19
Total derivatives designated as hedging instruments for regulatory purposes	$	197	$	53	$	27	$	72	$	45	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current liabilities(*)	$	17	$	8	$	9	$	—	$	—	$	—
Other deferred credits and liabilities	7		—		5		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	24	$	8	$	14	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current liabilities	$	4	$	—	$	—	$	—	$	—	$	4
Total liability derivatives	$	225	$	61	$	41	$	72	$	45	$	4

(*) Georgia Power and Gulf Power include current liabilities related to derivatives designated as hedging instruments in "Liabilities from risk management activities."

The derivative contracts of Southern Company, the traditional 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 and interest rate derivative contracts at March 31, 2015 and December 31, 2014 are presented in the following tables.

162

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Derivative Contracts at March 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		$	6		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(6		)	(1		)	(6		)	—		—		—
Net energy-related derivative assets	$	1		$	—		$	—		$	—	$	—	$	—
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	8		$	—		$	6		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(2		)	—			(2		)	—		—		—
Net interest rate derivative assets	$	6		$	—		$	4		$	—	$	—	$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	225		$	59		$	24		$	90	$	52	$	—
Gross amounts not offset in the Balance Sheet (b)	(6		)	(1		)	(6		)	—		—		—
Net energy-related derivative liabilities	$	219		$	58		$	18		$	90	$	52	$	—
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	46		$	14		$	31		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(2		)	—			(2		)	—		—		—
Net interest rate derivative liabilities	$	44		$	14		$	29		$	—	$	—	$	—

(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.

163

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Derivative Contracts at December 31, 2014
	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)	$	13		$	1	$	7		$	—	$	—	$	5
Gross amounts not offset in the Balance Sheet (b)	(9		)	—		(7		)	—		—		—
Net energy-related derivative assets	$	4		$	1	$	—		$	—	$	—	$	5
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	8		$	—	$	6		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(8		)	—		(6		)	—		—		—
Net interest rate derivative assets	$	—		$	—	$	—		$	—	$	—	$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	201		$	53	$	27		$	72	$	45	$	4
Gross amounts not offset in the Balance Sheet (b)	(9		)	—		(7		)	—		—		—
Net energy-related derivative liabilities	$	192		$	53	$	20		$	72	$	45	$	4
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	24		$	8	$	14		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(8		)	—		(6		)	—		—		—
Net interest rate derivative liabilities	$	16		$	8	$	8		$	—	$	—	$	—

(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.

164

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At March 31, 2015 and December 31, 2014, 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 March 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	$	(117	)	$	(33	)	$	(21	)	$	(37	)	$	(26	)
Other regulatory assets, deferred	(108		)	(26		)	(3		)	(53		)	(26		)
Other regulatory liabilities, current (a)	6			1			5			—			—
Other regulatory liabilities, deferred (b)	1			—			1			—			—
Total energy-related derivative gains (losses)	$	(218	)	$	(58	)	$	(18	)	$	(90	)	$	(52	)

(a) Southern Company and Georgia Power include 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, 2014
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	$	(118	)	$	(32	)	$	(23	)	$	(37	)	$	(26	)
Other regulatory assets, deferred	(79		)	(21		)	(4		)	(35		)	(19		)
Other regulatory liabilities, current (a)	7			1			6			—			—
Other regulatory liabilities, deferred (b)	—			—			1			—			—
Total energy-related derivative gains (losses)	$	(190	)	$	(52	)	$	(20	)	$	(72	)	$	(45	)

(a) Southern Company and Georgia Power include other regulatory liabilities, current in other current liabilities.

(b) Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.

For the three months ended March 31, 2015 and 2014, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income 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
	2015			2014			2015			2014
	(in millions)						(in millions)
Southern Company
Interest rate derivatives	$	(29	)	$	—	Interest expense, net of amounts capitalized	$	(2	)	$	(2	)
Alabama Power
Interest rate derivatives	$	(6	)	$	—	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Georgia Power
Interest rate derivatives	$	(23	)	$	—	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)

For the three months ended March 31, 2015 and 2014, 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.

165

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the three months ended March 31, 2015 and 2014, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were immaterial on a gross basis for all registrants. Furthermore, 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 months ended March 31, 2015 and 2014, the pre-tax effects of energy-related 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 March 31, 2015, the registrants' collateral posted with their derivative counterparties was immaterial.

At March 31, 2015, the fair value of derivative liabilities with contingent features was $59 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 $59 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 operating companies, and Southern Power are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional 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 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 operating companies', and Southern Power's exposure to counterparty credit risk. Therefore, Southern Company, the traditional operating companies, and Southern Power do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

(I) ACQUISITIONS

During 2015, Southern Power Company acquired or contracted to acquire the following projects in accordance with its overall growth strategy.

Decatur County Solar Projects

On February 19, 2015, Southern Power Company acquired all of the outstanding membership interests of Decatur Parkway Solar Project, LLC and Decatur County Solar Project, LLC from TradeWind Energy, Inc. as part of Southern Power's plans to build two solar photovoltaic facilities: the Decatur Parkway Solar Project and the Decatur County Solar Project. These two projects, approximately 80 MWs and 19 MWs, respectively, will be constructed on separate sites in Decatur County, Georgia. Construction of the Decatur Parkway Solar Project commenced in February 2015, while construction of the Decatur County Solar Project is expected to commence in June 2015. Both projects are expected to begin commercial operation in late 2015, and the entire output of each project is contracted to Georgia Power. The Decatur Parkway Solar Project is contracted under a 25-year PPA and the Decatur County Solar Project is contracted under a separate 20-year PPA. Construction costs incurred through March 31, 2015 were $32 million.

The total estimated cost of the facilities is expected to be between $200 million and $220 million, which includes the acquisition price for all of the outstanding membership interests of Decatur Parkway Solar Project, LLC and

166

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Decatur County Solar Project, LLC from TradeWind Energy, Inc. The ultimate outcome of these matters cannot be determined at this time.

Kay County Wind Facility

On February 24, 2015, Southern Power Company, through its wholly-owned subsidiary Southern Renewable Energy, Inc., entered into a purchase agreement with Kay Wind Holdings, LLC, a wholly-owned subsidiary of Apex Clean Energy Holdings, LLC, the developer of the project, to acquire all of the outstanding membership interests of Kay Wind, LLC (Kay Wind). Kay Wind is constructing and owns an approximately 299-MW wind facility in Kay County, Oklahoma. The wind facility is expected to begin commercial operation in late 2015, and the entire output of the facility is contracted under separate 20-year PPAs with Westar Energy, Inc. and Grand River Dam Authority.

In March 2015, Kay Wind obtained the necessary financing for the construction of the facility, and Southern Power Company's acquisition is expected to close in the fourth quarter 2015. The purchase price is expected to be approximately $492 million, with potential purchase price adjustments based on performance testing, and is included in Southern Power's capital program estimates for 2015. The completion of the acquisition is subject to Kay Wind achieving certain construction and project milestones, and various other customary conditions to closing. The ultimate outcome of this matter cannot be determined at this time.

Butler Solar Project

On March 12, 2015, Southern Power Company entered into a purchase agreement with CERSM, LLC and Community Energy, Inc. to acquire all of the outstanding membership interests of Butler Solar LLC as part of Southern Power's plans to build an approximately 100-MW solar photovoltaic facility in Taylor County, Georgia. Construction of the project is expected to commence in July 2015, with commercial operation expected to begin in December 2016. The entire output of the project is contracted to Georgia Power under a 30-year PPA.

Southern Power Company's acquisition of Butler Solar LLC is expected to close later in May 2015 and the total estimated cost of the facility is expected to be between $220 million and $230 million, which includes the acquisition price for all of the outstanding membership interests of Butler Solar LLC from CERSM, LLC and Community Energy, Inc. The completion of the acquisition is subject to customary conditions to closing. The ultimate outcome of this matter cannot be determined at this time.

Subsequent Events

Lost Hills-Blackwell Solar Facilities

On April 15, 2015, Southern Power Company, through its subsidiary Southern Renewable Partnerships, LLC (SRP), acquired 100% of the class A membership interests of Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell) from a wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project, for approximately $74 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of Lost Hills Blackwell for approximately $34 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from Lost Hills Blackwell. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. Lost Hills Blackwell constructed and owns the approximately 20-MW Lost Hills and the approximately 12-MW Blackwell solar facilities in Kern County, California. These solar facilities began commercial operation on April 17, 2015, and their entire output is contracted under PPAs, initially to the City of Roseville and then to Pacific Gas and Electric Company, that together extend approximately 29 years.

Pawpaw Solar Project

On April 22, 2015, Southern Power Company entered into a purchase agreement with Longview Solar, LLC to acquire all of the outstanding membership interests of LS – Pawpaw, LLC as part of Southern Power Company's plans to build an approximately 30-MW solar photovoltaic facility in Taylor County, Georgia. Construction of the project is expected to commence in June 2015, with commercial operation expected to begin in December 2015. The entire output of the project is contracted to Georgia Power under a 30-year PPA.

167

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Southern Power Company's acquisition of LS – Pawpaw, LLC is expected to close later in May 2015 and the total estimated cost of the facility is expected to be between $65 million and $75 million, which includes the acquisition price for all of the outstanding membership interests of LS – Pawpaw, LLC from Longview Solar, LLC. The completion of the acquisition is subject to customary conditions to closing. The ultimate outcome of this matter cannot be determined at this time.

North Star Solar Facility

On April 30, 2015, Southern Power Company, through its subsidiary SRP, acquired 100% of the class A membership interests of NS Solar Holdings, LLC (North Star) from a wholly-owned subsidiary of First Solar, the developer of the project, for approximately $208 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of North Star for approximately $99 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from North Star. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. North Star is constructing and owns the approximately 60-MW North Star solar facility in Fresno County, California, which is expected to begin commercial operation in June 2015. The entire output of the project is contracted under a 20-year PPA with Pacific Gas and Electric Company. The ultimate outcome of this matter cannot be determined at this time.

168

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 operating companies and Southern Power. The four traditional 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 operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $114 million and $72 million for the three months ended March 31, 2015 and March 31, 2014, 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 investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material. Financial data for business segments and products and services for the three months ended March 31, 2015 and 2014 was as follows:

	Electric Utilities
	Traditional Operating Companies		Southern Power		Eliminations			Total		All Other		Eliminations			Consolidated
	(in millions)
Three Months Ended March 31, 2015:
Operating revenues	$	3,948	$	348	$	(124	)	$	4,172	$	40	$	(29	)	$	4,183
Segment net income (loss)(a)(b)	477		33		—			510		3		(5		)	508
Total assets at March 31, 2015	$	65,530	$	5,564	$	(273	)	$	70,821	$	1,091	$	(302	)	$	71,610
Three Months Ended March 31, 2014:
Operating revenues	$	4,378	$	351	$	(102	)	$	4,627	$	41	$	(24	)	$	4,644
Segment net income (loss)(a)(b)	318		33		—			351		—		—			351
Total assets at December 31, 2014	$	64,644	$	5,550	$	(131	)	$	70,063	$	1,156	$	(296	)	$	70,923

(a) After dividends on preferred and preference stock of subsidiaries.

(b) Segment net income (loss) for the traditional operating companies for the three months ended March 31, 2015 and March 31, 2014 includes a $9 million pre-tax charge ($6 million after tax) and a $380 million pre-tax charge ($235 million after tax), respectively, for estimated probable losses on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended March 31, 2015	$	3,542	$	467	$	163	$	4,172
Three Months Ended March 31, 2014	3,858		604		165		4,627

169

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. There have been no material changes to these risk factors from those previously disclosed in the Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

(c) Issuer Purchases of Equity Securities

2015	Total Number of Shares Purchased (*)	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(*)	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs (*)
January 1 – January 31	N/A	N/A		N/A	N/A
February 1 – February 28	N/A	N/A		N/A	N/A
March 1 – March 31	2,599,366	$	44.227	2,599,366	N/A
Total	2,599,366	$	44.227	2,599,366	17,400,634

(*) On March 2, 2015, Southern Company announced a program to repurchase up to 20 million shares of Southern Company common stock to offset all or a portion of the incremental shares issued under its employee and director equity compensation plans, including through stock option exercises, until December 31, 2017.

170

Item 6.    Exhibits.

	(4) Instruments Describing Rights of Security Holders, Including Indentures
	Alabama Power
	(b)1	-	Fifty-Third Supplemental Indenture to Senior Note Indenture dated as of March 11, 2015, providing for the issuance of the Series 2015A 3.750% Senior Notes due March 1, 2045. (Designated in Form 8-K dated March 5, 2015, File No. 1-3164, as Exhibit 4.6.)
	(b)2	-	Fifty-Fourth Supplemental Indenture to Senior Note Indenture dated as of April 14, 2015, providing for the issuance of the Series 2015B 2.800% Senior Notes due April 1, 2025. (Designated in Form 8-K dated April 9, 2015, File No. 1-3164, as Exhibit 4.6(b).)
	(10) Material Contracts
	Southern Company
#	(a)1	-	Retention Award Agreement between Southern Nuclear and Stephen E. Kuczynski effective as of October 20, 2014.
#	(a)2	-	Base Salaries of Named Executive Officers.
	Georgia Power
#	(c)1	-	Base Salaries of Named Executive Officers.
#	(c)2	-	First Amendment to the Deferred Compensation Plan for Outside Directors of Georgia Power Company, Amended and Restated Effective January 1, 2008.
#	(c)3	-	Deferred Compensation Agreement between Southern Company, Southern Company Services, Inc., and John L. Pemberton, effective October 8, 2008.
#	(c)4	-	Summary of Non-Employee Director Compensation Arrangements.
	Mississippi Power
#	(e)1	-	Base Salaries of Named Executive Officers.
	(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, 2014, 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, 2014, 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, 2014, File No. 1-6468 as Exhibit 24(c).)

171

Gulf Power
(d)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2014, 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, 2014, File No. 001-11229 as Exhibit 24(e).)
Southern Power
(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2014, File No. 333-98553 as Exhibit 24(f).)
(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.

172

(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) XBRL – Related Documents
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

173

THE SOUTHERN COMPANY

SIGNATURES

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

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

Date: May 7, 2015

174

ALABAMA POWER COMPANY

SIGNATURES

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

	ALABAMA POWER COMPANY
By	Mark A. Crosswhite
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Philip C. Raymond
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: May 7, 2015

175

GEORGIA POWER COMPANY

SIGNATURES

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

	GEORGIA POWER COMPANY
By	W. Paul Bowers
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	W. Ron Hinson
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: May 7, 2015

176

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.
	President and Chief Executive Officer
	(Principal Executive Officer)
By	Richard S. Teel
	Vice President and Chief Financial Officer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: May 7, 2015

177

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	G. Edison Holland, Jr.
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Moses H. Feagin
	Vice President, Treasurer, and Chief Financial Officer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: May 7, 2015

178

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	Oscar C. Harper IV
	President and Chief Executive Officer
	(Principal Executive Officer)
By	William C. Grantham
	Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: May 7, 2015

179

EX-10.A1

Exhibit 10(a)1

RETENTION AWARD AGREEMENT

THIS RETENTION AWARD AGREEMENT (Agreement), made and entered into by and between SOUTHERN NUCLEAR OPERATING COMPANY, INC. (Company) and STEPHEN E. KUCZYNSKI (Employee), shall be effective as of October 20, 2014 (Effective Date).

1.    Award Amount. As approved by the Compensation and Management Succession Committee of the Board of Directors of The Southern Company at its meeting held on October 20, 2014, Employee is awarded under the Agreement the number of Restricted Stock Units (RSUs) with a value of One Million Dollars and No Cents ($1,000,000.00) on the Effective Date and shall become vested in the RSUs, provided Employee is actively employed with the Company or an affiliate of the Company on December 31, 2017 (Vesting Date).

The Award under this Paragraph 1 is an award of time-based RSUs under the terms of the Southern Company Omnibus Incentive Compensation Plan and therefore governed by the terms of that plan. The deemed dividends associated with the RSUs shall be credited and treated as reinvested in additional RSUs until the Award is paid in accordance with Paragraph 2.

2.    Timing and Form of Payment of Retention Amount.

(a)    Generally. Unless modified by the provisions set forth in Paragraphs 2(b)-2(e), the vested amount shall be paid in shares of Common Stock to Employee in a lump sum within 30 days following the Vesting Date (Scheduled Payment Date), less any amounts required to be withheld as set forth in Paragraph 7 below.

(b)    Death. If Employee dies while in active service prior to the Vesting Date, notwithstanding anything to the contrary in the Agreement, Employee shall be treated as fully vested in the Award. The amount vested under this Paragraph 2(b) shall be paid on the earlier of (i) the Scheduled Payment Date or (ii) within 30 days following the Employee's date of death. Employee shall designate his beneficiary(ies) in the beneficiary designation form set forth in Exhibit 1 to the Agreement.

(c)    Disability. If Employee separates from service on account of becoming totally disabled as defined under the Company's long term disability plan prior to the Vesting Date, notwithstanding anything to the contrary in the Agreement, Employee shall be treated as fully vested in the Award. The amount vested under this Paragraph 2(c) shall be paid on the earlier of (i) the Scheduled Payment Date or (ii) within 30 days following the date Employee separates from service on account of disability.

(d)    Involuntary Termination. If Employee separates from service on account of being involuntarily terminated for reasons other than Cause prior to the Vesting Date, notwithstanding anything to the contrary in the Agreement, Employee shall be treated as fully vested in the Award. The amount vested under this Paragraph 2(d) shall be paid on the earlier of

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(i) the Scheduled Payment Date or (ii) within 30 days following the date the Employee separates from service.

(e)    Voluntary Termination or Termination for Cause. If Employee voluntarily terminates employment prior to the Vesting Date or is terminated for Cause solely as determined by the Company prior to the Scheduled Payment Date, Employee forfeits the Award and all amounts which could have been paid under the Agreement. For purposes of the Agreement, Cause or Termination for Cause shall include the following conditions:

(1)    Failure to Appropriately Discharge Duties. Employee willfully neglects or refuses to discharge his duties of employment, refuses to comply with any lawful or reasonable instructions given to him by the Company without reasonable excuse or knowingly violates the law in the course of the performance of his duties of employment or

(2)     Gross Misconduct. Employee is guilty of gross misconduct. For the purposes of the Agreement, the following acts shall constitute gross misconduct as solely determined by the Company:

(i)    Any act involving fraud or dishonesty against the Company or any of its affiliates;

(ii)    The carrying out of any activity or the making of any statement which disparages the Company or any of its affiliates or which would prejudice and/or reduce the good name and standing of the Company or any of its affiliates or would bring any one of these into contempt, ridicule or would reasonably shock or offend any community in which these companies are located;

(iii)    Final conviction of any felony or of any crime involving moral turpitude, dishonesty, breach of trust or unethical business conduct; or

(iv)    Violation of any Company policy that would warrant immediate termination of employment.

(e)    Delaying Payment. As set forth in Section 10 of the Agreement, the Award earned, vested and paid hereunder is a Short-Term Deferral and therefore not subject to the delayed payment provisions of Section 409A of the Internal Revenue Code of 1986, as amended (Code), and the regulations promulgated thereunder. Notwithstanding the foregoing, if Employee is a “specified employee” within the meaning of Section 409A of the Code as of the date of his separation from service, then payment of any amounts under the Agreement shall be deferred for six months after the date of his separation from service if it is determined that such delay is required by Section 409A of the Code.

3.    Amendment and/or Termination of the Agreement. The Agreement terminates when all amounts have been paid or forfeited pursuant to Paragraph 2. Notwithstanding the

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preceding sentence, the Employee and the Company may mutually agree to amend or terminate the Agreement prior to the Vesting Date only by written agreement signed by each party.

4.    Confidentiality. Employee represents and agrees that he will keep all terms and provisions of the Agreement completely confidential, except for possible disclosures to his legal and financial advisors and his spouse or to the extent required by law.

5.    Assignability. Neither Employee, his estate, his beneficiaries nor his legal representatives shall have any rights to commute, sell, assign, transfer or otherwise convey the right to receive any payments hereunder, which payments and the rights thereto are expressly declared to be nonassignable and nontransferable. Any attempt to assign or transfer the right to payments under the Agreement shall be void and have no effect.

6.    No Effect on Other Arrangements. It is expressly understood and agreed that any payments made in accordance with the Agreement are in addition to any other benefits or compensation to which Employee may be entitled or for which he may be eligible, whether funded or unfunded, by reason of his employment with the Company.

7.     Tax Withholding and Implications. To the extent permitted under Section 409A of the Code, there shall be deducted from the vested Award the number of shares of Common Stock necessary to cover the amount of any tax required by any governmental authority to be withheld from the Employee and paid over by the Company or an affiliate of the Company to such governmental authority for the account of the Employee. The Company makes no representations or guarantees regarding the tax implications of the Agreement and advises Employee to consult with his attorney and/or tax advisor regarding the tax implications of the Agreement.

8.    Compensation. Any compensation paid to Employee pursuant to the Agreement shall not be considered "compensation" as the term is defined in The Southern Company Employee Savings Plan, or "earnings" as such term is defined in The Southern Company Pension Plan. Payments to Employee shall not be considered wages, salaries or compensation under any other Company-sponsored employee benefit or compensation plan or program, unless the explicit terms of such plan or program provide otherwise.

9.    No Guarantee of Employment. No provision of the Agreement shall be construed to affect in any manner the existing rights of the Company to suspend, terminate, alter or modify, whether or not for Cause, the Employee’s employment relationship with the Company.

10.    Short-Term Deferral. The parties agree that the terms and provisions of the Agreement will be construed and interpreted to the maximum extent permitted in order to satisfy the requirements of a Short-Term Deferral under Section 409A of the Code, and the regulations promulgated thereunder.

SIGNATURES ARE ON FOLLOWING PAGE

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The Agreement has been executed by the parties first listed above, this 20th day of October 2014.

COMPANY
By:	/s/Stacy R. Kilcoyne
Its:	Vice President
EMPLOYEE
/s/Stephen E. Kuczynski

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RETENTION AND RESTRICTED STOCK UNIT AWARD AGREEMENT

EXHIBIT 1

BENEFICIARY DESIGNATION

Beneficiary

Name	Relationship	Percentage
Name	Relationship	Percentage

In the event that all or some beneficiaries designated above are not living at the time payment

should be made, I designate the following contingent beneficiaries to be paid such amounts:

Contingent Beneficiary

Name	Relationship	Percentage
Name	Relationship	Percentage

Any amounts not paid to the contingent beneficiary(ies) shall be paid to the Employee's estate.

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EX-10.A2

Exhibit 10(a)2

BASE SALARIES OF NAMED EXECUTIVE OFFICERS

THE SOUTHERN COMPANY

The following are the annual base salaries, effective March 1, 2015, unless otherwise noted, of the Chief Executive Officer and Chief Financial Officer of The Southern Company (the “Company”) and certain other executive officers of the Company who served during 2014.

Thomas A. Fanning Chairman, President and Chief Executive Officer	$1,250,000
Art P. Beattie Executive Vice President and Chief Financial Officer	$700,438
W. Paul Bowers Executive Vice President of the Company, President and Chief Executive Officer of Georgia Power Company	$814,895
Kimberly S. Greene Executive Vice President and Chief Operating Officer	$666,250
Stephen E. Kuczynski President and Chief Executive Officer of Southern Nuclear Operating Company	$708,496
Charles D. McCrary* Executive Vice President of the Company, President and Chief Executive Officer of Alabama Power Company	$803,247

* Retired May 1, 2014. Salary shown was Mr. McCrary’s salary effective March 1, 2014.

EX-10.C1

EXHIBIT 10(c)1

BASE SALARIES OF NAMED EXECUTIVE OFFICERS

GEORGIA POWER COMPANY

The following are the annual base salaries, effective March 1, 2015 of the Chief Executive Officer and Chief Financial Officer of Georgia Power Company and certain other executive officers of Georgia Power Company who served during 2014.

W. Paul Bowers President and Chief Executive Officer	$814,895
W. Ron Hinson Executive Vice President, Chief Financial Officer And Treasurer	$372,254
Joseph A. Miller Executive Vice President	$567,582
John L. Pemberton Executive Vice President	$336,929
Anthony L. Wilson Executive Vice President	$368,280

EX-10.C2

Exhibit 10(c)2

FIRST AMENDMENT TO THE DEFERRED COMPENSATION PLAN

FOR OUTSIDE DIRECTORS OF GEORGIA POWER COMPANY

WHEREAS, the Board of Directors of Georgia Power Company (the “Board”) previously adopted the Deferred Compensation Plan for Outside Directors of Georgia Power Company, as amended and restated effective January 1, 2008 (the “Plan”);

WHEREAS, the Board has authorized an amendment to the Plan to change the date the market value is determined under the Plan; and

WHEREAS, Section 12.1 of the Plan provides in relevant part that the Plan may be amended or modified by the Board for the desired purpose.

NOW, THEREFORE, effective April 1, 2015, the Board hereby amends the Plan as follows:

1.

Section 2.27, “Market Value,” is hereby amended by deleting such Section in its entirety and replacing it with the following.

2.27 “Market Value” means the closing price at which a share of the Common Stock shall have been traded on the date such Market Value is to be determined, as specified herein(or on the next preceding trading day if such date was not a trading date, as reported by the principal securities exchange on which the Common Stock is traded or, if there is no such sale on the relevant date, then on the last previous day on which a sale was reported. If the Common Stock is not listed for trading on a national securities exchange, the fair market value of the shares shall be determined by the Committee in good faith and in accordance with a reasonable valuation method as determined under Code Section 409A and the rules and regulations promulgated thereunder).

2.

Section 8.2, “Timing of Distribution(s),” is hereby amended by deleting the fourth and fifth paragraphs of that Section in their entirety and replacing them with the following:

The Market Value of any shares of Common Stock credited to a Director’s Phantom Stock Investment Account shall be determined as of the date of any lump sum or installment distribution as determined by the Committee.

Upon the death of a Director, or a former Director prior to the payment of all amounts credited to the Director’s Deferred Compensation Accounts, the unpaid balance shall be paid in a lump sum to the designated beneficiary of such Director or former Director within sixty (60) days of the date of death as permitted by Code Section 409A. In the event a beneficiary designation has not been made, or

the designated beneficiary is deceased or cannot be located, payment shall be made to the estate of the Director or former Director.

The Market Value of any shares of Common Stock credited to a Director’s Phantom Stock Investment Account shall be determined as of the date of any lump sum or installment distribution as determined by the Committee.

3.

Section 6.2 of the “Schedule of Provisions for Pre-2005 Deferrals” is hereby amended by deleting the second and third paragraphs of that Section in their entirety and replacing them with the following:

In the event a Director elected to receive the balance of his Deferred Compensation Accounts in lump sum, distribution shall be made on the first day of the month selected by the Director on his Distribution Election, or as soon as reasonably possible thereafter. If the Director elected to receive annual installments, the first payment shall be made on the first day of the month selected by a Director, or as soon as reasonably possible thereafter, and shall be equal to the balance of the Director’s Deferred Compensation Accounts on such date divided by the number of annual installment payments. Each subsequent annual payment shall be an amount equal to the balance in the Director’s Deferred Compensation Accounts on the date of payment divided by the number of remaining annual payments and shall be paid on the anniversary of the preceding date of payment. The Market Value of any shares of Common Stock credited to a Director’s Phantom Stock Investment Account shall be determined as of the date of any lump sum or installment distribution as determined by the Committee.

Upon the death of a Director, or a former Director prior to the payment of all amounts credited to the Director’s Deferred Compensation Accounts, the unpaid balance shall be paid in the sole discretion of the Committee (i) in a lump sum to the designated beneficiary of such Director or former Director within thirty (30) days of the date of death (or as soon as reasonably possible thereafter) or (ii) in accordance with the Distribution Election made by such Director or former Director. In the event a beneficiary designation has not been made, or the designated beneficiary is deceased or cannot be located, payment shall be made to the estate of the Director or former Director. The Market Value of any shares of Common Stock credited to a Director’s Phantom Stock Investment Account shall be determined as of the date of any lump sum or installment distribution as determined by the Committee.

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4.

Except as amended herein by this First Amendment, the Plan shall remain in full force and effect.

IN WITNESS WHEREOF, the Board has adopted the First Amendment to the Deferred Compensation Plan for Outside Directors of Georgia Power Company, as amended and restated as of January 1, 2008, pursuant to resolutions of the Board, this 18th day February, 2015.

	GEORGIA POWER COMPANY
	By:	/s/Thomas P. Bishop
		Secretary
Attest:
/s/D. Emi Rahn
Assistant Secretary

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EX-10.C3

Exhibit 10(c)3

DEFERRED COMPENSATION AGREEMENT

THIS DEFERRED COMPENSATION AGREEMENT (“Agreement”) is made and entered into by THE SOUTHERN COMPANY, (“Southern”), Southern Company Services, Inc. (the “Company”) (collectively the “Southern Parties”) and JOHN L. PEMBERTON (“Employee”), this 8th day of October, 2008 (“Effective Date”).

W I T N E S S E T H

WHEREAS, Employee is a highly compensated employee of the Company and is a member of its management;

WHEREAS, although Employee’s career with the Southern Company system began on September 8, 2003, his valuable services to Southern and its affiliated subsidiaries began at an earlier date with his work on energy industry regulatory matters; and

WHEREAS, the Southern Parties desire to set forth the manner in which Employee will be recognized for his prior valuable service.

NOW, THEREFORE, in consideration of the premises, and the agreements of the parties set forth herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto, intending to be legally bound, hereby covenant and agree as follows:

1.Eligibility for Supplemental Retirement Benefits.

(a)Subject to the terms of this Agreement, the Southern Parties shall pay to Employee (or if payment continues, to Employee’s designated beneficiary, as the case may be, in the event of Employee’s death as described in Section 1(c) hereof) the supplemental retirement payment (the “Payment”) described in Section 1(b) hereof (to be shared among the Company and Southern in such pro rata portions as set forth in Sections 2 or 3 hereof).

(b)In the event Employee satisfies the requirements of this Agreement, the Payment shall be an amount equal to the difference between:

(i)the amounts payable to Employee under The Southern Company Pension Plan (“Pension Plan”), the Southern Company Supplemental Benefit Plan (“SBP”) and the Southern Company Supplemental Executive Retirement Plan (“SERP”) (collectively, the “Retirement Plans”) as each shall then be in effect, determined as if Employee had an additional five (5) years of Accredited Service under the Pension Plan; and

(ii)the amounts Employee is actually entitled to receive under the Retirement Plans at Employee’s retirement, as each shall then be in effect, as further determined and payable in accordance with Section 1(d) hereof.

(c)Payment in the Event of Death. In the event Employee dies and Payment continues to Employee’s designated beneficiary (the “Death Benefit”), such Payment shall be made in accordance with Section 1(d) hereof.

(d)Calculation, Form and Timing of Payment. The calculation (including actuarial assumptions), form and timing of the Payment or Death Benefit upon the occurrence of a “separation from service” as defined in Section 409A of the Internal Revenue Code and the regulations promulgated thereunder (“Separation from Service”) shall be the same as the calculation (including actuarial assumptions), form and timing of similar payments to Employee or designated beneficiary as the case may be, under the terms of the SERP and the SBP (but, as to the SBP, only concerning the “Pension Benefit” provided thereunder) as each may be amended from time to time.

(e)Termination for Cause. In the event of Employee’s termination of employment for Cause at any time as solely determined by the Company, the Employee shall forfeit the entire benefit provided in this Section 1, and Southern, the Company and any of their respective affiliates (the “Southern Entities”) shall have no further obligations with respect to any amount under this Agreement. As used in this Agreement, the term “Cause” shall mean gross negligence or willful misconduct in the performance of the duties and services required in the course of employment by the Company; the final conviction of a felony or misdemeanor involving moral turpitude; the carrying out of any activity or the making of any statement which would prejudice the good name and standing of any of the Southern Entities or would bring any of the Southern Entities into contempt, ridicule or would reasonably shock or offend any community in which any of the Southern Entities is located; a material breach of the fiduciary obligations owed by an officer and an employee to any of the Southern Entities; or the Employee’s unsatisfactory performance of the duties and services required by his employment.

(f)Misconduct. Notwithstanding the foregoing, in the event the Employee engages in Misconduct, as defined below and as solely determined by the Company, before or after the Employee’s termination date but prior to receiving the benefit and all of the payments described in this Section 1, the Company may cease making payments to the Employee under

2

this Section 1, and the Company shall have no further obligations with respect to any amounts under this Agreement. For purposes of this Section 1(f), “Misconduct” shall mean (i) the final conviction of any felony, or (ii) the carrying out of any activity or the making of any public statement which materially diminishes the good name and standing of any Southern Entity or materially and untruthfully brings one or all of the Southern Entities into contempt, ridicule or materially and reasonably shocks or offends the community in which a Southern Entity is located.

2.Sharing of Expense. In the event that the Employee is employed by more than one subsidiary or affiliate of Southern, the liability for amounts paid under this Agreement shall be apportioned so that each such company is obligated in accordance with this Section 2 to cover their percentage of the total liability as determined below. Each company’s share of the liability shall be calculated by multiplying the Payment by a fraction where the numerator of such fraction is the base rate of pay received by the Employee at the respective company on his date of termination of employment or transfer, as applicable, multiplied by the Accredited Service as defined in the Pension Plan earned by the Employee at the respective company and where the denominator of such fraction is the sum of all numerators calculated for each respective company by which the Employee has been employed.

3.Transfer of Employment to a Southern Subsidiary or Affiliate. In the event that Employee’s employment by the Company is terminated and Employee shall become immediately re-employed by a subsidiary or an affiliate of Southern, the Company shall assign this Agreement pursuant to an Assignment Agreement substantially in the form of Exhibit 1 attached hereto, and such assignee shall become the “Company” for all purposes hereunder. Such subsidiary or affiliate shall accept such assignment, but if for any reason this does not occur, Southern shall accept such assignment. In the event of such assignment, liability for any amounts to be paid under this Agreement shall be shared pro rata by the Company, Southern and any such assignee (collectively “Contract Obligors”) based upon the allocation methodology set forth in Section 2.

4.Business Protection Provisions.

(a)Preamble. As a material inducement to the Southern Parties to enter into this Agreement, and the recognition of the valuable experience, knowledge and proprietary information Employee gained from his employment with the Company, Employee warrants and

3

agrees he will abide by and adhere to the following business protection provisions in this Section 4.

(b)Definitions. For purposes of this Section 4, the following terms shall have the following meanings:

(i)“Competitive Position” shall mean any employment, consulting, advisory, directorship, agency, promotional or independent contractor arrangement between Employee and any Entity (as defined below) engaged wholly or in material part in the business that the Company is engaged in whereby Employee is required to or does perform services on behalf of or for the benefit of such Entity which are substantially similar to the services Employee participated in or directed while employed by the Company or any other Southern Entity and where such services would be inconsistent with or contrary to any policy position the Southern Entities have taken on legislative or regulatory issues at the state or federal level, as of the effective date of the Agreement.

(ii)“Confidential Information” shall mean the proprietary or confidential data, information, documents or materials (whether oral, written, electronic or otherwise) belonging to or pertaining to the Company or any of the other Southern Entities, other than “Trade Secrets” (as defined below), which is of tangible or intangible value to any of the Southern Entities and the details of which are not generally known or available to the public and to the competitors of the Southern Entities. Confidential Information shall also include: (A) any items that any of the Southern Entities have marked “CONFIDENTIAL” or some similar designation or are otherwise identified as being confidential; (B) all non-public information known by or in the possession of Employee related to or regarding any proceedings involving or related to the Southern Entities before any federal or state regulatory agencies; and (C) all non-public communications, research, analysis, reports, opinions, recommendations and presentations prepared, reviewed, edited or possessed by Employee at any time during his employment, whether marked Confidential or not, which relate to electric utilities, electric generation or transmission in the United States, or the building, acquisition or ownership of electric utility assets in the United States.

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(iii)“Entity” or “Entities” shall mean any person, business, individual, partnership, joint venture, agency, governmental agency, body or subdivision, association, firm, corporation, limited liability company or other entity of any kind.

(iv)“Territory” shall mean the service territory of the Southern Entities and those states contiguous to such service territory or otherwise connected through regional electric markets..

(v)“Trade Secrets” shall mean information or data of or about any of the Southern Entities, including, but not limited to, technical or non-technical data, formulas, patterns, compilations, programs, devices, methods, techniques, drawings, processes, financial data, financial plans, product plans or lists of actual or potential customers or suppliers that: (A) derives economic value, actual or potential, from not being generally known to, and not being readily ascertainable by proper means by, other persons who can obtain economic value from its disclosure or use; and (B) is the subject of efforts that are reasonable under the circumstances to maintain its secrecy. Employee agrees that trade secrets include non-public information related to the rate making process of the Southern Entities and any other information which is defined as a “trade secret” under applicable law, regardless of the process through which Employee would have become aware of or possessed such information.

(vi)“Work Product” shall mean all tangible work product, memoranda, working papers, property, data, documentation, concepts or plans, inventions, improvements, techniques and processes (and drafts thereof) relating to the Southern Entities that were conceived, discovered, created, written, revised or developed by Employee during the term of his employment with the Company and not otherwise publicly available.

(c)Nondisclosure: Ownership of Proprietary Property.

(i)In recognition of the need of the Company to protect its legitimate business interests, Confidential Information and Trade Secrets, Employee hereby covenants and agrees that Employee shall regard and treat Trade Secrets and all Confidential Information as strictly confidential and wholly-owned by

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the Company and shall not, for any reason, in any fashion, either directly or indirectly, use, sell, lend, lease, distribute, license, give, transfer, assign, show, disclose, disseminate, reproduce, copy, misappropriate or otherwise communicate any such item or information to any third party Entity for any purpose other than in accordance with this Agreement or as required by applicable law: (A) with regard to each item constituting a Trade Secret, at all times such information remains a “trade secret” under applicable law, and (B) with regard to any Confidential Information, for a period of three (3) years following the Employee’s date of Separation from Service (hereafter the “Restricted Period”).

(ii)Employee shall exercise best efforts to ensure the continued confidentiality of all Trade Secrets and Confidential Information, and he shall immediately notify the Company of any unauthorized disclosure or use of any Trade Secrets or Confidential Information of which Employee becomes aware. Employee shall assist the Company, to the extent necessary, in the protection of or procurement of any intellectual property protection or other rights in any of the Trade Secrets or Confidential Information.

(iii)All Work Product shall be owned exclusively by the Company. To the greatest extent possible, any Work Product shall be deemed to be “work made for hire” (as defined in the Copyright Act, 17 U.S.C.A. § 101 et seq., as amended), and Employee hereby unconditionally and irrevocably transfers and assigns to the Company all right, title and interest Employee currently has or may have by operation of law or otherwise in or to any Work Product, including, without limitation, all patents, copyrights, trademarks (and the goodwill associated therewith), trade secrets, service marks (and the goodwill associated therewith) and other intellectual property rights. Employee agrees to execute and deliver to the Company any transfers, assignments, documents or other instruments which the Company may deem necessary or appropriate, from time to time, to protect the rights granted herein or to vest complete title and ownership of any and all Work Product, and all associated intellectual property and other rights therein, exclusively in the Company.

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(d)Non-Interference with Employees. Employee covenants and agrees that during the Restricted Period he will not, either directly or indirectly, alone or in conjunction with any Entity: (i) actively recruit, solicit, attempt to solicit, or induce any person who, during such Restricted Period, or within one year prior to his date of Separation from Service, was an exempt employee of the Company or any of its subsidiaries, or was an officer of any of the other Southern Entities to leave or cease such employment for any reason whatsoever; or (ii) hire or engage the services of any such person described in Section 4(d)(i) in any business substantially similar or competitive with that in which the Southern Entities were engaged during his employment.

(e)Non-Interference with Customers.

(i)Employee acknowledges that in the course of employment, he has learned about the Company’s business, services, materials, programs, plans, processes, and products and the manner in which they are developed, marketed, serviced and provided. Employee knows and acknowledges that the Company has invested considerable time and money in developing its business, services, materials, programs, plans, processes, products and marketing techniques and that they are unique and original. Employee further acknowledges that the Company must keep secret all pertinent information divulged to Employee regarding the Company’s business concepts, services, materials, ideas, programs, plans and processes, products and marketing techniques, so as not to aid the Company’s competitors. Accordingly, the parties agree that the Company is entitled to the following protection, which Employee agrees is reasonable:

(ii)Employee covenants and agrees that for a period of two (2) years following his date of Separation from Service, he will not, on his own behalf or on behalf of any Entity, solicit, direct, appropriate, call upon, or initiate communication or contact with any Entity or any representative of any Entity, with whom Employee had contact during his employment, with a view toward the sale or the providing of any product, equipment or service sold or provided or under development by the Company during the period of two (2) years immediately preceding the date of Employee’s date of Separation from Service. The restrictions set forth in this Section shall apply only to Entities with whom

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Employee had actual contact during the two (2) years prior to Employee’s date of Separation from Service with a view toward the sale or providing of any product, equipment or service sold, provided, or under development by the Company.

(f)Non-Interference with Business.

(i)Employee and the Company expressly covenant and agree that the scope, territorial, time and other restrictions contained in this entire Agreement constitute the most reasonable and equitable restrictions possible to protect the business interests of the Company given: (A) the business of the Company; (B) the competitive nature of the Company’s industry; and (C) that Employee’s skills are such that he could easily find alternative, commensurate employment or consulting work in his field which would not violate any of the provisions of this Agreement.

(ii)Employee covenants and agrees to not obtain or work in a Competitive Position within the Territory for a period of two (2) years from the date of Separation from Service, except as expressly approved by the Chief Executive Officer of the Company.

5.Publicity; No Disparaging Statement. Subject to the provisions of Section 9 hereof, Employee and the Company covenant and agree that they shall not engage in any communications which shall disparage one another or interfere with their existing or prospective business relationships. As to both the Employee and Company, such communications include, but are not necessarily limited to, remarks, comments, observations, analysis, opinions, statements, whether solicited or unsolicited, written or verbal, which reflect in any manner on the market, operating, financial, communications, people or other business strategies or actions of the Southern Entities, and their officers, directors, employees and agents.

6.No Employment. Employee agrees that he shall not unilaterally seek re-employment as an employee, temporary employee, leased employee or independent contractor with any of the Southern Entities, for a period of two (2) years following the Employee’s date of Separation from Service. Further, neither the Company nor any of the other Southern Entities shall rehire Employee as an employee, temporary employee, leased employee or independent contractor for a period of two (2) years following Employee’s date of Separation from Service, unless a necessary business reason exists for rehiring Employee and a committee, comprised of

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(a) an officer from the business unit of the Southern Entity seeking to rehire Employee and (b) a senior officer responsible for external affairs for the Company, approves of such rehiring.

7.Return of Materials. By no later than the Employee’s date of Separation from Service, Employee agrees to return to the Company all property of the Company and other Southern Entities, including but not limited to data, lists, information, memoranda, documents, identification cards, parking cards, keys, computers, fax machines, beepers, phones, files and any and all written or descriptive materials of any kind belonging or relating to the Company or any other Southern Entity, including, without limitation, any originals, copies and abstracts containing any Work Product, intellectual property, Confidential Information and Trade Secrets in Employee’s possession or control.

8.Cooperation. The parties agree that as a result of Employee’s duties and activities during his employment, Employee’s reasonable availability may be necessary for the Company to meaningfully respond to or address actual or threatened litigation, or government inquiries or investigations, or required filings with state, federal or foreign agencies (hereinafter “Company Matters”). Upon request of the Company, and at any point following Employee’s date of Separation from Service, Employee will make himself available to the Company for reasonable periods not inconsistent with his future employment, if any, by other Entities and will cooperate with the Company’s agents and attorneys as reasonably required by such Company Matters. The Company will reimburse Employee for any reasonable out-of-pocket expenses associated with providing such cooperation.

9.Confidentiality and Legal Process. Employee represents and agrees that he will keep the terms, amount and fact of this Agreement confidential and that he will not hereafter disclose any information concerning this Agreement at any time, without the express written consent of the Company, to anyone, including, but not limited to, any past, present, or prospective employee or applicant for employment with the Company. Notwithstanding the foregoing, nothing in this Section shall prohibit Employee from disclosing or discussing this Agreement with his spouse, attorney, tax advisors or accountants, who must be informed of and agree to be bound by the confidentiality provision set forth in this Section 9 before Employee discloses any information to them about this Agreement. In addition, nothing in this Agreement is intended to prohibit Employee from performing any duty or obligation that shall arise as a matter of law. Specifically, Employee shall continue to be under a duty to truthfully respond to

9

any legal and valid subpoena or other legal process. This Agreement is not intended in any way to proscribe Employee’s right and ability to provide information to any federal, state or local government in the lawful exercise of such governments’ governmental functions.

10.Successors and Assigns; Applicable Law. This Agreement shall be binding upon and inure to the benefit of Employee and his heirs, administrators, representatives, executors, successors and assigns, and shall be binding upon and inure to the benefit of the Contract Obligors and their officers, directors, employees, agents, shareholders, parent corporation, subsidiaries and affiliates, and their respective predecessors, successors, assigns, heirs, executors and administrators and each of them, and to their heirs, administrators, representatives, executors, successors, and assigns. This Agreement shall be construed and interpreted in accordance with the laws of the State of Georgia (without giving effect to principles of conflicts of laws), to the extent such laws are not otherwise superseded by the laws of the United States.

11.Complete Agreement. This Agreement shall constitute the full and complete agreement between the parties concerning its subject matter and fully supersedes any and all other prior agreements or understandings between the parties concerning the subject matter hereof. This Agreement shall not be modified or amended except by a written instrument signed by both Employee and an authorized representative of the Company and Southern.

12.Severability. The unenforceability or invalidity of any particular provision of this Agreement shall not affect its other provisions, and to the extent necessary to give such other provisions effect, they shall be deemed severable. If any of the provisions of this Agreement are determined by any court of law or equity with jurisdiction over this matter to be unreasonable or unenforceable, in whole or in part, as written, the parties hereby consent to and affirmatively request that said court reform the provision so as to be reasonable and enforceable and that said court enforce the provision as reformed. Employee acknowledges and agrees that the covenants and agreements contained in this Agreement, including, without limitation, the covenants and agreements contained in Sections 4, 5, 6, 7 and 8 shall be construed as covenants and agreements independent of each other or any other contract between the parties hereto and that the existence of any claim or cause of action by Employee, whether predicated upon this Agreement or any other contract, shall not constitute a defense to the enforcement by the Southern Parties of said covenants and agreements.

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13.Waiver of Breach; Specific Performance. The waiver of a breach of any provision of this Agreement shall not operate or be construed as a waiver of any other breach. Each of the parties to this Agreement will be entitled to enforce its or his rights under this Agreement, specifically, to recover damages by reason of any breach of any provision of this Agreement and to exercise all other rights existing in its or his favor. The parties hereto agree and acknowledge that money damages may not be an adequate remedy for any breach of the provisions of this Agreement and that any party may in its or his sole discretion apply to any court of law or equity of competent jurisdiction for specific performance or injunctive relief in order to enforce or prevent any violations of the provisions of this Agreement.

14.Unsecured General Creditor. The Contract Obligors shall neither reserve nor specifically set aside funds for the payment of its obligations under this Agreement, and such obligations shall be paid solely from the general assets of the Contract Obligors. Notwithstanding that Employee may be entitled to receive the value of his benefit under the terms and conditions of this Agreement, the assets from which such amount may be paid shall at all times be subject to the claims of the Contract Obligors’ creditors.

15.No Effect on other Arrangements. It is expressly understood and agreed that the payments made in accordance with this Agreement are in addition to any other benefits or compensation to which Employee may be entitled or for which he may be eligible, whether funded or unfunded, by reason of his employment with the Contract Obligors.

16.Tax Withholding and Implications. There shall be deducted from any payment under this Agreement 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 Employee.

17.Notices. All notices required, necessary or desired to be given pursuant to this Agreement shall be in writing and shall be effective when delivered or on the third day following the date upon which such notice is deposited, postage prepaid, in the United States mail, certified return receipt requested, and addressed to the party at the address set forth below:

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If to Employee:	If to the Company:
John L. Pemberton 5847 Potomac Avenue Washington, D.C. 20016	Patricia L. Roberts Vice President and Associate General Counsel Southern Company Services, Inc. 30 Ivan Allen Blvd., NW, Bin #SC1204 Atlanta, Georgia 30308

18.Compensation and/or Earnings. Any compensation paid to Employee under this Agreement shall not be considered “compensation,” as such term is defined in The Southern Company Employee Savings Plan or “earnings” as such term is defined in the Pension Plan. Any payment under this Agreement shall not be considered wages, salary or compensation under any other employee benefit plan of the Company or any other Southern Entity.

19.No Guarantee of Employment. No provision of this Agreement shall be construed to affect in any manner the existing rights of the Company to suspend, end, alter, or modify, whether or not for cause, the employment relationship of Employee and the Company.

20.Interpretation. The judicial body interpreting this Agreement shall not more strictly construe the terms of this Agreement against one party, it being agreed that both parties and/or their attorneys or agents have negotiated and participated in the preparation hereof.

21.Accredited Investor. Employee understands that the Company’s obligations under this Agreement have not been registered under the Securities Exchange Act of 1933, as amended (the “Securities Act”), or any state securities laws. Employee is an “accredited investor” as defined in Regulation D under the Securities Act, and has such knowledge and experience in financial and business matters that he is able to evaluate the risks and benefits of this Agreement. There has been direct communication and negotiation between the Company and Employee with respect to this Agreement. The Company has made available to Employee information regarding the business of the Company and the risks inherent therein, and Employee has had the opportunity to ask questions of, and receive responses from, the Company regarding such matters and the terms and conditions of this Agreement.

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first above written.

“SOUTHERN” THE SOUTHERN COMPANY
By:	/s/G. Edison Holland
Its:	Executive Vice President, General Counsel & Secretary
“SCS” SOUTHERN COMPANY SERVICES, INC
By:	/s/G. Edison Holland
Its:	Executive Vice President & General Counsel
“EMPLOYEE” John L. Pemberton
/s/John L. Pemberton

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EX-10.C4

EXHIBIT 10(c)(4)

SUMMARY OF NON-EMPLOYEE DIRECTOR COMPENSATION

GEORGIA POWER COMPANY

Only non-employee directors are compensated for service on the Board of Directors (the "Board") of Georgia Power Company.

At the election of the director, all or a portion of the cash retainer may be payable in common stock of The Southern Company, and all or a portion of total cash compensation may be deferred under the Deferred Compensation Plan and all of the stock retainer may be deferred under the Deferred Compensation Plan until membership on the Board is terminated. There is no pension plan for non-employee directors.

Prior to July 1, 2015, the pay components are as follows:

Ÿ	Annual Cash Retainer Fee:	$44,000 per year (paid quarterly)
Ÿ	Committee Chair Annual Retainer:	$5,000 per year (paid quarterly)
Ÿ	Annual Stock Retainer Fee:	$30,000 per year payable in common stock of The Southern Company (paid quarterly)
Ÿ	Board Meeting Fees:	If more than five meetings of the Board are held in a calendar year, $1,800 will be paid for participation in each meeting of the Board beginning with the sixth meeting.
Ÿ	Committee Meeting Fees:	If more than five meetings of any one Committee are held in a calendar year, $1,200 will be paid for participation in each meeting of that Committee beginning with the sixth meeting.

Effective July 1, 2015, the pay components are as follows:

Ÿ	Annual Cash Retainer Fee:	$44,000 per year (paid quarterly)
Ÿ	Committee Chair Annual Retainer:	$8,000 per year (paid quarterly)
Ÿ	Annual Stock Retainer Fee:	$34,500 per year payable in common stock of The Southern Company (paid quarterly)
Ÿ	Board Meeting Fees:	If more than six meetings of the Board are held in a calendar year, $1,800 will be paid for participation in each meeting of the Board beginning with the seventh meeting.
Ÿ	Committee Meeting Fees:	If more than six meetings of any one Committee are held in a calendar year, $1,500 will be paid for participation in each meeting of that Committee beginning with the seventh meeting.

EX-10.E1

EXHIBIT 10(e)1

BASE SALARIES OF NAMED EXECUTIVE OFFICERS

MISSISSIPPI POWER COMPANY

The following are the annual base salaries, effective March 1, 2015, unless otherwise noted, of the Chief Executive Officer and Chief Financial Officer of Mississippi Power Company and certain other executive officers of Mississippi Power Company who served during 2014.

G. Edison Holland, Jr. President and Chief Executive Officer	$678,480
Moses Feagin Vice President, Treasurer and Chief Financial Officer	$263,280
John W. Atherton Vice President	$267,651
Jeff G. Franklin Vice President	$265,125
R. Allen Reaves, Jr. Vice President	$223,465

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:  May 7, 2015

/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:  May 7, 2015

/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:  May 7, 2015

/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:  May 7, 2015

/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:   May 7, 2015

/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:  May 7, 2015

/s/W. Ron Hinson

W. Ron Hinson

Executive Vice President, Chief Financial Officer and Treasurer

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:  May 7, 2015

/s/S. W. Connally, Jr.

S. W. Connally, Jr.

President and Chief Executive Officer

EX-31.D2

Exhibit 31(d)2

GULF POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Richard S. Teel, 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:  May 7, 2015

/s/Richard S. Teel

Richard S. Teel

Vice President and Chief Financial Officer

EX-31.E1

Exhibit 31(e)1

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, G. Edison Holland, Jr., 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:  May 7, 2015

/s/G. Edison Holland, Jr.

G. Edison Holland, Jr.

Chairman, 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:  May 7, 2015

/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, Oscar C. Harper IV, 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:   May 7, 2015

/s/Oscar C. Harper IV

Oscar C. Harper IV

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:  May 7, 2015

/s/William C. Grantham

William C. Grantham

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 March 31, 2015, 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 March 31, 2015, 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 March 31, 2015, 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

May 7, 2015

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 March 31, 2015, 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 March 31, 2015, 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 March 31, 2015, 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

May 7, 2015

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 March 31, 2015, 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 March 31, 2015, 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 March 31, 2015, 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 and Treasurer

May 7, 2015

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 March 31, 2015, 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 March 31, 2015, 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 March 31, 2015, 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.

President and Chief Executive Officer

/s/Richard S. Teel

Richard S. Teel

Vice President and Chief Financial Officer

May 7, 2015

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 March 31, 2015, 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 March 31, 2015, 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 March 31, 2015, fairly presents, in all material respects, the financial condition and results of operations of Mississippi Power Company.

/s/G. Edison Holland, Jr.

G. Edison Holland, Jr.

Chairman, President and Chief Executive Officer

/s/Moses H. Feagin

Moses H. Feagin

Vice President, Treasurer and

Chief Financial Officer

May 7, 2015

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 March 31, 2015, 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 March 31, 2015, 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 March 31, 2015, fairly presents, in all material respects, the financial condition and results of operations of Southern Power Company.

/s/Oscar C. Harper IV

Oscar C. Harper IV

President and Chief Executive Officer

/s/William C. Grantham

William C. Grantham

Vice President, Treasurer and

Chief Financial Officer

May 7, 2015

XML

Stockholders' Equity - Changes in Stockholders' Equity (Details) (USD $) In Millions, except Share data in Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015		Mar. 31, 2014		Dec. 31, 2014
Changes in Stockholders' Equity
Beginning Balance	$ 20,926		$ 19,764
Net income after dividends on preferred and preference stock	508	[1],[2]	351	[1],[2]
Other comprehensive income (loss)	(15)		2
Treasury stock re-issued			111
Stock issued	112		53
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition	53
Stock repurchased, at cost	(115)		(4)
Cash dividends on common stock	(478)		(451)
Other	3		0
Ending Balance	20,994		19,826
Number of Common shares Issued [Member]
Changes in Stockholders' Equity
Beginning Balance, Shares	908,502		892,733
Stock issued, Shares	3,094		1,340
Ending Balance, Shares	911,596		894,073
Number of Common shares Treasury [Member]
Changes in Stockholders' Equity
Beginning Balance, Shares	725		5,647
Treasury stock re-issued, Shares			2,404
Stock repurchased, at cost, Shares	(2,599)
Other, Shares	(11)		(18)
Ending Balance, Shares	3,335		3,261
Common Stockholders' Equity [Member]
Changes in Stockholders' Equity
Beginning Balance	19,949		19,008
Net income after dividends on preferred and preference stock	508		351
Other comprehensive income (loss)	(15)		2
Treasury stock re-issued			111
Stock issued	112		53
Adjustments to Additional Paid in Capital, Share-based Compensation, Requisite Service Period Recognition	53
Stock repurchased, at cost, Shares	(2,600)
Stock repurchased, at cost	(115)		(4)
Cash dividends on common stock	(478)		(451)
Other	3		0
Ending Balance	20,017		19,070
Preferred And Preference Stock [Member]
Changes in Stockholders' Equity
Beginning Balance			756		756
Stock issued			0
Ending Balance	756		756		756
Noncontrolling Interest [Member]
Changes in Stockholders' Equity
Beginning Balance					221
Ending Balance	$ 221				$ 221
Stock Option Exercises Through December Two Thousand Seventeen [Member]
Changes in Stockholders' Equity
Stock repurchased, at cost, Shares	(20,000)

[1] Segment net income (loss) for the traditional operating companies for the three months ended March 31, 2015 and March 31, 2014 includes a $9 million pre-tax charge ($6 million after tax) and a $380 million pre-tax charge ($235 million after tax), respectively, for estimated probable losses on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

[2] After dividends on preferred and preference stock of subsidiaries.

XML

Derivatives - Pre-tax Effects of Derivatives Designated as Cash Flow Hedging Instruments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015		Mar. 31, 2014	Dec. 31, 2014
Southern Company [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	$ (218)			$ (190)
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	(117)			(118)
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	(108)			(79)
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	6	[1]		7	[1]
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	1	[2]		0	[3]
Southern Company [Member] | Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(29)		0
Southern Company [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from AOCI into Income (Effective Portion)	(2)		(2)
Alabama Power [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(58)			(52)
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	(33)			(32)
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	(26)			(21)
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	1	[1]		1	[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	0	[2]		0	[3]
Alabama Power [Member] | Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(6)		0
Alabama Power [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from AOCI into Income (Effective Portion)	(1)		(1)
Georgia Power [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(18)			(20)
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	(21)			(23)
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	(3)			(4)
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	5	[1]		6	[1]
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	1	[2]		1	[3]
Georgia Power [Member] | Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(23)		0
Georgia Power [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from AOCI into Income (Effective Portion)	(1)		(1)
Gulf Power [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(90)			(72)
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	(37)			(37)
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	(53)			(35)
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	0	[1]		0	[1]
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	0	[2]		0	[3]
Mississippi Power [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(52)			(45)
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	(26)			(26)
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	(26)			(19)
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	[1]		0	[1]
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	$ 0	[2]		$ 0	[3]

[1] Southern Company and Georgia Power include other regulatory liabilities, current in other current liabilities.

[2] 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, 2014Derivative Category and Balance SheetLocation SouthernCompany AlabamaPower GeorgiaPower GulfPower MississippiPower (in millions)Energy-related derivatives: Other regulatory assets, current $(118) $(32) $(23) $(37) $(26)Other regulatory assets, deferred (79) (21) (4) (35) (19)Other regulatory liabilities, current (a) 7 1 6 — —Other regulatory liabilities, deferred (b) — — 1 — —Total energy-related derivative gains (losses) $(190) $(52) $(20) $(72) $(45)

[3] Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.

XML

Derivatives - Balance Sheet Presentation (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			$ 6	[1]
Southern Company [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	15		21
Derivative Liability, Fair Value, Gross Liability	271		225
Southern Company [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			4
Alabama Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1		1
Derivative Liability, Fair Value, Gross Liability	73		61
Alabama Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0	[1]
Alabama Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			0
Georgia Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	12		13
Derivative Liability, Fair Value, Gross Liability	55		41
Georgia Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0	[1]
Georgia Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			0
Gulf Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Derivative Liability, Fair Value, Gross Liability	90		72
Gulf Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0	[1]
Gulf Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			0
Mississippi Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Derivative Liability, Fair Value, Gross Liability	52		45
Mississippi Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			0	[1]
Mississippi Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			0
Southern Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		5
Derivative Liability, Fair Value, Gross Liability	0		4
Southern Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset			5	[1]
Southern Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability			4
Cash Flow and Fair Value Hedging [Member] | Southern Company [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	8		8
Cash Flow and Fair Value Hedging [Member] | Southern Company [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	46		24
Cash Flow and Fair Value Hedging [Member] | Southern Company [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	7		7
Cash Flow and Fair Value Hedging [Member] | Southern Company [Member] | Interest Rate Contract [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1		1
Cash Flow and Fair Value Hedging [Member] | Southern Company [Member] | Interest Rate Contract [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	45		17
Cash Flow and Fair Value Hedging [Member] | Southern Company [Member] | Interest Rate Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	1		7
Cash Flow and Fair Value Hedging [Member] | Alabama Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Cash Flow and Fair Value Hedging [Member] | Alabama Power [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	14		8
Cash Flow and Fair Value Hedging [Member] | Alabama Power [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Cash Flow and Fair Value Hedging [Member] | Alabama Power [Member] | Interest Rate Contract [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Cash Flow and Fair Value Hedging [Member] | Alabama Power [Member] | Interest Rate Contract [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	14		8
Cash Flow and Fair Value Hedging [Member] | Alabama Power [Member] | Interest Rate Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Cash Flow and Fair Value Hedging [Member] | Georgia Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	6		6
Cash Flow and Fair Value Hedging [Member] | Georgia Power [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	31		14
Cash Flow and Fair Value Hedging [Member] | Georgia Power [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	5		5
Cash Flow and Fair Value Hedging [Member] | Georgia Power [Member] | Interest Rate Contract [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1		1
Cash Flow and Fair Value Hedging [Member] | Georgia Power [Member] | Interest Rate Contract [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	31		9
Cash Flow and Fair Value Hedging [Member] | Georgia Power [Member] | Interest Rate Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		5
Cash Flow and Fair Value Hedging [Member] | Gulf Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Cash Flow and Fair Value Hedging [Member] | Gulf Power [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Cash Flow and Fair Value Hedging [Member] | Gulf Power [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Cash Flow and Fair Value Hedging [Member] | Gulf Power [Member] | Interest Rate Contract [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Cash Flow and Fair Value Hedging [Member] | Gulf Power [Member] | Interest Rate Contract [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Cash Flow and Fair Value Hedging [Member] | Gulf Power [Member] | Interest Rate Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Cash Flow and Fair Value Hedging [Member] | Mississippi Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Cash Flow and Fair Value Hedging [Member] | Mississippi Power [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Cash Flow and Fair Value Hedging [Member] | Mississippi Power [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Cash Flow and Fair Value Hedging [Member] | Mississippi Power [Member] | Interest Rate Contract [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Cash Flow and Fair Value Hedging [Member] | Mississippi Power [Member] | Interest Rate Contract [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Cash Flow and Fair Value Hedging [Member] | Mississippi Power [Member] | Interest Rate Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Cash Flow and Fair Value Hedging [Member] | Southern Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Cash Flow and Fair Value Hedging [Member] | Southern Power [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Cash Flow and Fair Value Hedging [Member] | Southern Power [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Cash Flow and Fair Value Hedging [Member] | Southern Power [Member] | Interest Rate Contract [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Cash Flow and Fair Value Hedging [Member] | Southern Power [Member] | Interest Rate Contract [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Cash Flow and Fair Value Hedging [Member] | Southern Power [Member] | Interest Rate Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Hedging Instruments for Regulatory Purposes [Member] | Southern Company [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	7		7
Derivative Liability, Fair Value, Gross Liability	225		197
Hedging Instruments for Regulatory Purposes [Member] | Southern Company [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	6		7
Hedging Instruments for Regulatory Purposes [Member] | Southern Company [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1		0
Hedging Instruments for Regulatory Purposes [Member] | Southern Company [Member] | Energy Related Derivative [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	117	[2]	118	[2]
Hedging Instruments for Regulatory Purposes [Member] | Southern Company [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	108		79
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1		1
Derivative Liability, Fair Value, Gross Liability	59		53
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1		1
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Energy Related Derivative [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	33	[2]	32	[2]
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	26		21
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	6		7
Derivative Liability, Fair Value, Gross Liability	24		27
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	5		6
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1		1
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	21	[2]	23	[2]
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	3		4
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Derivative Liability, Fair Value, Gross Liability	90		72
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	37	[2]	37	[2]
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	53		35
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Derivative Liability, Fair Value, Gross Liability	52		45
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Other current liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	26	[2]	26	[2]
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 26		$ 19

[1] Southern Power includes current assets related to derivatives not designated as hedging instruments in "Assets from risk management activities."

[2] Georgia Power and Gulf Power include current liabilities related to derivatives designated as hedging instruments in "Liabilities from risk management activities."

XML

Contingencies and Regulatory Matters - Narrative (Details) (USD $)	3 Months Ended			12 Months Ended		0 Months Ended			1 Months Ended	6 Months Ended	12 Months Ended	18 Months Ended	1 Months Ended	0 Months Ended	1 Months Ended	0 Months Ended	1 Months Ended		12 Months Ended	25 Months Ended	0 Months Ended	1 Months Ended		12 Months Ended
	Mar. 31, 2015		Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	May 07, 2015	Feb. 27, 2015	Jan. 29, 2015	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2008	Jun. 30, 2014	May 31, 2014	Apr. 16, 2015 MW	Dec. 31, 2013	Feb. 25, 2015	Oct. 31, 2014	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2015 mi	Oct. 06, 2014	Feb. 28, 2013	Jan. 31, 2013	Dec. 31, 2010	Feb. 02, 2015	Jan. 31, 2014	Apr. 23, 2015
Loss Contingencies [Line Items]
Civil penalties under Clean Air Act, per day, per violation, minimum	$ 25,000
Civil penalties under Clean Air Act, per day, per violation, maximum	37,500
Revenues	4,183,000,000		4,644,000,000
Minimum [Member]
Loss Contingencies [Line Items]
Asset Retirement Obligation	525,000,000																			525,000,000
Maximum [Member]
Loss Contingencies [Line Items]
Asset Retirement Obligation	575,000,000																			575,000,000
Kemper IGCC [Member]
Loss Contingencies [Line Items]
Pre-tax charge to income	9,000,000		380,000,000	868,000,000	1,200,000,000
After tax charge to income	6,000,000		235,000,000	536,000,000	729,000,000
Unrecognized Tax Benefits	211,000,000																			211,000,000
Subsequent Event [Member]
Loss Contingencies [Line Items]
Period To Meet Market-based Rate Standards						60 days
Georgia Power [Member]
Loss Contingencies [Line Items]
Environmental Exit Costs, Assets Previously Disposed, Liability for Remediation	27,000,000																			27,000,000
Civil penalties per day violation rate	37,500																			37,500
Number of times of punitive damages in comparison to cost incurred by Environmental Protection Agency	3																			3
Claims Awarded to Companies Related to Nuclear Fuel Disposal Litigation									18,000,000
Additional Construction Capital Costs										200,000,000		2,800,000,000
Percentage of Proportionate Share Owed in Consortium Agreement	45.70%
Reduction in projected in-service cost due to recovered cost											425,000,000
Increase (Decrease) In Projected Certified Construction Capital Costs	5.00%
Delay Of Estimated In-service Date							18 months	18 months
Revenues	1,978,000,000		2,269,000,000
Georgia Power [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Damages In Connection With Counterclaim													113,000,000
Estimated In-service Capital Cost	4,400,000,000				4,400,000,000
Asset Retirement Obligation	10,000,000																			10,000,000
Georgia Power [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Additional Construction Capital Costs											114,000,000
Estimated In-service Capital Cost					4,800,000,000
Asset Retirement Obligation	20,000,000																			20,000,000
Georgia Power [Member] | Other deferred charges and assets [Member]
Loss Contingencies [Line Items]
Fuel cost recovery balance	151,000,000			199,000,000					199,000,000	199,000,000										151,000,000
Georgia Power [Member] | Plant Vogtle Units 3 And 4 [Member]
Loss Contingencies [Line Items]
Estimated In-service Capital Cost							5,000,000,000
Monthly Operational Readiness Costs							10,000,000
Monthly Financing Costs	30,000,000
Construction Financing Costs	2,500,000,000
Georgia Power [Member] | Subsequent Event [Member] | Plant Branch Units 1 and 3 and 4 [Member]
Loss Contingencies [Line Items]
Capacity Of Units Included In Request For Decertification Of Units (in MWs)														1,266
Georgia Power [Member] | Subsequent Event [Member] | Plant Yates Units 1 through 5 [Member]
Loss Contingencies [Line Items]
Capacity Of Units Included In Request For Decertification Of Units (in MWs)														579
Georgia Power [Member] | Subsequent Event [Member] | Plant McManus Units 1 and 2 [Member]
Loss Contingencies [Line Items]
Capacity Of Units Included In Request For Decertification Of Units (in MWs)														122
Georgia Power [Member] | Subsequent Event [Member] | Plant Mitchell Unit 3 [Member]
Loss Contingencies [Line Items]
Electric Generating Units, Capacity (in MW's)														155
Gulf Power [Member]
Loss Contingencies [Line Items]
Environmental Exit Costs, Assets Previously Disposed, Liability for Remediation	47,000,000																			47,000,000
Reduction In Depreciation Expense															62,500,000
Reduction In Depreciation Expense Year One	19,600,000
Number Of Regulatory Clauses	4
Ownership percentage in scrubber project																			50.00%
Revenues	357,000,000		407,000,000
Gulf Power [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Asset Retirement Obligation	70,000,000																			70,000,000
Gulf Power [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Asset Retirement Obligation	80,000,000																			80,000,000
Mississippi Power [Member]
Loss Contingencies [Line Items]
Environmental Exit Costs, Assets Previously Disposed, Liability for Remediation	500,000																			500,000
Psc Approved Annual Property Damage Reserve Accrual																									3,000,000
Ownership percentage in scrubber project																			50.00%
Estimated cost of scrubber project																			330,000,000
Scrubber project expenditures amount	290,000,000																			290,000,000
Allowance For Funds Used During Construction Cost	22,000,000
Revenues	276,000,000		331,000,000													8,000,000
Over Recovered Fuel Cost	15,000,000																			15,000,000
Under recovered regulatory clause revenues				2,000,000					2,000,000	2,000,000
Plant Capacity Under Coal Gasification Combined Cycle Technology (in MWs)	582
Co Two Pipeline Infrastructure (in miles)	61																			61
Costs associated with CCP12 grant funds																			245,000,000
Other Property And Investments	2,000,000																			2,000,000
Lignite Mining Costs	52,000,000																			52,000,000
Materials, Supplies, and Other	35,000,000																			35,000,000
Cost deferred in other regulatory assets	174,000,000																			174,000,000
Other deferred charges and assets	12,000,000																			12,000,000
Previously expensed	1,000,000																			1,000,000
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																				294,000,000
Reduced percentage interest transferred under asset purchase agreement																		15.00%	15.00%
Percentage of Carbon Dioxide Captured from Project	70.00%																			70.00%
Percentage of Contract to Purchase Carbon Dioxide from Project	30.00%																			30.00%
Purchase of Interest																			17.50%					17.50%
Capacity Revenues Under Power Supply Agreement	4,000,000			17,000,000
Deposit received																			150,000,000							75,000,000
Interest Bearing Refundable Deposit Related to Asset Sale	0		75,000,000														50,000,000
Maximum period of discretion in the event senior unsecured credit rating falls	15 days
Internal Revenue Code Section Forty Eight Tax Credits Phase I I	279,000,000
Tax Credit Carryforward, Amount	276,000,000																			276,000,000
Tax Credit Carryforward Utilized	207,000,000																			207,000,000
Minimum percentage of carbon dioxide that must be capture and sequester to remain eligible for the phase II tax credits	65.00%
Mississippi Power [Member] | Mirror Construction Work In Progress [Member]
Loss Contingencies [Line Items]
Net Regulatory Assets	(311,000,000)																			(311,000,000)
Mississippi Power [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Asset Retirement Obligation	75,000,000																			75,000,000
Costs Due To Extension Of In-service Date	25,000,000
Mississippi Power [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Asset Retirement Obligation	85,000,000																			85,000,000
Costs Due To Extension Of In-service Date	30,000,000
Mississippi Power [Member] | Construction in Progress [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	2,060,000,000																			2,060,000,000
Mississippi Power [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Electric Generating Units, Capacity (in MW's)																		75
Estimated Cost	4,370,000,000	[1]																	2,880,000,000
Asset Retirement Obligation	24,000,000																			24,000,000
Pre-tax charge to income	9,000,000			868,000,000	1,100,000,000														78,000,000
After tax charge to income	6,000,000			536,000,000	681,000,000														48,000,000
Monthly Charge Of Allowance For Equity Funds Used During Construction	13,000,000
Monthly Cost Regulatory Assets Deferred	6,000,000
Regulatory Liabilities For Plant Construction																				294,000,000
Maximum Cap Construction Cost	5,400,000,000	[1],[2]
Regulatory Assets	174,000,000																			174,000,000
Projected Balance Of Regulatory Assets	266,000,000																			266,000,000
Purchase of Interest																					15.00%
Acquisition Period For SMEPA																					180 days
Unrecognized Tax Benefits	211,000,000																			211,000,000
Mississippi Power [Member] | Kemper IGCC [Member] | Current Estimate [Member]
Loss Contingencies [Line Items]
Estimated Cost	4,940,000,000	[1]
Maximum Cap Construction Cost	6,220,000,000	[1],[2]
Mississippi Power [Member] | Kemper IGCC [Member] | Property, Plant and Equipment [Member]
Loss Contingencies [Line Items]
Estimated Cost	3,270,000,000
Mississippi Power [Member] | Electricity Generation Plant, Non-Nuclear [Member]
Loss Contingencies [Line Items]
Estimated Cost																							2,400,000,000
Alternate Financing																						1,000,000,000
Mississippi Power [Member] | Mine [Member]
Loss Contingencies [Line Items]
Term of Management Fee Contract																								40 years
Mississippi Power [Member] | Subsequent Event [Member]
Loss Contingencies [Line Items]
AFUDC Cost						12,000,000
Percentage Of PSC Retail Rate Increase (Decrease)																											(0.35%)
PSC Retail Rate Increase (Decrease)																											(2,000,000)
Mississippi Power [Member] | Subsequent Event [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
AFUDC Cost						9,000,000
Alabama Power [Member]
Loss Contingencies [Line Items]
Claims Awarded to Companies Related to Nuclear Fuel Disposal Litigation									26,000,000
Non-environmental Costs	14,000,000
Recovery Of Non-environmental Costs	50,000,000
Revenues	1,401,000,000		1,508,000,000
Alabama Power [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Asset Retirement Obligation	330,000,000																			330,000,000
Alabama Power [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Asset Retirement Obligation	350,000,000																			350,000,000
Gulf Power and Mississippi Power [Member]
Loss Contingencies [Line Items]
Estimated cost of scrubber project																			660,000,000
Scrubber project expenditures amount	$ 570,000,000																			$ 570,000,000

[1] The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and 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" for additional information.

[2] Amounts in the Current Estimate reflect estimated costs through March 31, 2016.

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Retirement Benefits (Tables)

3 Months Ended

Mar. 31, 2015

Compensation and Retirement Disclosure [Abstract]

Pension Plans and Postretirement Plans

Components of the net periodic benefit costs for the three months ended March 31, 2015 and 2014 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended March 31, 2015
Service cost	$	64		$	15		$	18		$	3		$	3
Interest cost	111			26			38			5			5
Expected return on plan assets	(181		)	(45		)	(63		)	(8		)	(8		)
Amortization:
Prior service costs	6			2			3			—			—
Net (gain)/loss	54			14			19			3			3
Net cost	$	54		$	12		$	15		$	3		$	3
Three Months Ended March 31, 2014
Service cost	$	53		$	12		$	16		$	3		$	3
Interest cost	109			26			38			5			5
Expected return on plan assets	(161		)	(42		)	(57		)	(7		)	(7		)
Amortization:
Prior service costs	6			1			3			—			—
Net (gain)/loss	28			8			10			1			1
Net cost	$	35		$	5		$	10		$	2		$	2

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power
	(in millions)
Three Months Ended March 31, 2015
Service cost	$	6		$	1		$	2		$	—	$	—
Interest cost	19			5			8			1		1
Expected return on plan assets	(15		)	(6		)	(6		)	—		—
Amortization:
Prior service costs	1			1			—			—		—
Net (gain)/loss	5			—			3			—		—
Net cost	$	16		$	1		$	7		$	1	$	1
Three Months Ended March 31, 2014
Service cost	$	5		$	1		$	2		$	—	$	—
Interest cost	20			5			8			1		1
Expected return on plan assets	(15		)	(6		)	(6		)	—		—
Amortization:
Prior service costs	1			1			—			—		—
Net (gain)/loss	1			—			—			—		—
Net cost	$	12		$	1		$	4		$	1	$	1

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Acquisitions (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended	1 Months Ended	0 Months Ended
	Feb. 19, 2015	Mar. 31, 2015	Feb. 24, 2015	Mar. 12, 2015	Apr. 15, 2015	Apr. 22, 2015	Apr. 30, 2015
Southern Power [Member] | Decatur Parkway Solar Project, LLC [Member]
Business Acquisition [Line Items]
Power of solar polycrystalline silicon facility (in MWs)	80
Life Output Of Plant	25 years
Southern Power [Member] | Decatur County Solar Project, LLC [Member]
Business Acquisition [Line Items]
Power of solar polycrystalline silicon facility (in MWs)	19
Life Output Of Plant	20 years
Southern Power [Member] | Decatur County Solar Projects [Member]
Business Acquisition [Line Items]
Beginning Year Of Output Of Constructed Plant	2015
Construction Capital Costs		$ 32
Southern Power [Member] | Decatur County Solar Projects [Member] | Minimum [Member]
Business Acquisition [Line Items]
Estimated Cost	200
Southern Power [Member] | Decatur County Solar Projects [Member] | Maximum [Member]
Business Acquisition [Line Items]
Estimated Cost	220
Southern Power [Member] | Kay Wind, LLC [Member]
Business Acquisition [Line Items]
Beginning Year Of Output Of Constructed Plant			2015
Life Output Of Plant			20 years
Energy From Wind-Powered Generating Facilities (in MWs)			299
Acquisition - cash consideration			492
Southern Power [Member] | Butler Solar LLC [Member]
Business Acquisition [Line Items]
Power of solar polycrystalline silicon facility (in MWs)				100
Beginning Year Of Output Of Constructed Plant				2016
Life Output Of Plant				30 years
Southern Power [Member] | Butler Solar LLC [Member] | Minimum [Member]
Business Acquisition [Line Items]
Estimated Cost				220
Southern Power [Member] | Butler Solar LLC [Member] | Maximum [Member]
Business Acquisition [Line Items]
Estimated Cost				230
Southern Power [Member] | Lost Hills Blackwell Holdings, LLC [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Beginning Year Of Output Of Constructed Plant					2015
Life Output Of Plant					29 years
Acquisition - cash consideration					74
Southern Power [Member] | Lost Hills Blackwell Holdings, LLC [Member] | Class A Membership Interest [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent					100.00%
Percentage Of Entitled Cash Distributions					51.00%
Southern Power [Member] | Lost Hills Solar Facility [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Power of solar polycrystalline silicon facility (in MWs)					20
Southern Power [Member] | Blackwell Solar Facility [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Power of solar polycrystalline silicon facility (in MWs)					12
Southern Power [Member] | LS Pawpaw, LLC [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Power of solar polycrystalline silicon facility (in MWs)						30
Beginning Year Of Output Of Constructed Plant						2015
Life Output Of Plant						30 years
Southern Power [Member] | LS Pawpaw, LLC [Member] | Minimum [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Estimated Cost						65
Southern Power [Member] | LS Pawpaw, LLC [Member] | Maximum [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Estimated Cost						75
Southern Power [Member] | North Star [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Power of solar polycrystalline silicon facility (in MWs)							60
Beginning Year Of Output Of Constructed Plant							2015
Life Output Of Plant							20 years
Acquisition - cash consideration							208
Southern Power [Member] | North Star [Member] | Class A Membership Interest [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent							100.00%
Percentage Of Entitled Cash Distributions							51.00%
First Solar [Member] | Lost Hills Blackwell Holdings, LLC [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Acquisition - cash consideration					34
First Solar [Member] | Lost Hills Blackwell Holdings, LLC [Member] | Class B Membership Interest [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent					100.00%
Percentage Of Entitled Cash Distributions					49.00%
First Solar [Member] | North Star [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Acquisition - cash consideration							$ 99
First Solar [Member] | North Star [Member] | Class B Membership Interest [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent							100.00%
Percentage Of Entitled Cash Distributions							49.00%

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Financing - Narrative (Details) (USD $)	0 Months Ended
	May 15, 2015	May 07, 2015 loan	Mar. 31, 2015
Debt Instrument [Line Items]
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support			$ 1,800,000,000
Alabama Power [Member]
Debt Instrument [Line Items]
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support			864,000,000
Amount of Fixed Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support			200,000,000
Alabama Power [Member] | Scenario, Plan [Member] | Five Point Two Zero Percent Class A Preferred Stock [Member]
Debt Instrument [Line Items]
Temporary Equity, Shares Outstanding	6,480,000
Temporary Equity, Dividend Rate Percentage	0.052
Temporary Equity, Par or Stated Value Per Share	$ 25
Alabama Power [Member] | Scenario, Plan [Member] | Five Point Three Zero Percent Class A Preferred Stock [Member]
Debt Instrument [Line Items]
Temporary Equity, Shares Outstanding	4,000,000
Temporary Equity, Dividend Rate Percentage	0.053
Temporary Equity, Par or Stated Value Per Share	$ 25
Alabama Power [Member] | Scenario, Plan [Member] | Five Point Six Two Five Percent Preference Stock [Member]
Debt Instrument [Line Items]
Temporary Equity, Shares Outstanding	6,000,000
Temporary Equity, Dividend Rate Percentage	0.05625
Temporary Equity, Par or Stated Value Per Share	$ 25
Alabama Power [Member] | Aggregate Stated Capital [Member] | Scenario, Plan [Member] | Five Point Two Zero Percent Class A Preferred Stock [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	162,000,000
Alabama Power [Member] | Aggregate Stated Capital [Member] | Scenario, Plan [Member] | Five Point Three Zero Percent Class A Preferred Stock [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	100,000,000
Alabama Power [Member] | Aggregate Stated Capital [Member] | Scenario, Plan [Member] | Five Point Six Two Five Percent Preference Stock [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	150,000,000
Alabama Power [Member] | Senior Notes [Member] | Series 2015A [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			550,000,000
Debt Instrument, Interest Rate, Stated Percentage			3.75%
Alabama Power [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Redemption Amount Of Principal Notes			250,000,000
Alabama Power [Member] | Series DD [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			5.65%
Alabama Power [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Long-term Pollution Control Bond		80,000,000
Alabama Power [Member] | Subsequent Event [Member] | Series 2007B [Member]
Debt Instrument [Line Items]
Long-term Pollution Control Bond		80,000,000
Alabama Power [Member] | Subsequent Event [Member] | Senior Notes [Member] | Series 2015A [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		175,000,000
Debt Instrument, Interest Rate, Stated Percentage		3.75%
Alabama Power [Member] | Subsequent Event [Member] | Senior Notes [Member] | Series 2015B [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		250,000,000
Debt Instrument, Interest Rate, Stated Percentage		2.80%
Georgia Power [Member]
Debt Instrument [Line Items]
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support			865,000,000
Amount of Fixed Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support			118,000,000
Georgia Power [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Long-term Pollution Control Bond		65,000,000
Georgia Power [Member] | Subsequent Event [Member] | Second Series 2008 [Member]
Debt Instrument [Line Items]
Long-term Pollution Control Bond		65,000,000
Gulf Power [Member]
Debt Instrument [Line Items]
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support			69,000,000
Amount of Fixed Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support			78,000,000
Mississippi Power [Member]
Debt Instrument [Line Items]
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support			40,000,000
Mississippi Power [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Number Of Floating Rate Bank Loans		3
Aggregate Principal Amount Of Floating Rate Bank Loan		475,000,000
Debt Instrument, Description of Variable Rate Basis		one-month LIBOR
Repayment Aggregate Principal Amount Of Floating Rate Bank Loan		275,000,000
Mississippi Power [Member] | Subsequent Event [Member] | Maturity April First Two Thousand Sixteen [Member]
Debt Instrument [Line Items]
Number Of Floating Rate Bank Loans		2
Aggregate Principal Amount Of Floating Rate Bank Loan		425,000,000
Traditional Operating Companies [Member]
Debt Instrument [Line Items]
Amount of Fixed Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support			$ 396,000,000

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Fair Value Measurements - Narrative (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds including reinvested interest and dividends	$ 65
Georgia Power [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Notices Of Withdrawal Foreign Equity Funds	20.00%
Increase (decrease) in fair value of funds including reinvested interest and dividends	18
Georgia Power [Member] | Other - commingled funds [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Maximum Number of Days Related to Dollar Weighted Average Portfolio Maturities Regarding Commingled Funds	90 days
Georgia Power [Member] | Minimum [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Withdrawal Of Foreign Equity Fund Investment	1
Foreign Equity Fund Investment	10
Alabama Power [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds including reinvested interest and dividends	$ 47

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Segment and Related Information - Financial Data for Products and Services (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	$ 4,172	$ 4,627
Retail [Member]
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	3,542	3,858
Wholesale [Member]
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	467	604
Other [Member]
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	$ 163	$ 165

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Derivatives - Balance Sheet Offsetting (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
Southern Company [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 15		$ 21
Derivative Liability, Fair Value, Gross Liability	271		225
Southern Company [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	1		4
Derivative Liability, Fair Value, Amount Offset Against Collateral	219		192
Southern Company [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	7	[1]	13	[1]
Derivative Liability, Fair Value, Gross Liability	225	[1]	201	[1]
Southern Company [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(6)	[2]	(9)	[2]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(6)	[2]	(9)	[2]
Southern Company [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	6		0
Derivative Liability, Fair Value, Amount Offset Against Collateral	44		16
Southern Company [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	8	[1]	8	[1]
Derivative Liability, Fair Value, Gross Liability	46	[1]	24	[1]
Southern Company [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(2)	[2]	(8)	[2]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(2)	[2]	(8)	[2]
Alabama Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1		1
Derivative Liability, Fair Value, Gross Liability	73		61
Alabama Power [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	0		1
Derivative Liability, Fair Value, Amount Offset Against Collateral	58		53
Alabama Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	1	[1]	1	[1]
Derivative Liability, Fair Value, Gross Liability	59	[1]	53	[1]
Alabama Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(1)	[2]	0	[2]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(1)	[2]	0	[2]
Alabama Power [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	0		0
Derivative Liability, Fair Value, Amount Offset Against Collateral	14		8
Alabama Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[1]	0	[1]
Derivative Liability, Fair Value, Gross Liability	14	[1]	8	[1]
Alabama Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	[2]	0	[2]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	[2]	0	[2]
Georgia Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	12		13
Derivative Liability, Fair Value, Gross Liability	55		41
Georgia Power [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	0		0
Derivative Liability, Fair Value, Amount Offset Against Collateral	18		20
Georgia Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	6	[1]	7	[1]
Derivative Liability, Fair Value, Gross Liability	24	[1]	27	[1]
Georgia Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(6)	[2]	(7)	[2]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(6)	[2]	(7)	[2]
Georgia Power [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	4		0
Derivative Liability, Fair Value, Amount Offset Against Collateral	29		8
Georgia Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	6	[1]	6	[1]
Derivative Liability, Fair Value, Gross Liability	31	[1]	14	[1]
Georgia Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(2)	[2]	(6)	[2]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(2)	[2]	(6)	[2]
Gulf Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Derivative Liability, Fair Value, Gross Liability	90		72
Gulf Power [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	0		0
Derivative Liability, Fair Value, Amount Offset Against Collateral	90		72
Gulf Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[1]	0	[1]
Derivative Liability, Fair Value, Gross Liability	90	[1]	72	[1]
Gulf Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	[2]	0	[2]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	[2]	0	[2]
Gulf Power [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	0		0
Derivative Liability, Fair Value, Amount Offset Against Collateral	0		0
Gulf Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[1]	0	[1]
Derivative Liability, Fair Value, Gross Liability	0	[1]	0	[1]
Gulf Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	[2]	0	[2]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	[2]	0	[2]
Mississippi Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Derivative Liability, Fair Value, Gross Liability	52		45
Mississippi Power [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	0		0
Derivative Liability, Fair Value, Amount Offset Against Collateral	52		45
Mississippi Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[1]	0	[1]
Derivative Liability, Fair Value, Gross Liability	52	[1]	45	[1]
Mississippi Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	[2]	0	[2]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	[2]	0	[2]
Mississippi Power [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	0		0
Derivative Liability, Fair Value, Amount Offset Against Collateral	0		0
Mississippi Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[1]	0	[1]
Derivative Liability, Fair Value, Gross Liability	0	[1]	0	[1]
Mississippi Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	[2]	0	[2]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	[2]	0	[2]
Southern Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		5
Derivative Liability, Fair Value, Gross Liability	0		4
Southern Power [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	0		5
Derivative Liability, Fair Value, Amount Offset Against Collateral	0		4
Southern Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[1]	5	[1]
Derivative Liability, Fair Value, Gross Liability	0	[1]	4	[1]
Southern Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	[2]	0	[2]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0	[2]	0	[2]
Southern Power [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	0		0
Derivative Liability, Fair Value, Amount Offset Against Collateral	0		0
Southern Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[1]	0	[1]
Derivative Liability, Fair Value, Gross Liability	0	[1]	0	[1]
Southern Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	[2]	0	[2]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ 0	[2]	$ 0	[2]

[1] 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.

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

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Introduction

3 Months Ended

Mar. 31, 2015

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, 2014 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 three-month periods ended March 31, 2015 and 2014. 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.

On February 6, 2015, Gulf Power announced plans to retire its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) by March 31, 2016. In connection with this retirement, Gulf Power reclassified the net carrying value of these units from plant in service, net of depreciation, to other utility plant, net at March 31, 2015. Gulf Power expects to recover through its rates the remaining book value of the retired units and certain costs associated with the retirements; however, recovery will be considered by the Florida PSC in future rate proceedings.

Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board (FASB) issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition. On April 29, 2015, the FASB issued an exposure draft proposing the standard be effective for fiscal years beginning after December 15, 2017. The registrants continue to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

On February 18, 2015, the FASB issued Accounting Standards Update (ASU) 2015-02, Amendments to the Consolidation Analysis, which makes certain changes to both the variable interest model and the voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. This ASU is effective for fiscal years beginning after December 15, 2015. Southern Power is currently evaluating these requirements. The ultimate impact of this ASU on Southern Power has not yet been determined.

On April 7, 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Company currently reflects unamortized debt issuance costs in unamortized debt issuance expense on its balance sheet. The traditional operating companies and Southern Power currently reflect unamortized debt issuance costs in other deferred charges and assets on their balance sheets. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of any registrant.

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.

On April 17, 2015, the EPA published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule) in the Federal Register, setting October 14, 2015 as the effective date of the CCR Rule. The ultimate impact of the CCR Rule cannot be determined at this timeand will depend on the traditional operating companies' ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges.

In the second quarter 2015, Southern Company and the traditional operating companies expect to record incremental asset retirement obligations (ARO) related to the CCR Rule in amounts currently estimated to fall within the following ranges:

	Low		High
	(in millions)
Southern Company	$	525	$	575
Alabama Power	$	330	$	350
Georgia Power	$	10	$	20
Gulf Power	$	70	$	80
Mississippi Power	$	75	$	85

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Retirement Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Pension Plans [Member] | Southern Company [Member]
Pension Plans and Postretirement Plans
Service cost	$ 64	$ 53
Interest cost	111	109
Expected return on plan assets	(181)	(161)
Amortization:
Prior service costs	6	6
Net (gain)/loss	54	28
Net cost	54	35
Pension Plans [Member] | Alabama Power [Member]
Pension Plans and Postretirement Plans
Service cost	15	12
Interest cost	26	26
Expected return on plan assets	(45)	(42)
Amortization:
Prior service costs	2	1
Net (gain)/loss	14	8
Net cost	12	5
Pension Plans [Member] | Georgia Power [Member]
Pension Plans and Postretirement Plans
Service cost	18	16
Interest cost	38	38
Expected return on plan assets	(63)	(57)
Amortization:
Prior service costs	3	3
Net (gain)/loss	19	10
Net cost	15	10
Pension Plans [Member] | Gulf Power [Member]
Pension Plans and Postretirement Plans
Service cost	3	3
Interest cost	5	5
Expected return on plan assets	(8)	(7)
Amortization:
Prior service costs	0	0
Net (gain)/loss	3	1
Net cost	3	2
Pension Plans [Member] | Mississippi Power [Member]
Pension Plans and Postretirement Plans
Service cost	3	3
Interest cost	5	5
Expected return on plan assets	(8)	(7)
Amortization:
Prior service costs	0	0
Net (gain)/loss	3	1
Net cost	3	2
Other Postretirement Benefits [Member] | Southern Company [Member]
Pension Plans and Postretirement Plans
Service cost	6	5
Interest cost	19	20
Expected return on plan assets	(15)	(15)
Amortization:
Prior service costs	1	1
Net (gain)/loss	5	1
Net cost	16	12
Other Postretirement Benefits [Member] | Alabama Power [Member]
Pension Plans and Postretirement Plans
Service cost	1	1
Interest cost	5	5
Expected return on plan assets	(6)	(6)
Amortization:
Prior service costs	1	1
Net (gain)/loss	0	0
Net cost	1	1
Other Postretirement Benefits [Member] | Georgia Power [Member]
Pension Plans and Postretirement Plans
Service cost	2	2
Interest cost	8	8
Expected return on plan assets	(6)	(6)
Amortization:
Prior service costs	0	0
Net (gain)/loss	3	0
Net cost	7	4
Other Postretirement Benefits [Member] | Gulf Power [Member]
Pension Plans and Postretirement Plans
Service cost	0	0
Interest cost	1	1
Expected return on plan assets	0	0
Amortization:
Prior service costs	0	0
Net (gain)/loss	0	0
Net cost	1	1
Other Postretirement Benefits [Member] | Mississippi Power [Member]
Pension Plans and Postretirement Plans
Service cost	0	0
Interest cost	1	1
Expected return on plan assets	0	0
Amortization:
Prior service costs	0	0
Net (gain)/loss	0	0
Net cost	$ 1	$ 1

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Introduction - Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015
Minimum [Member]
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation	$ 525
Minimum [Member] | Alabama Power [Member]
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation	330
Minimum [Member] | Georgia Power [Member]
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation	10
Minimum [Member] | Gulf Power [Member]
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation	70
Minimum [Member] | Mississippi Power [Member]
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation	75
Maximum [Member]
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation	575
Maximum [Member] | Alabama Power [Member]
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation	350
Maximum [Member] | Georgia Power [Member]
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation	20
Maximum [Member] | Gulf Power [Member]
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation	80
Maximum [Member] | Mississippi Power [Member]
Property, Plant and Equipment [Line Items]
Asset Retirement Obligation	$ 85

XML

Introduction - Narrative (Details) (Plant Smith Units 1 and 2 [Member], Gulf Power [Member])	0 Months Ended
	Feb. 06, 2015 MW
Plant Smith Units 1 and 2 [Member] | Gulf Power [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Capacity Of Units Included In Request For Decertification Of Units (in MWs)	357

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Effective Tax Rate and Unrecognized Tax Benefits - Narrative (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Income Tax Contingency [Line Items]
Effective tax rate	34.30%	32.30%
Kemper Igcc [Member]
Income Tax Contingency [Line Items]
Unrecognized tax benefit	211
Unrecognized tax benefit, associated interest	3
Mississippi Power [Member]
Income Tax Contingency [Line Items]
Effective tax rate	10.00%	(43.00%)
Mississippi Power [Member] | Kemper Igcc [Member]
Income Tax Contingency [Line Items]
Unrecognized tax benefit	211
Unrecognized tax benefit, associated interest	3
Southern Power [Member]
Income Tax Contingency [Line Items]
Effective tax rate	25.80%	8.50%

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Contingencies and Regulatory Matters - Retail Regulatory Matters (Details) (Alabama Power [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
Deferred Under Recovered Regulatory Clause Revenues [Member]
Loss Contingencies [Line Items]
Under Recovered Rate Cnp Balance	$ 25	[1]	$ 2	[1]
Rate Cnp Power Purchase Agreement	62		29
Under Recovered Regulatory Clause Revenues [Member]
Loss Contingencies [Line Items]
Under Recovered Rate Cnp Balance, Current	16		47
Rate Cnp Power Purchase Agreement	0		27
Deferred Over Recovered Regulatory Clause Revenues [Member]
Loss Contingencies [Line Items]
Retail Energy Cost Recovery - Over	81		47
Other regulatory liabilities deferred [Member]
Loss Contingencies [Line Items]
Accumulated reserve balance for future storms	$ 82		$ 84

[1] Formerly Known As Rate CNP Environmental

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Contingencies and Regulatory Matters - Cost Recovery Clause (Details) (Under Recovered Regulatory Clause Revenues [Member], Gulf Power [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Under Recovered Regulatory Clause Revenues [Member] | Gulf Power [Member]
Loss Contingencies [Line Items]
Under Recovered Fuel Cost	$ 32	$ 40
Under Recovered Purchased Power Capacity Costs	3	0
Under Recovered Environmental Cost	12	10
Under Recovered Energy Conservation Costs	$ 1	$ 3

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Southern Company [Member]
Common stock, par value (in dollars per share)	$ 5	$ 5
Common stock, shares authorized	1,500,000,000	1,500,000,000
Common stock, shares issued	912,000,000	909,000,000
Treasury shares at cost	3,300,000	700,000
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	5,442,717
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	$ 9	$ 8
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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Contingencies and Regulatory Matters - Current And Actual Cost Estimate (Details) (Mississippi Power [Member], USD $)	0 Months Ended	3 Months Ended		12 Months Ended
	May 07, 2015	Mar. 31, 2015		Dec. 31, 2012
Subsequent Event [Member]
Loss Contingencies [Line Items]
AFUDC Cost	$ 12,000,000
Kemper Igcc [Member]
Loss Contingencies [Line Items]
Estimated Cost		4,370,000,000	[1]	2,880,000,000
Cost Of Lignite Mine And Equipment		230,000,000
CO2 Pipeline Facilities		100,000,000
Cost Of AFUDC		480,000,000	[2],[3]
Combined Cycle And Related Assets Placed In Service, Incremental		0	[4]
General Exceptions		80,000,000
Deferred Costs		140,000,000	[3],[5]
Maximum Cap Construction Cost		5,400,000,000	[1],[3]
Kemper Igcc [Member] | Subsequent Event [Member]
Loss Contingencies [Line Items]
AFUDC Cost	9,000,000
Project Estimate [Member] | Kemper Igcc [Member]
Loss Contingencies [Line Items]
Estimated Cost		2,400,000,000	[1],[6]
Cost Of Lignite Mine And Equipment		210,000,000	[6]
CO2 Pipeline Facilities		140,000,000	[6]
Cost Of AFUDC		170,000,000	[2],[3],[6]
Combined Cycle And Related Assets Placed In Service, Incremental		0	[4],[6]
General Exceptions		50,000,000	[6]
Deferred Costs		0	[3],[5],[6]
Maximum Cap Construction Cost		2,970,000,000	[1],[3],[6]
Current Estimate [Member] | Kemper Igcc [Member]
Loss Contingencies [Line Items]
Estimated Cost		4,940,000,000	[1]
Cost Of Lignite Mine And Equipment		230,000,000
CO2 Pipeline Facilities		110,000,000
Cost Of AFUDC		640,000,000	[2],[3]
Combined Cycle And Related Assets Placed In Service, Incremental		20,000,000	[4]
General Exceptions		100,000,000
Deferred Costs		180,000,000	[3],[5]
Maximum Cap Construction Cost		$ 6,220,000,000	[1],[3]

[1] The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and 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" for additional information.

[2] Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate includes an approximately $9 million increase in AFUDC related to a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.

[3] Amounts in the Current Estimate reflect estimated costs through March 31, 2016.

[4] Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information.

[5] The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities."

[6] The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC.

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Financing - Schedule of Credit Arrangements (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015
Line of Credit Facility [Line Items]
Expires, 2015	$ 478
Expires, 2016	565
Expires, 2017	30
Expires, 2018	4,130
Total	5,203
Unused	5,147
Executable Term Loans, One Year	153
Executable Term Loans, Two Years	40
Due Within One Year, Term Out	193
Due Within One Year, No Term Out	800
Southern Company [Member]
Line of Credit Facility [Line Items]
Expires, 2015	0
Expires, 2016	0
Expires, 2017	0
Expires, 2018	1,000
Total	1,000
Unused	1,000
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, 2015	228
Expires, 2016	50
Expires, 2017	0
Expires, 2018	1,030
Total	1,308
Unused	1,308
Executable Term Loans, One Year	58
Executable Term Loans, Two Years	0
Due Within One Year, Term Out	58
Due Within One Year, No Term Out	170
Georgia Power [Member]
Line of Credit Facility [Line Items]
Expires, 2015	0
Expires, 2016	150
Expires, 2017	0
Expires, 2018	1,600
Total	1,750
Unused	1,736
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	150
Gulf Power [Member]
Line of Credit Facility [Line Items]
Expires, 2015	45
Expires, 2016	200
Expires, 2017	30
Expires, 2018	0
Total	275
Unused	275
Executable Term Loans, One Year	50
Executable Term Loans, Two Years	0
Due Within One Year, Term Out	50
Due Within One Year, No Term Out	195
Mississippi Power [Member]
Line of Credit Facility [Line Items]
Expires, 2015	135
Expires, 2016	165
Expires, 2017	0
Expires, 2018	0
Total	300
Unused	270
Executable Term Loans, One Year	25
Executable Term Loans, Two Years	40
Due Within One Year, Term Out	65
Due Within One Year, No Term Out	235
Southern Power [Member]
Line of Credit Facility [Line Items]
Expires, 2015	0
Expires, 2016	0
Expires, 2017	0
Expires, 2018	500
Total	500
Unused	488
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 Subsidiaries [Member]
Line of Credit Facility [Line Items]
Expires, 2015	70
Expires, 2016	0
Expires, 2017	0
Expires, 2018	0
Total	70
Unused	70
Executable Term Loans, One Year	20
Executable Term Loans, Two Years	0
Due Within One Year, Term Out	20
Due Within One Year, No Term Out	$ 50

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Condensed Consolidated Statements of Income (Unaudited) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2015		Mar. 31, 2014
Operating Revenues:
Total operating revenues	$ 4,183		$ 4,644
Other Income and (Expense):
Net Income (Loss) After Dividends on Preferred and Preference Stock of Subsidiaries	508	[1],[2]	351	[1],[2]
Southern Company [Member]
Operating Revenues:
Retail revenues	3,542		3,858
Wholesale revenues	467		604
Other electric revenues	163		165
Other revenues	11		17
Total operating revenues	4,183		4,644
Operating Expenses:
Fuel	1,212		1,647
Purchased power	144		187
Other operations and maintenance	1,122		986
Depreciation and amortization	487		497
Taxes other than income taxes	252		247
Estimated loss on Kemper IGCC	9		380
Total operating expenses	3,226		3,944
Operating Income (Loss)	957		700
Other Income and (Expense):
Allowance for equity funds used during construction	63		57
Interest expense, net of amounts capitalized	(213)		(206)
Other income (expense), net	(8)		(7)
Total other income and (expense)	(158)		(156)
Earnings (Loss) Before Income Taxes	799		544
Income taxes (benefit)	274		176
Net Income (Loss)	525		368
Dividends on preferred and preference stock of subsidiaries	17		17
Net Income (Loss) After Dividends on Preferred and Preference Stock of Subsidiaries	508		351
Earnings per share (EPS) -
Basic EPS (in dollars per share)	$ 0.56		$ 0.39
Diluted EPS (in dollars per share)	$ 0.56		$ 0.39
Average number of shares of common stock outstanding (in millions)
Basic (in shares)	910		890
Diluted (in shares)	915		893
Cash dividends paid per share of common stock (in dollars per share)	$ 0.525		$ 0.5075
Alabama Power [Member]
Operating Revenues:
Retail revenues	1,268		1,297
Wholesale revenues, non-affiliates	65		85
Wholesale revenues, affiliates	15		69
Other revenues	53		57
Total operating revenues	1,401		1,508
Operating Expenses:
Fuel	310		432
Purchased power, non-affiliates	41		57
Purchased power, affiliates	53		49
Other operations and maintenance	399		325
Depreciation and amortization	158		175
Taxes other than income taxes	94		89
Total operating expenses	1,055		1,127
Operating Income (Loss)	346		381
Other Income and (Expense):
Allowance for equity funds used during construction	15		10
Interest expense, net of amounts capitalized	(65)		(62)
Other income (expense), net	(4)		(5)
Total other income and (expense)	(54)		(57)
Earnings (Loss) Before Income Taxes	292		324
Income taxes (benefit)	113		127
Net Income (Loss)	179		197
Dividends on preferred and preference stock of subsidiaries	10		10
Net Income (Loss) After Dividends on Preferred and Preference Stock of Subsidiaries	169		187
Georgia Power [Member]
Operating Revenues:
Retail revenues	1,814		2,050
Wholesale revenues, non-affiliates	68		109
Wholesale revenues, affiliates	8		21
Other revenues	88		89
Total operating revenues	1,978		2,269
Operating Expenses:
Fuel	526		752
Purchased power, non-affiliates	60		79
Purchased power, affiliates	149		184
Other operations and maintenance	474		427
Depreciation and amortization	216		208
Taxes other than income taxes	99		103
Total operating expenses	1,524		1,753
Operating Income (Loss)	454		516
Other Income and (Expense):
Allowance for equity funds used during construction	15		6
Interest expense, net of amounts capitalized	(89)		(84)
Other income (expense), net	0		(2)
Total other income and (expense)	(74)		(80)
Earnings (Loss) Before Income Taxes	380		436
Income taxes (benefit)	140		166
Net Income (Loss)	240		270
Dividends on preferred and preference stock of subsidiaries	4		4
Net Income (Loss) After Dividends on Preferred and Preference Stock of Subsidiaries	236		266
Gulf Power [Member]
Operating Revenues:
Retail revenues	293		303
Wholesale revenues, non-affiliates	25		36
Wholesale revenues, affiliates	22		53
Other revenues	17		15
Total operating revenues	357		407
Operating Expenses:
Fuel	110		168
Purchased power, non-affiliates	25		15
Purchased power, affiliates	9		7
Other operations and maintenance	93		84
Depreciation and amortization	20		32
Taxes other than income taxes	28		27
Total operating expenses	285		333
Operating Income (Loss)	72		74
Other Income and (Expense):
Allowance for equity funds used during construction	4		2
Interest expense, net of amounts capitalized	(13)		(13)
Other income (expense), net	(1)		(1)
Total other income and (expense)	(10)		(12)
Earnings (Loss) Before Income Taxes	62		62
Income taxes (benefit)	23		23
Net Income (Loss)	39		39
Dividends on preferred and preference stock of subsidiaries	2		2
Net Income (Loss) After Dividends on Preferred and Preference Stock of Subsidiaries	37		37
Mississippi Power [Member]
Operating Revenues:
Retail revenues	167		207
Wholesale revenues, non-affiliates	77		97
Wholesale revenues, affiliates	27		23
Other revenues	5		4
Total operating revenues	276		331
Operating Expenses:
Fuel	114		147
Purchased power, non-affiliates	2		11
Purchased power, affiliates	2		9
Other operations and maintenance	73		66
Depreciation and amortization	27		23
Taxes other than income taxes	25		20
Estimated loss on Kemper IGCC	9		380
Total operating expenses	252		656
Operating Income (Loss)	24		(325)
Other Income and (Expense):
Allowance for equity funds used during construction	28		38
Interest expense, net of amounts capitalized	(11)		(12)
Other income (expense), net	(2)		(3)
Total other income and (expense)	15		23
Earnings (Loss) Before Income Taxes	39		(302)
Income taxes (benefit)	4		(130)
Net Income (Loss)	35		(172)
Dividends on preferred and preference stock of subsidiaries	0		0
Net Income (Loss) After Dividends on Preferred and Preference Stock of Subsidiaries	35		(172)
Southern Power [Member]
Operating Revenues:
Wholesale revenues, non-affiliates	232		278
Wholesale revenues, affiliates	114		72
Other revenues	2		1
Total operating revenues	348		351
Operating Expenses:
Fuel	138		125
Purchased power, non-affiliates	16		28
Purchased power, affiliates	10		29
Other operations and maintenance	52		53
Depreciation and amortization	59		51
Taxes other than income taxes	6		6
Total operating expenses	281		292
Operating Income (Loss)	67		59
Other Income and (Expense):
Interest expense, net of amounts capitalized	(22)		(22)
Earnings (Loss) Before Income Taxes	45		37
Income taxes (benefit)	12		3
Net Income (Loss)	33		34
Less: Net income attributable to noncontrolling interests	0		1
Net income attributable to Southern Power Company	$ 33		$ 33

[1] Segment net income (loss) for the traditional operating companies for the three months ended March 31, 2015 and March 31, 2014 includes a $9 million pre-tax charge ($6 million after tax) and a $380 million pre-tax charge ($235 million after tax), respectively, for estimated probable losses on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

[2] After dividends on preferred and preference stock of subsidiaries.

XML

Derivatives - Schedule of Derivatives and Gains (Losses) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015
Notional amount of interest rate derivatives
Notional Amount	$ 2,050
Fair Value Gain (Loss) at March 31, 2015	(37)
Alabama Power [Member] | Maturity Date October 2025 [Member] | Cash Flow Hedges Of Forecasted Debt [Member]
Notional amount of interest rate derivatives
Notional Amount	200
Interest Rate Received, Description	3-month LIBOR
Weighted Average Interest Rate Paid	2.93%
Hedge Maturity Date	Oct. 01, 2025
Fair Value Gain (Loss) at March 31, 2015	(14)
Alabama Power [Member] | Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu	54,000,000
Longest Hedge Date	2018
Georgia Power [Member] | Maturity Date May 2025 [Member] | Cash Flow Hedges Of Forecasted Debt [Member]
Notional amount of interest rate derivatives
Notional Amount	350
Interest Rate Received, Description	3-month LIBOR
Weighted Average Interest Rate Paid	2.57%
Hedge Maturity Date	May 01, 2025
Fair Value Gain (Loss) at March 31, 2015	(17)
Georgia Power [Member] | Maturity Date November 2025 [Member] | Cash Flow Hedges Of Forecasted Debt [Member]
Notional amount of interest rate derivatives
Notional Amount	350
Interest Rate Received, Description	3-month LIBOR
Weighted Average Interest Rate Paid	2.57%
Hedge Maturity Date	Nov. 01, 2025
Fair Value Gain (Loss) at March 31, 2015	(13)
Georgia Power [Member] | Maturity Date March 2016 [Member] | Cash Flow Hedges Of Existing Debt [Member]
Notional amount of interest rate derivatives
Notional Amount	250
Interest Rate Received, Description	3-month LIBOR + 0.32%
Interest Rate Received	0.32%
Weighted Average Interest Rate Paid	0.75%
Hedge Maturity Date	Mar. 01, 2016
Fair Value Gain (Loss) at March 31, 2015	0
Georgia Power [Member] | Maturity Date August 2016 [Member] | Cash Flow Hedges Of Existing Debt [Member]
Notional amount of interest rate derivatives
Notional Amount	200
Interest Rate Received, Description	3-month LIBOR + 0.40%
Interest Rate Received	0.40%
Weighted Average Interest Rate Paid	1.01%
Hedge Maturity Date	Aug. 01, 2016
Fair Value Gain (Loss) at March 31, 2015	0
Georgia Power [Member] | Maturity Date June 2018 [Member] | Fair Value Hedges Of Existing Debt [Member]
Notional amount of interest rate derivatives
Notional Amount	250
Interest Rate Received	5.40%
Weighted Average Interest Rate Paid	4.02%
Weighted Average Interest Rate Paid, Description	3-month LIBOR + 4.02%
Hedge Maturity Date	Jun. 01, 2018
Fair Value Gain (Loss) at March 31, 2015	2
Georgia Power [Member] | Maturity Date December 2019 [Member] | Fair Value Hedges Of Existing Debt [Member]
Notional amount of interest rate derivatives
Notional Amount	200
Interest Rate Received	4.25%
Weighted Average Interest Rate Paid	2.46%
Weighted Average Interest Rate Paid, Description	3-month LIBOR + 2.46%
Hedge Maturity Date	Dec. 01, 2019
Fair Value Gain (Loss) at March 31, 2015	4
Georgia Power [Member] | Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu	44,000,000
Longest Hedge Date	2017
Southern Company [Member] | Maturity Date August 2017 [Member] | Fair Value Hedges Of Existing Debt [Member]
Notional amount of interest rate derivatives
Notional Amount	250
Interest Rate Received	1.30%
Weighted Average Interest Rate Paid	0.17%
Weighted Average Interest Rate Paid, Description	3-month LIBOR + 0.17%
Hedge Maturity Date	Aug. 01, 2017
Fair Value Gain (Loss) at March 31, 2015	$ 1
Southern Company [Member] | Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu	241,000,000
Longest Hedge Date	2020
Longest Non-Hedge Date	2017
Gulf Power [Member] | Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu	92,000,000
Longest Hedge Date	2020
Mississippi Power [Member] | Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu	49,000,000
Longest Hedge Date	2018
Southern Power [Member] | Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu	2,000,000
Longest Non-Hedge Date	2017

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Southern Company [Member]
Net cash paid for capitalized interest	$ 32	$ 22
Alabama Power [Member]
Net cash paid for capitalized interest	5	4
Georgia Power [Member]
Net cash paid for capitalized interest	6	3
Gulf Power [Member]
Net cash paid for capitalized interest	2	1
Mississippi Power [Member]
Interest paid	17	17
Net cash paid for capitalized interest	18	14
Southern Power [Member]
Net cash paid for capitalized interest	$ 0	$ 0

XML

Fair Value Measurements - Fair Value Measurements Calculated at Net Asset Value Per Share (Details) (USD $)	3 Months Ended
	Mar. 31, 2015
Foreign equity funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	$ 126,000,000
Unfunded Commitments	0
Redemption Frequency	Monthly
Redemption Notice Period	5 days
Redemption Notice Period, Description	5 days
Equity - commingled funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	65,000,000
Unfunded Commitments	0
Redemption Frequency	Daily/Monthly
Redemption Notice Period	7 days
Redemption Notice Period, Description	Daily/7 days
Debt - Commingled Funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	16,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	5 days
Redemption Notice Period, Description	5 days
Other - commingled funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	6,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Other - money market funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	11,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Trust owned life insurance [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	118,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	15 days
Redemption Notice Period, Description	15 days
Money market funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	863,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Alabama Power [Member] | Equity - commingled funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	65,000,000
Unfunded Commitments	0
Redemption Frequency	Daily/Monthly
Redemption Notice Period	7 days
Redemption Notice Period, Description	Daily/7 days
Alabama Power [Member] | Debt - Commingled Funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	16,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	5 days
Redemption Notice Period, Description	5 days
Alabama Power [Member] | Trust owned life insurance [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	118,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period	15 days
Redemption Notice Period, Description	15 days
Alabama Power [Member] | Money market funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	287,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Georgia Power [Member] | Foreign equity funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	126,000,000
Unfunded Commitments	0
Redemption Frequency	Monthly
Redemption Notice Period	5 days
Redemption Notice Period, Description	5 days
Georgia Power [Member] | Other - commingled funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	6,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Georgia Power [Member] | Other - money market funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	11,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Georgia Power [Member] | Money market funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	406,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Gulf Power [Member] | Money market funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	18,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Mississippi Power [Member] | Money market funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	110,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Southern Power [Member] | Money market funds [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Fair Value	3,000,000
Unfunded Commitments	$ 0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable

XML

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

Assets and liabilities measured at fair value on a recurring basis

As of March 31, 2015, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:

	Fair Value Measurements Using
As of March 31, 2015:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives	$	—	$	7	$	—	$	7
Interest rate derivatives	—		8		—		8
Nuclear decommissioning trusts(a)	632		937		4		1,573
Cash equivalents	863		—		—		863
Other investments	9		—		1		10
Total	$	1,504	$	952	$	5	$	2,461
Liabilities:
Energy-related derivatives	$	—	$	225	$	—	$	225
Interest rate derivatives	—		46		—		46
Total	$	—	$	271	$	—	$	271
Alabama Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Nuclear decommissioning trusts(b)
Domestic equity	393		90		—		483
Foreign equity	36		65		—		101
U.S. Treasury and government agency securities	—		34		—		34
Corporate bonds	10		113		—		123
Mortgage and asset backed securities	—		18		—		18
Other	—		6		4		10
Cash equivalents	287		—		—		287
Total	$	726	$	327	$	4	$	1,057
Liabilities:
Energy-related derivatives	$	—	$	59	$	—	$	59
Interest rate derivatives	—		14		—		14
Total	$	—	$	73	$	—	$	73

	Fair Value Measurements Using
As of March 31, 2015:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in millions)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	6	$	—	$	6
Interest rate derivatives	—		6		—		6
Nuclear decommissioning trusts(b) (c)
Domestic equity	182		2		—		184
Foreign equity	—		126		—		126
U.S. Treasury and government agency securities	—		86		—		86
Municipal bonds	—		92		—		92
Corporate bonds	—		192		—		192
Mortgage and asset backed securities	—		107		—		107
Other	11		6		—		17
Cash equivalents	406		—		—		406
Total	$	599	$	623	$	—	$	1,222
Liabilities:
Energy-related derivatives	$	—	$	24	$	—	$	24
Interest rate derivatives	—		31		—		31
Total	$	—	$	55	$	—	$	55
Gulf Power
Assets:
Cash equivalents	$	18	$	—	$	—	$	18
Liabilities:
Energy-related derivatives	—		90		—		90
Mississippi Power
Assets:
Cash equivalents	$	110	$	—	$	—	$	110
Liabilities:
Energy-related derivatives	—		52		—		52
Southern Power
Assets:
Cash equivalents	$	3	$	—	$	—	$	3

(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 March 31, 2015, approximately $50 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan and pledged 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 March 31, 2015, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:

As of March 31, 2015:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Foreign equity funds	$	126	None	Monthly	5 days
Equity - commingled funds	65		None	Daily/Monthly	Daily/7 days
Debt - commingled funds	16		None	Daily	5 days
Other - commingled funds	6		None	Daily	Not applicable
Other - money market funds	11		None	Daily	Not applicable
Trust-owned life insurance	118		None	Daily	15 days
Cash equivalents:
Money market funds	863		None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Equity - commingled funds	$	65	None	Daily/Monthly	Daily/7 days
Debt - commingled funds	16		None	Daily	5 days
Trust-owned life insurance	118		None	Daily	15 days
Cash equivalents:
Money market funds	287		None	Daily	Not applicable
Georgia Power
Nuclear decommissioning trusts:
Foreign equity funds	$	126	None	Monthly	5 days
Other - commingled funds	6		None	Daily	Not applicable
Other - money market funds	11		None	Daily	Not applicable
Cash equivalents:
Money market funds	406		None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds	$	18	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds	$	110	None	Daily	Not applicable
Southern Power
Cash equivalents:
Money market funds	$	3	None	Daily	Not applicable

Financial instruments for which carrying amount did not equal fair value

As of March 31, 2015, 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:
Southern Company	$	24,241	$	26,350
Alabama Power	$	6,922	$	7,696
Georgia Power	$	9,801	$	10,733
Gulf Power	$	1,370	$	1,501
Mississippi Power	$	2,251	$	2,323
Southern Power	$	1,621	$	1,789

XML

Fair Value Measurements - Financial Instruments for which Carrying Amount did not Equal Fair Value (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015
Southern Company [Member]
Long-term debt:
Long-term debt, Carrying Amount	$ 24,241
Long-term debt, Fair Value	26,350
Alabama Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	6,922
Long-term debt, Fair Value	7,696
Georgia Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	9,801
Long-term debt, Fair Value	10,733
Gulf Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	1,370
Long-term debt, Fair Value	1,501
Mississippi Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	2,251
Long-term debt, Fair Value	2,323
Southern Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	1,621
Long-term debt, Fair Value	$ 1,789

XML

Financing (Tables)

3 Months Ended

Mar. 31, 2015

Debt Disclosure [Abstract]

Credit arrangements by company

The following table outlines the committed credit arrangements by company as of March 31, 2015:

	Expires												Executable Term Loans				Due Within One Year
Company	2015		2016		2017		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)								(in millions)				(in millions)				(in millions)
Southern Company	$	—	$	—	$	—	$	1,000	$	1,000	$	1,000	$	—	$	—	$	—	$	—
Alabama Power	228		50		—		1,030		1,308		1,308		58		—		58		170
Georgia Power	—		150		—		1,600		1,750		1,736		—		—		—		150
Gulf Power	45		200		30		—		275		275		50		—		50		195
Mississippi Power	135		165		—		—		300		270		25		40		65		235
Southern Power	—		—		—		500		500		488		—		—		—		—
Other	70		—		—		—		70		70		20		—		20		50
Total	$	478	$	565	$	30	$	4,130	$	5,203	$	5,147	$	153	$	40	$	193	$	800

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 three months of 2015:

Company(a)	Senior Note Issuances		Senior Note Redemptions		Other Long-Term Debt Redemptions and Maturities(b)
	(in millions)
Alabama Power	$	550	$	250	$	—
Georgia Power	—		—		3
Mississippi Power	—		—		76
Other	—		—		4
Total	$	550	$	250	$	83

(a) Southern Company, Gulf Power, and Southern Power did not issue or redeem any long-term debt during the first three months of 2015.

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

XML

Condensed Consolidated Balance Sheets (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Deferred Charges and Other Assets:
Total Assets	$ 71,610	$ 70,923
Common Stockholders' Equity:
Total Stockholders' Equity	20,994	20,926
Southern Company [Member]
Current Assets:
Cash and cash equivalents	1,112	710
Receivables --
Customer accounts receivable	1,117	1,090
Unbilled revenues	374	432
Under recovered regulatory clause revenues	159	136
Other accounts and notes receivable	241	307
Accumulated provision for uncollectible accounts	(19)	(18)
Fossil fuel stock, at average cost	855	930
Materials and supplies, at average cost	1,050	1,039
Vacation pay	178	177
Prepaid expenses	299	665
Deferred income taxes, current	578	506
Other regulatory assets, current	363	346
Other current assets	65	50
Total current assets	6,372	6,370
Property, Plant, and Equipment:
In service	70,279	70,013
Less accumulated provision for depreciation	24,307	24,059
Plant in service, net of depreciation	45,972	45,954
Other utility plant, net	275	211
Nuclear fuel, at amortized cost	914	911
Construction work in progress	8,314	7,792
Total property, plant, and equipment	55,475	54,868
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,574	1,546
Leveraged leases	749	743
Miscellaneous property and investments	204	203
Total other property and investments	2,527	2,492
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,527	1,510
Unamortized debt issuance expense	200	202
Unamortized loss on reacquired debt	239	243
Other regulatory assets, deferred	4,462	4,334
Other deferred charges and assets	808	904
Total deferred charges and other assets	7,236	7,193
Total Assets	71,610	70,923
Current Liabilities:
Securities due within one year	3,306	3,333
Interest-bearing refundable deposit	275	275
Notes payable	1,679	803
Accounts Payable and Accrued Liabilities, Current [Abstract]
Accounts payable	1,289	1,593
Customer deposits	395	390
Accrued taxes --
Accrued income taxes	198	151
Other accrued taxes	248	487
Accrued interest	286	295
Accrued vacation pay	222	223
Accrued compensation	186	576
Dividends on preferred and preference stock of subsidiaries	17
Mirror CWIP	311	271
Other current liabilities	790	570
Total current liabilities	9,185	8,967
Long-term Debt	21,093	20,841
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	11,706	11,568
Deferred credits related to income taxes	185	192
Accumulated deferred investment tax credits	1,198	1,208
Employee benefit obligations	2,416	2,432
Asset retirement obligations	2,151	2,168
Other cost of removal obligations	1,209	1,215
Other regulatory liabilities, deferred	439	398
Other deferred credits and liabilities	619	594
Total deferred credits and other liabilities	19,923	19,775
Total Liabilities	50,201	49,583
Redeemable Preferred Stock of Subsidiaries	375	375
Redeemable Noncontrolling Interest	40	39
Common Stockholders' Equity:
Common stock	4,555	4,539
Paid-in capital	6,108	5,955
Treasury, at cost	(142)	(26)
Retained earnings (accumulated deficit)	9,639	9,609
Accumulated other comprehensive income (loss)	(143)	(128)
Total common stockholders' equity	20,017	19,949
Preferred and Preference Stock of Subsidiaries	756	756
Noncontrolling Interest	221	221
Total Stockholders' Equity	20,994	20,926
Total Liabilities and Stockholders' Equity	71,610	70,923
Alabama Power [Member]
Current Assets:
Cash and cash equivalents	395	273
Receivables --
Customer accounts receivable	374	345
Unbilled revenues	115	138
Under recovered regulatory clause revenues	16	74
Other accounts and notes receivable	24	23
Affiliated companies	36	37
Accumulated provision for uncollectible accounts	(10)	(9)
Fossil fuel stock, at average cost	268	268
Materials and supplies, at average cost	410	406
Vacation pay	66	65
Prepaid expenses	134	244
Other regulatory assets, current	91	84
Other current assets	4	5
Total current assets	1,923	1,953
Property, Plant, and Equipment:
In service	23,254	23,080
Less accumulated provision for depreciation	8,627	8,522
Plant in service, net of depreciation	14,627	14,558
Nuclear fuel, at amortized cost	359	348
Construction work in progress	1,089	1,006
Total property, plant, and equipment	16,075	15,912
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	67	66
Nuclear decommissioning trusts, at fair value	770	756
Miscellaneous property and investments	85	84
Total other property and investments	922	906
Deferred Charges and Other Assets:
Deferred charges related to income taxes	523	525
Deferred under recovered regulatory clause revenues	87	31
Other regulatory assets, deferred	1,065	1,063
Other deferred charges and assets	161	162
Total deferred charges and other assets	1,836	1,781
Total Assets	20,756	20,552
Current Liabilities:
Securities due within one year	734	454
Accounts Payable and Accrued Liabilities, Current [Abstract]
Affiliated accounts payable	225	248
Other accounts payable	273	443
Customer deposits	88	87
Accrued taxes --
Accrued income taxes	37	2
Other accrued taxes	59	37
Accrued interest	59	66
Accrued vacation pay	54	54
Accrued compensation	44	131
Other regulatory liabilities, current	2	2
Dividends on preferred and preference stock of subsidiaries	10
Other current liabilities	114	80
Total current liabilities	1,689	1,604
Long-term Debt	6,193	6,176
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,890	3,874
Deferred credits related to income taxes	71	72
Accumulated deferred investment tax credits	123	125
Employee benefit obligations	322	326
Asset retirement obligations	840	829
Other cost of removal obligations	743	744
Other regulatory liabilities, deferred	242	239
Deferred over recovered regulatory clause revenues	81	47
Other deferred credits and liabilities	88	79
Total deferred credits and other liabilities	6,400	6,335
Total Liabilities	14,282	14,115
Redeemable Preferred Stock	342	342
Preference Stock	343	343
Common Stockholders' Equity:
Common stock	1,222	1,222
Paid-in capital	2,318	2,304
Retained earnings (accumulated deficit)	2,281	2,255
Accumulated other comprehensive income (loss)	(32)	(29)
Total common stockholders' equity	5,789	5,752
Total Liabilities and Stockholders' Equity	20,756	20,552
Georgia Power [Member]
Current Assets:
Cash and cash equivalents	413	24
Receivables --
Customer accounts receivable	642	553
Unbilled revenues	174	201
Joint owner accounts receivable	47	121
Other accounts and notes receivable	70	61
Affiliated companies	16	18
Accumulated provision for uncollectible accounts	(7)	(6)
Fossil fuel stock, at average cost	372	439
Materials and supplies, at average cost	443	438
Vacation pay	91	91
Prepaid income taxes	86	278
Other regulatory assets, current	142	136
Other current assets	85	74
Total current assets	2,574	2,428
Property, Plant, and Equipment:
In service	31,425	31,083
Less accumulated provision for depreciation	11,326	11,222
Plant in service, net of depreciation	20,099	19,861
Other utility plant, net	197	211
Nuclear fuel, at amortized cost	555	563
Construction work in progress	4,193	4,031
Total property, plant, and equipment	25,044	24,666
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	60	58
Nuclear decommissioning trusts, at fair value	804	789
Miscellaneous property and investments	37	38
Total other property and investments	901	885
Deferred Charges and Other Assets:
Deferred charges related to income taxes	696	698
Deferred under recovered regulatory clause revenues	62	197
Other regulatory assets, deferred	1,796	1,753
Other deferred charges and assets	443	403
Total deferred charges and other assets	2,997	3,051
Total Assets	31,516	31,030
Current Liabilities:
Securities due within one year	1,600	1,154
Notes payable	840	156
Accounts Payable and Accrued Liabilities, Current [Abstract]
Affiliated accounts payable	364	451
Other accounts payable	469	555
Customer deposits	256	253
Accrued taxes --
Other accrued taxes	116	332
Accrued interest	100	96
Accrued vacation pay	62	63
Accrued compensation	54	153
Dividends on preferred and preference stock of subsidiaries	4
Liabilities from risk management activities	52	32
Other current liabilities	388	225
Total current liabilities	4,301	3,470
Long-term Debt	8,393	8,683
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,471	5,507
Deferred credits related to income taxes	104	106
Accumulated deferred investment tax credits	193	196
Employee benefit obligations	891	903
Asset retirement obligations	1,223	1,223
Other deferred credits and liabilities	268	255
Total deferred credits and other liabilities	8,150	8,190
Total Liabilities	20,844	20,343
Redeemable Preferred Stock	45	45
Preference Stock	221	221
Common Stockholders' Equity:
Common stock	398	398
Paid-in capital	6,218	6,196
Retained earnings (accumulated deficit)	3,812	3,835
Accumulated other comprehensive income (loss)	(22)	(8)
Total common stockholders' equity	10,406	10,421
Total Liabilities and Stockholders' Equity	31,516	31,030
Gulf Power [Member]
Current Assets:
Cash and cash equivalents	55	39
Receivables --
Customer accounts receivable	79	73
Unbilled revenues	52	58
Under recovered regulatory clause revenues	53	57
Other accounts and notes receivable	9	8
Affiliated companies	1	10
Accumulated provision for uncollectible accounts	(2)	(2)
Fossil fuel stock, at average cost	104	101
Materials and supplies, at average cost	54	56
Prepaid expenses	38	40
Other regulatory assets, current	77	74
Other current assets	2	2
Total current assets	522	516
Property, Plant, and Equipment:
In service	4,405	4,495
Less accumulated provision for depreciation	1,236	1,296
Plant in service, net of depreciation	3,169	3,199
Other utility plant, net	79	0
Construction work in progress	474	465
Total property, plant, and equipment	3,722	3,664
Other Property and Investments:
Total other property and investments	15	15
Deferred Charges and Other Assets:
Deferred charges related to income taxes	59	56
Other regulatory assets, deferred	423	416
Other deferred charges and assets	37	41
Total deferred charges and other assets	519	513
Total Assets	4,778	4,708
Current Liabilities:
Securities due within one year	23	0
Notes payable	150	110
Accounts Payable and Accrued Liabilities, Current [Abstract]
Affiliated accounts payable	68	87
Other accounts payable	49	56
Customer deposits	35	35
Accrued taxes --
Other accrued taxes	14	9
Accrued interest	21	11
Accrued compensation	7	23
Deferred capacity expense, current	22	22
Dividends on preferred and preference stock of subsidiaries	2
Liabilities from risk management activities	37	37
Other current liabilities	24	23
Total current liabilities	450	413
Long-term Debt	1,347	1,370
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	836	800
Employee benefit obligations	120	121
Other cost of removal obligations	218	235
Other regulatory liabilities, deferred	45	49
Deferred capacity expense	158	163
Other deferred credits and liabilities	120	101
Total deferred credits and other liabilities	1,497	1,469
Total Liabilities	3,294	3,252
Preference Stock	147	147
Common Stockholders' Equity:
Common stock	503	483
Paid-in capital	563	560
Retained earnings (accumulated deficit)	272	267
Accumulated other comprehensive income (loss)	(1)	(1)
Total common stockholders' equity	1,337	1,309
Total Liabilities and Stockholders' Equity	4,778	4,708
Mississippi Power [Member]
Current Assets:
Cash and cash equivalents	134	133
Receivables --
Customer accounts receivable	38	43
Unbilled revenues	33	35
Other accounts and notes receivable	13	11
Affiliated companies	40	51
Accumulated provision for uncollectible accounts	(1)	(1)
Fossil fuel stock, at average cost	96	100
Materials and supplies, at average cost	64	62
Prepaid income taxes	162	191
Other regulatory assets, current	74	73
Other current assets	6	6
Total current assets	659	704
Property, Plant, and Equipment:
In service	4,396	4,378
Less accumulated provision for depreciation	1,194	1,173
Plant in service, net of depreciation	3,202	3,205
Construction work in progress	2,361	2,161
Total property, plant, and equipment	5,563	5,366
Other Property and Investments:
Total other property and investments	6	5
Deferred Charges and Other Assets:
Deferred charges related to income taxes	243	226
Other regulatory assets, deferred	419	385
Other deferred charges and assets	57	71
Total deferred charges and other assets	719	682
Total Assets	6,947	6,757
Current Liabilities:
Securities due within one year	3	778
Interest-bearing refundable deposit	275	275
Notes payable	30	0
Accounts Payable and Accrued Liabilities, Current [Abstract]
Affiliated accounts payable	80	86
Other accounts payable	148	178
Accrued taxes --
Accrued income taxes	185	142
Other accrued taxes	29	84
Accrued interest	86	76
Accrued compensation	6	26
Dividends on preferred and preference stock of subsidiaries	0
Over recovered regulatory clause liabilities	23	1
Mirror CWIP	311	271
Other current liabilities	61	61
Total current liabilities	1,237	1,978
Long-term Debt	2,328	1,630
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	397	285
Accumulated deferred investment tax credits	282	283
Employee benefit obligations	148	148
Asset retirement obligations	49	48
Other cost of removal obligations	168	166
Other regulatory liabilities, deferred	65	64
Other deferred credits and liabilities	43	38
Total deferred credits and other liabilities	1,152	1,032
Total Liabilities	4,717	4,640
Redeemable Preferred Stock	33	33
Common Stockholders' Equity:
Common stock	38	38
Paid-in capital	2,690	2,612
Retained earnings (accumulated deficit)	(524)	(559)
Accumulated other comprehensive income (loss)	(7)	(7)
Total common stockholders' equity	2,197	2,084
Total Liabilities and Stockholders' Equity	6,947	6,757
Southern Power [Member]
Current Assets:
Cash and cash equivalents	23	75
Receivables --
Customer accounts receivable	71	77
Other accounts and notes receivable	14	15
Affiliated companies	37	34
Fossil fuel stock, at average cost	16	22
Materials and supplies, at average cost	59	58
Prepaid service agreements - current	10	8
Prepaid expenses	10	8
Deferred income taxes, current	379	306
Assets from risk management activities	0	5
Prepaid income taxes	21	19
Total current assets	640	627
Property, Plant, and Equipment:
In service	5,658	5,657
Less accumulated provision for depreciation	1,093	1,035
Plant in service, net of depreciation	4,565	4,622
Construction work in progress	48	11
Total property, plant, and equipment	4,613	4,633
Other Property and Investments:
Goodwill	2	2
Other intangible assets, net of amortization of $9 and $8 at March 31, 2015 and December 31, 2014, respectively	46	47
Total other property and investments	48	49
Deferred Charges and Other Assets:
Prepaid long-term service agreements	137	124
Other deferred charges and assets -- affiliated	13	5
Other deferred charges and assets	113	112
Total deferred charges and other assets	263	241
Total Assets	5,564	5,550
Current Liabilities:
Securities due within one year	525	525
Notes payable	233	195
Accounts Payable and Accrued Liabilities, Current [Abstract]
Affiliated accounts payable	69	78
Other accounts payable	32	30
Accrued taxes --
Accrued income taxes	65	72
Accrued interest	15	30
Other current liabilities	19	17
Total current liabilities	958	947
Long-term Debt	1,095	1,095
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	882	863
Accumulated deferred investment tax credits	596	601
Deferred capacity revenues -- affiliated	5	15
Other deferred credits and liabilities — affiliated	0	1
Other deferred credits and liabilities	16	18
Total deferred credits and other liabilities	1,499	1,498
Total Liabilities	3,552	3,540
Redeemable Noncontrolling Interest	40	39
Common Stockholders' Equity:
Common stock	0	0
Paid-in capital	1,176	1,176
Retained earnings (accumulated deficit)	574	573
Accumulated other comprehensive income (loss)	3	3
Total common stockholders' equity	1,753	1,752
Noncontrolling Interest, Total	219	219
Total Stockholders' Equity	1,972	1,971
Total Liabilities and Stockholders' Equity	$ 5,564	$ 5,550

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	$ (15)	$ 2
Southern Company [Member]
Net Income (loss)	525	368
Qualifying hedges:
Changes in fair value, net of tax	(18)	0
Reclassification adjustment for amounts included in net income, net of tax	1	1
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	2	1
Total other comprehensive income (loss)	(15)	2
Dividends on preferred and preference stock of subsidiaries	(17)	(17)
Comprehensive Income (Loss)	493	353
Alabama Power [Member]
Net Income (loss)	179	197
Qualifying hedges:
Changes in fair value, net of tax	(4)	0
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	(4)	0
Dividends on preferred and preference stock of subsidiaries	(10)	(10)
Comprehensive Income (Loss)	175	197
Georgia Power [Member]
Net Income (loss)	240	270
Qualifying hedges:
Changes in fair value, net of tax	(14)	0
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	(14)	0
Dividends on preferred and preference stock of subsidiaries	(4)	(4)
Comprehensive Income (Loss)	226	270
Gulf Power [Member]
Net Income (loss)	39	39
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	0	0
Dividends on preferred and preference stock of subsidiaries	(2)	(2)
Comprehensive Income (Loss)	39	39
Mississippi Power [Member]
Net Income (loss)	35	(172)
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	0	0
Dividends on preferred and preference stock of subsidiaries	0	0
Comprehensive Income (Loss)	35	(172)
Southern Power [Member]
Net Income (loss)	33	34
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	0	0
Less: Comprehensive income attributable to noncontrolling interest/Dividends on preferred and preference stock of subsidiaries	0	1
Comprehensive Income (Loss)	$ 33	$ 33

XML

Acquisitions

3 Months Ended

Mar. 31, 2015

Business Combinations [Abstract]

ACQUISITIONS

ACQUISITIONS

During 2015, Southern Power Company acquired or contracted to acquire the following projects in accordance with its overall growth strategy.

Decatur County Solar Projects

On February 19, 2015, Southern Power Company acquired all of the outstanding membership interests of Decatur Parkway Solar Project, LLC and Decatur County Solar Project, LLC from TradeWind Energy, Inc. as part of Southern Power's plans to build two solar photovoltaic facilities: the Decatur Parkway Solar Project and the Decatur County Solar Project. These two projects, approximately 80 MWs and 19 MWs, respectively, will be constructed on separate sites in Decatur County, Georgia. Construction of the Decatur Parkway Solar Project commenced in February 2015, while construction of the Decatur County Solar Project is expected to commence in June 2015. Both projects are expected to begin commercial operation in late 2015, and the entire output of each project is contracted to Georgia Power. The Decatur Parkway Solar Project is contracted under a 25-year PPA and the Decatur County Solar Project is contracted under a separate 20-year PPA. Construction costs incurred through March 31, 2015 were $32 million.

The total estimated cost of the facilities is expected to be between $200 million and $220 million, which includes the acquisition price for all of the outstanding membership interests of Decatur Parkway Solar Project, LLC and Decatur County Solar Project, LLC from TradeWind Energy, Inc. The ultimate outcome of these matters cannot be determined at this time.

Kay County Wind Facility

On February 24, 2015, Southern Power Company, through its wholly-owned subsidiary Southern Renewable Energy, Inc., entered into a purchase agreement with Kay Wind Holdings, LLC, a wholly-owned subsidiary of Apex Clean Energy Holdings, LLC, the developer of the project, to acquire all of the outstanding membership interests of Kay Wind, LLC (Kay Wind). Kay Wind is constructing and owns an approximately 299-MW wind facility in Kay County, Oklahoma. The wind facility is expected to begin commercial operation in late 2015, and the entire output of the facility is contracted under separate 20-year PPAs with Westar Energy, Inc. and Grand River Dam Authority.

In March 2015, Kay Wind obtained the necessary financing for the construction of the facility, and Southern Power Company's acquisition is expected to close in the fourth quarter 2015. The purchase price is expected to be approximately $492 million, with potential purchase price adjustments based on performance testing, and is included in Southern Power's capital program estimates for 2015. The completion of the acquisition is subject to Kay Wind achieving certain construction and project milestones, and various other customary conditions to closing. The ultimate outcome of this matter cannot be determined at this time.

Butler Solar Project

On March 12, 2015, Southern Power Company entered into a purchase agreement with CERSM, LLC and Community Energy, Inc. to acquire all of the outstanding membership interests of Butler Solar LLC as part of Southern Power's plans to build an approximately 100-MW solar photovoltaic facility in Taylor County, Georgia. Construction of the project is expected to commence in July 2015, with commercial operation expected to begin in December 2016. The entire output of the project is contracted to Georgia Power under a 30-year PPA.

Southern Power Company's acquisition of Butler Solar LLC is expected to close later in May 2015 and the total estimated cost of the facility is expected to be between $220 million and $230 million, which includes the acquisition price for all of the outstanding membership interests of Butler Solar LLC from CERSM, LLC and Community Energy, Inc. The completion of the acquisition is subject to customary conditions to closing. The ultimate outcome of this matter cannot be determined at this time.

Subsequent Events

Lost Hills-Blackwell Solar Facilities

On April 15, 2015, Southern Power Company, through its subsidiary Southern Renewable Partnerships, LLC (SRP), acquired 100% of the class A membership interests of Lost Hills Blackwell Holdings, LLC (Lost Hills Blackwell) from a wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project, for approximately $74 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of Lost Hills Blackwell for approximately $34 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from Lost Hills Blackwell. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. Lost Hills Blackwell constructed and owns the approximately 20-MW Lost Hills and the approximately 12-MW Blackwell solar facilities in Kern County, California. These solar facilities began commercial operation on April 17, 2015, and their entire output is contracted under PPAs, initially to the City of Roseville and then to Pacific Gas and Electric Company, that together extend approximately 29 years.

Pawpaw Solar Project

On April 22, 2015, Southern Power Company entered into a purchase agreement with Longview Solar, LLC to acquire all of the outstanding membership interests of LS – Pawpaw, LLC as part of Southern Power Company's plans to build an approximately 30-MW solar photovoltaic facility in Taylor County, Georgia. Construction of the project is expected to commence in June 2015, with commercial operation expected to begin in December 2015. The entire output of the project is contracted to Georgia Power under a 30-year PPA.

Southern Power Company's acquisition of LS – Pawpaw, LLC is expected to close later in May 2015 and the total estimated cost of the facility is expected to be between $65 million and $75 million, which includes the acquisition price for all of the outstanding membership interests of LS – Pawpaw, LLC from Longview Solar, LLC. The completion of the acquisition is subject to customary conditions to closing. The ultimate outcome of this matter cannot be determined at this time.

North Star Solar Facility

On April 30, 2015, Southern Power Company, through its subsidiary SRP, acquired 100% of the class A membership interests of NS Solar Holdings, LLC (North Star) from a wholly-owned subsidiary of First Solar, the developer of the project, for approximately $208 million. Concurrently, a wholly-owned subsidiary of First Solar acquired 100% of the class B membership interests of North Star for approximately $99 million. SRP and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from North Star. In addition, Southern Power Company is entitled to substantially all of the federal tax benefits with respect to the transaction. North Star is constructing and owns the approximately 60-MW North Star solar facility in Fresno County, California, which is expected to begin commercial operation in June 2015. The entire output of the project is contracted under a 20-year PPA with Pacific Gas and Electric Company. The ultimate outcome of this matter cannot be determined at this time.

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2015
Document Information [Line Items]
Entity Registrant Name	SOUTHERN CO
Entity Central Index Key	0000092122
Document Type	10-Q
Document Period End Date	Mar. 31, 2015
Amendment Flag	false
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	908,261,371
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

Segment and Related Information

3 Months Ended

Mar. 31, 2015

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 operating companies and Southern Power. The four traditional 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 operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $114 million and $72 million for the three months ended March 31, 2015 and March 31, 2014, 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 investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material. Financial data for business segments and products and services for the three months ended March 31, 2015 and 2014 was as follows:

	Electric Utilities
	Traditional Operating Companies		Southern Power		Eliminations			Total		All Other		Eliminations			Consolidated
	(in millions)
Three Months Ended March 31, 2015:
Operating revenues	$	3,948	$	348	$	(124	)	$	4,172	$	40	$	(29	)	$	4,183
Segment net income (loss)(a)(b)	477		33		—			510		3		(5		)	508
Total assets at March 31, 2015	$	65,530	$	5,564	$	(273	)	$	70,821	$	1,091	$	(302	)	$	71,610
Three Months Ended March 31, 2014:
Operating revenues	$	4,378	$	351	$	(102	)	$	4,627	$	41	$	(24	)	$	4,644
Segment net income (loss)(a)(b)	318		33		—			351		—		—			351
Total assets at December 31, 2014	$	64,644	$	5,550	$	(131	)	$	70,063	$	1,156	$	(296	)	$	70,923

(a) After dividends on preferred and preference stock of subsidiaries.

(b) Segment net income (loss) for the traditional operating companies for the three months ended March 31, 2015 and March 31, 2014 includes a $9 million pre-tax charge ($6 million after tax) and a $380 million pre-tax charge ($235 million after tax), respectively, for estimated probable losses on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended March 31, 2015	$	3,542	$	467	$	163	$	4,172
Three Months Ended March 31, 2014	3,858		604		165		4,627

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Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Southern Company [Member]
Changes in fair value, tax	$ (11)	$ 0
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	1	1
Reclassification adjustment for amounts of pension and other post retirement benefit plans included in net income, tax	1	0
Alabama Power [Member]
Changes in fair value, tax	(2)	0
Georgia Power [Member]
Changes in fair value, tax	$ (9)	$ 0

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Stockholders' Equity

3 Months Ended

Mar. 31, 2015

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 March 31, 2015	Three Months Ended March 31, 2014
	(in millions)
As reported shares	910	890
Effect of options and performance share award units	5	3
Diluted shares	915	893

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for the three months ended March 31, 2015 and were 17 million for the three months ended March 31, 2014.

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 Interest
	(in thousands)			(in millions)
Balance at December 31, 2014	908,502	(725	)	$	19,949		$	756	$	221	$	20,926
Net income after dividends on preferred and preference stock	—	—		508			—		—		508
Other comprehensive income (loss)	—	—		(15		)	—		—		(15		)
Stock issued	3,094	—		112			—		—		112
Stock-based compensation	—	—		53			—		—		53
Stock repurchased, at cost	—	(2,599	)	(115		)	—		—		(115		)
Cash dividends on common stock	—	—		(478		)	—		—		(478		)
Other	—	(11	)	3			—		—		3
Balance at March 31, 2015	911,596	(3,335	)	$	20,017		$	756	$	221	$	20,994
Balance at December 31, 2013	892,733	(5,647	)	$	19,008		$	756	$	—	$	19,764
Net income after dividends on preferred and preference stock	—	—		351			—		—		351
Other comprehensive income (loss)	—	—		2			—		—		2
Treasury stock re-issued	—	2,404		111			—		—		111
Stock issued	1,340	—		53			—		—		53
Stock repurchased, at cost	—	—		(4		)	—		—		(4		)
Cash dividends on common stock	—	—		(451		)	—		—		(451		)
Other	—	(18	)	—			—		—		—
Balance at March 31, 2014	894,073	(3,261	)	$	19,070		$	756	$	—	$	19,826

Stock Repurchased

On March 2, 2015, Southern Company announced a program to repurchase up to 20 million shares of Southern Company common stock to offset all or a portion of the incremental shares issued under its employee and director equity compensation plans, including through stock option exercises, until December 31, 2017. Under this program, approximately 2.6 million shares have been repurchased through March 31, 2015 at a total cost of approximately $115 million. Pursuant to board approval, Southern Company may repurchase shares through open market purchases or privately negotiated transactions, including accelerated or other share repurchase programs, in accordance with applicable securities laws.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

As of March 31, 2015, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:

	Fair Value Measurements Using
As of March 31, 2015:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives	$	—	$	7	$	—	$	7
Interest rate derivatives	—		8		—		8
Nuclear decommissioning trusts(a)	632		937		4		1,573
Cash equivalents	863		—		—		863
Other investments	9		—		1		10
Total	$	1,504	$	952	$	5	$	2,461
Liabilities:
Energy-related derivatives	$	—	$	225	$	—	$	225
Interest rate derivatives	—		46		—		46
Total	$	—	$	271	$	—	$	271
Alabama Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Nuclear decommissioning trusts(b)
Domestic equity	393		90		—		483
Foreign equity	36		65		—		101
U.S. Treasury and government agency securities	—		34		—		34
Corporate bonds	10		113		—		123
Mortgage and asset backed securities	—		18		—		18
Other	—		6		4		10
Cash equivalents	287		—		—		287
Total	$	726	$	327	$	4	$	1,057
Liabilities:
Energy-related derivatives	$	—	$	59	$	—	$	59
Interest rate derivatives	—		14		—		14
Total	$	—	$	73	$	—	$	73

	Fair Value Measurements Using
As of March 31, 2015:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in millions)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	6	$	—	$	6
Interest rate derivatives	—		6		—		6
Nuclear decommissioning trusts(b) (c)
Domestic equity	182		2		—		184
Foreign equity	—		126		—		126
U.S. Treasury and government agency securities	—		86		—		86
Municipal bonds	—		92		—		92
Corporate bonds	—		192		—		192
Mortgage and asset backed securities	—		107		—		107
Other	11		6		—		17
Cash equivalents	406		—		—		406
Total	$	599	$	623	$	—	$	1,222
Liabilities:
Energy-related derivatives	$	—	$	24	$	—	$	24
Interest rate derivatives	—		31		—		31
Total	$	—	$	55	$	—	$	55
Gulf Power
Assets:
Cash equivalents	$	18	$	—	$	—	$	18
Liabilities:
Energy-related derivatives	—		90		—		90
Mississippi Power
Assets:
Cash equivalents	$	110	$	—	$	—	$	110
Liabilities:
Energy-related derivatives	—		52		—		52
Southern Power
Assets:
Cash equivalents	$	3	$	—	$	—	$	3

(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 March 31, 2015, approximately $50 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan and pledged to creditors under the funds' managers' securities lending program.

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 financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally, implied volatility of interest rate options. See Note (H) herein for additional information on how these derivatives are used.

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' judgment, are also obtained when available.

Investments in private equity and real estate within Alabama Power's nuclear decommissioning trusts are generally classified as Level 3, as the underlying assets typically do not have observable inputs. The fund manager values these assets using various inputs and techniques depending on the nature of the underlying investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.

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

As of March 31, 2015, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:

As of March 31, 2015:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Foreign equity funds	$	126	None	Monthly	5 days
Equity - commingled funds	65		None	Daily/Monthly	Daily/7 days
Debt - commingled funds	16		None	Daily	5 days
Other - commingled funds	6		None	Daily	Not applicable
Other - money market funds	11		None	Daily	Not applicable
Trust-owned life insurance	118		None	Daily	15 days
Cash equivalents:
Money market funds	863		None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Equity - commingled funds	$	65	None	Daily/Monthly	Daily/7 days
Debt - commingled funds	16		None	Daily	5 days
Trust-owned life insurance	118		None	Daily	15 days
Cash equivalents:
Money market funds	287		None	Daily	Not applicable
Georgia Power
Nuclear decommissioning trusts:
Foreign equity funds	$	126	None	Monthly	5 days
Other - commingled funds	6		None	Daily	Not applicable
Other - money market funds	11		None	Daily	Not applicable
Cash equivalents:
Money market funds	406		None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds	$	18	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds	$	110	None	Daily	Not applicable
Southern Power
Cash equivalents:
Money market funds	$	3	None	Daily	Not applicable

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (the Funds) to comply with the NRC's regulations. The foreign equity fund in Georgia Power's nuclear decommissioning trusts seeks to provide long-term capital appreciation. In pursuing this investment objective, the foreign equity fund primarily invests in a diversified portfolio of equity securities of foreign companies, including those in emerging markets. These equity securities may include, but are not limited to, common stocks, preferred stocks, real estate investment trusts, convertible securities, depositary receipts (including American depositary receipts, European depositary receipts, and global depositary receipts), and rights and warrants to buy common stocks. Georgia Power may withdraw all or a portion of its investment on the last business day of each month subject to a minimum withdrawal of $1 million, provided that a minimum investment of $10 million remains. If notices of withdrawal exceed 20% of the aggregate value of the foreign equity fund, then the foreign equity fund's board may refuse to permit the withdrawal of all such investments and may scale down the amounts to be withdrawn pro rata and may further determine that any withdrawal that has been postponed will have priority on the subsequent withdrawal date.

The other-commingled funds and other-money market funds in Georgia Power's nuclear decommissioning trusts are invested primarily in a diversified portfolio of high-quality, short-term, liquid debt securities. The funds represent cash collateral received under the Funds' managers' securities lending program and/or excess cash held within each separate investment account.The primary objective of the funds is to provide a high level of current income consistent with stability of principal and liquidity. The funds invest primarily in, but not limited to, commercial paper, floating and variable rate demand notes, debt securities issued or guaranteed by the U.S. government or its agencies or instrumentalities, time deposits, repurchase agreements, municipal obligations, notes, and other high-quality short-term liquid debt securities that mature in 90 days or less. Redemptions are available on a same day basis up to the full amount of the investment in the fund. See Note 1 to the financial statements of Southern Company and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

Alabama Power's nuclear decommissioning trusts include investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trusts invest in the TOLI in order to minimize the impact of taxes on the portfolios and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trusts do not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. These commingled funds, along with other equity and debt commingled funds held in Alabama Power's nuclear decommissioning trusts, primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities may include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection. See Note 1 to the financial statements of Southern Company and Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. For the three months ended March 31, 2015, the change in fair value of the funds, including reinvested interest and dividends reduced by the funds' expenses, increased by $65 million at Southern Company. For the three months ended March 31, 2015, Alabama Power recorded an increase in fair value of $47 million as an increase in regulatory liabilities. Georgia Power recorded an increase in fair value of $18 million as a reduction of its regulatory asset related to its ARO.

The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the investment in the money market funds.

As of March 31, 2015, 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:
Southern Company	$	24,241	$	26,350
Alabama Power	$	6,922	$	7,696
Georgia Power	$	9,801	$	10,733
Gulf Power	$	1,370	$	1,501
Mississippi Power	$	2,251	$	2,323
Southern Power	$	1,621	$	1,789

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 offered to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power.

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Stockholders' Equity (Tables)

3 Months Ended

Mar. 31, 2015

Equity [Abstract]

Earnings per Share

Shares used to compute diluted earnings per share were as follows:

	Three Months Ended March 31, 2015	Three Months Ended March 31, 2014
	(in millions)
As reported shares	910	890
Effect of options and performance share award units	5	3
Diluted shares	915	893

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 Interest
	(in thousands)			(in millions)
Balance at December 31, 2014	908,502	(725	)	$	19,949		$	756	$	221	$	20,926
Net income after dividends on preferred and preference stock	—	—		508			—		—		508
Other comprehensive income (loss)	—	—		(15		)	—		—		(15		)
Stock issued	3,094	—		112			—		—		112
Stock-based compensation	—	—		53			—		—		53
Stock repurchased, at cost	—	(2,599	)	(115		)	—		—		(115		)
Cash dividends on common stock	—	—		(478		)	—		—		(478		)
Other	—	(11	)	3			—		—		3
Balance at March 31, 2015	911,596	(3,335	)	$	20,017		$	756	$	221	$	20,994
Balance at December 31, 2013	892,733	(5,647	)	$	19,008		$	756	$	—	$	19,764
Net income after dividends on preferred and preference stock	—	—		351			—		—		351
Other comprehensive income (loss)	—	—		2			—		—		2
Treasury stock re-issued	—	2,404		111			—		—		111
Stock issued	1,340	—		53			—		—		53
Stock repurchased, at cost	—	—		(4		)	—		—		(4		)
Cash dividends on common stock	—	—		(451		)	—		—		(451		)
Other	—	(18	)	—			—		—		—
Balance at March 31, 2014	894,073	(3,261	)	$	19,070		$	756	$	—	$	19,826

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Introduction (Policies)

3 Months Ended

Mar. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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

In May 2014, the Financial Accounting Standards Board (FASB) issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition. On April 29, 2015, the FASB issued an exposure draft proposing the standard be effective for fiscal years beginning after December 15, 2017. The registrants continue to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

On February 18, 2015, the FASB issued Accounting Standards Update (ASU) 2015-02, Amendments to the Consolidation Analysis, which makes certain changes to both the variable interest model and the voting model, including changes to the identification of variable interests, the variable interest entity characteristics for a limited partnership or similar entity, and the primary beneficiary determination. This ASU is effective for fiscal years beginning after December 15, 2015. Southern Power is currently evaluating these requirements. The ultimate impact of this ASU on Southern Power has not yet been determined.

On April 7, 2015, the FASB issued ASU No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30):Simplifying the Presentation of Debt Issuance Costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability and is effective for fiscal years beginning after December 15, 2015. Southern Company currently reflects unamortized debt issuance costs in unamortized debt issuance expense on its balance sheet. The traditional operating companies and Southern Power currently reflect unamortized debt issuance costs in other deferred charges and assets on their balance sheets. Upon adoption, the reclassification will not have a material impact on the results of operations, financial position, or cash flows of any registrant.

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 financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally, implied volatility of interest rate options. See Note (H) herein for additional information on how these derivatives are used.

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' judgment, are also obtained when available.

Investments in private equity and real estate within Alabama Power's nuclear decommissioning trusts are generally classified as Level 3, as the underlying assets typically do not have observable inputs. The fund manager values these assets using various inputs and techniques depending on the nature of the underlying investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.

"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.

Energy-Related Derivatives

The traditional 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 operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional 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 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 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.

To mitigate residual risks relative to movements in electricity prices, the traditional operating companies and Southern Power may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the traditional operating companies and Southern Power may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

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 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 and 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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Effective Tax Rate and Unrecognized Tax Benefits

3 Months Ended

Mar. 31, 2015

Income Tax Disclosure [Abstract]

EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS

EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS

Effective Tax Rate

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

Southern Company

Southern Company's effective tax rate is typically lower than the statutory rate due to its employee stock plans' dividend deduction and non-taxable AFUDC equity.

Southern Company's effective tax rate was 34.3% for the three months ended March 31, 2015 compared to 32.3% for the corresponding period in 2014. The effective tax rate increase was due to higher net income and beneficial changes that impacted 2014 state income taxes.

Mississippi Power

Mississippi Power's effective tax rate was 10.0% for the three months ended March 31, 2015 compared to (43.0)% for the corresponding period in 2014. The increase was primarily due to higher net income, partially offset by a decrease in non-taxable AFUDC equity related to the construction of the Kemper IGCC.

Southern Power

Southern Power's effective tax rate was 25.8% for the three months ended March 31, 2015 compared to 8.5% for the corresponding period in 2014. The increase was primarily due to beneficial changes that impacted 2014 state income taxes, which was partially offset by increased federal income tax benefits related to ITCs in the current year.

Unrecognized Tax Benefits

Southern Company reduced tax payments for 2014, and included in its 2013 consolidated federal income tax return deductions for R&E expenditures related to the Kemper IGCC. The Kemper IGCC is based on first-of-a-kind technology, and Mississippi Power and Southern Company believe that a significant portion of the plant costs qualify as deductible R&E 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, Mississippi Power and Southern Company had related unrecognized tax benefits of approximately $211 million and associated interest of $3 million at March 31, 2015.

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

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Financing

3 Months Ended

Mar. 31, 2015

Debt Disclosure [Abstract]

FINANCING

FINANCING

Bank Credit Arrangements

Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional operating companies' variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2015 was approximately $1.8 billion (comprised of approximately $864 million at Alabama Power, $865 million at Georgia Power, $69 million at Gulf Power, and $40 million at Mississippi Power). In addition, at March 31, 2015, the traditional operating companies had approximately $396 million (comprised of approximately $200 million at Alabama Power, $118 million at Georgia Power, and $78 million at Gulf Power) of fixed rate pollution control revenue bonds outstanding that were required to be remarketed 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 for additional information. Subsequent to March 31, 2015, $80 million and $65 million of these fixed rate pollution control revenue bonds were purchased and are being held by Alabama Power and Georgia Power, respectively, and currently are not required to be remarketed within the next 12 months. See "Financing Activities" herein for additional information.

The following table outlines the committed credit arrangements by company as of March 31, 2015:

	Expires												Executable Term Loans				Due Within One Year
Company	2015		2016		2017		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)								(in millions)				(in millions)				(in millions)
Southern Company	$	—	$	—	$	—	$	1,000	$	1,000	$	1,000	$	—	$	—	$	—	$	—
Alabama Power	228		50		—		1,030		1,308		1,308		58		—		58		170
Georgia Power	—		150		—		1,600		1,750		1,736		—		—		—		150
Gulf Power	45		200		30		—		275		275		50		—		50		195
Mississippi Power	135		165		—		—		300		270		25		40		65		235
Southern Power	—		—		—		500		500		488		—		—		—		—
Other	70		—		—		—		70		70		20		—		20		50
Total	$	478	$	565	$	30	$	4,130	$	5,203	$	5,147	$	153	$	40	$	193	$	800

Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration.

Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first three months of 2015:

Company(a)	Senior Note Issuances		Senior Note Redemptions		Other Long-Term Debt Redemptions and Maturities(b)
	(in millions)
Alabama Power	$	550	$	250	$	—
Georgia Power	—		—		3
Mississippi Power	—		—		76
Other	—		—		4
Total	$	550	$	250	$	83

(a) Southern Company, Gulf Power, and Southern Power did not issue or redeem any long-term debt during the first three months of 2015.

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

Alabama Power

In March 2015, Alabama Power issued $550 million aggregate principal amount of Series 2015A 3.750% Senior Notes due March 1, 2045. The proceeds were used to redeem $250 million aggregate principal amount of Series DD 5.65% Senior Notes due March 15, 2035 and for general corporate purposes, including Alabama Power's continuous construction program.

Subsequent to March 31, 2015, Alabama Power purchased and held $80 million aggregate principal amount of Industrial Development Board of the City of Mobile, Alabama Pollution Control Revenue Bonds (Alabama Power Company Barry Plant Project), Series 2007-B. Alabama Power may reoffer these bonds to the public at a later date.

Also subsequent to March 31, 2015, Alabama Power issued $175 million additional aggregate principal amount of its Series 2015A 3.750% Senior Notes due March 1, 2045 (Additional Series 2015A Senior Notes) and $250 million aggregate principal amount of its Series 2015B 2.800% Senior Notes due April 1, 2025 (Series 2015B Senior Notes). A portion of the proceeds of the Additional Series 2015A Senior Notes and the Series 2015B Senior Notes will be used for the announced redemption on May 15, 2015 of 6.48 million shares ($162 million aggregate stated capital) of Alabama Power's 5.20% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, 4.0 million shares ($100 million aggregate stated capital) of Alabama Power's 5.30% Class A Preferred Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and 6.0 million shares ($150 million aggregate stated capital) of Alabama Power's 5.625% Series Preference Stock at a redemption price of $25 per share plus accrued and unpaid dividends to the redemption date, and the remaining net proceeds will be used for general corporate purposes, including Alabama Power's continuous construction program.

Georgia Power

Subsequent to March 31, 2015, Georgia Power purchased and held $65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008. Georgia Power may reoffer these bonds to the public at a later date.

Mississippi Power

Subsequent to March 31, 2015, Mississippi Power entered into two floating rate bank loans with a maturity date of April 1, 2016, in an aggregate principal amount of $475 million, bearing interest based on one-month LIBOR. The proceeds of these loans were used for the repayment of term loans in an aggregate principal amount of $275 million, working capital, and other general corporate purposes, including Mississippi Power's ongoing construction program. Mississippi Power also amended three outstanding floating rate bank loans for an aggregate principal amount of $425 million which, among other things, extended the maturity dates from various dates in 2015 to April 1, 2016.

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Retirement Benefits

3 Months Ended

Mar. 31, 2015

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, 2015. 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 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 months ended March 31, 2015 and 2014 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended March 31, 2015
Service cost	$	64		$	15		$	18		$	3		$	3
Interest cost	111			26			38			5			5
Expected return on plan assets	(181		)	(45		)	(63		)	(8		)	(8		)
Amortization:
Prior service costs	6			2			3			—			—
Net (gain)/loss	54			14			19			3			3
Net cost	$	54		$	12		$	15		$	3		$	3
Three Months Ended March 31, 2014
Service cost	$	53		$	12		$	16		$	3		$	3
Interest cost	109			26			38			5			5
Expected return on plan assets	(161		)	(42		)	(57		)	(7		)	(7		)
Amortization:
Prior service costs	6			1			3			—			—
Net (gain)/loss	28			8			10			1			1
Net cost	$	35		$	5		$	10		$	2		$	2

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power
	(in millions)
Three Months Ended March 31, 2015
Service cost	$	6		$	1		$	2		$	—	$	—
Interest cost	19			5			8			1		1
Expected return on plan assets	(15		)	(6		)	(6		)	—		—
Amortization:
Prior service costs	1			1			—			—		—
Net (gain)/loss	5			—			3			—		—
Net cost	$	16		$	1		$	7		$	1	$	1
Three Months Ended March 31, 2014
Service cost	$	5		$	1		$	2		$	—	$	—
Interest cost	20			5			8			1		1
Expected return on plan assets	(15		)	(6		)	(6		)	—		—
Amortization:
Prior service costs	1			1			—			—		—
Net (gain)/loss	1			—			—			—		—
Net cost	$	12		$	1		$	4		$	1	$	1

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Derivatives

3 Months Ended

Mar. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES

DERIVATIVES

Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. 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) herein 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.

Energy-Related Derivatives

The traditional 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 operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional 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 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 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.

To mitigate residual risks relative to movements in electricity prices, the traditional operating companies and Southern Power may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the traditional operating companies and Southern Power may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

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 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 and 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 March 31, 2015, 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	241	2020	2017
Alabama Power	54	2018	—
Georgia Power	44	2017	—
Gulf Power	92	2020	—
Mississippi Power	49	2018	—
Southern Power	2	—	2017

In addition to the volumes discussed in the above table, the traditional 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 4 million mmBtu for Southern Company, 3 million mmBtu for Georgia Power, and 1 million mmBtu for Southern Power.

For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending March 31, 2016 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.

At March 31, 2015, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date	Fair Value Gain (Loss) at March 31, 2015
	(in millions)					(in millions)
Cash Flow Hedges of Forecasted Debt
Alabama Power	$	200	3-month LIBOR	2.93%	October 2025	$	(14	)
Georgia Power	350		3-month LIBOR	2.57%	May 2025	(17		)
Georgia Power	350		3-month LIBOR	2.57%	November 2025	(13		)
Cash Flow Hedges of Existing Debt
Georgia Power	250		3-month LIBOR + 0.32%	0.75%	March 2016	—
Georgia Power	200		3-month LIBOR + 0.40%	1.01%	August 2016	—
Fair Value Hedges on Existing Debt
Southern Company	250		1.30%	3-month LIBOR + 0.17%	August 2017	1
Georgia Power	250		5.40%	3-month LIBOR + 4.02%	June 2018	2
Georgia Power	200		4.25%	3-month LIBOR + 2.46%	December 2019	4
Total	$	2,050				$	(37	)

The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending March 31, 2016 are immaterial for all registrants. Southern Company and certain subsidiaries have deferred gains and losses that are expected to be amortized into earnings through 2037.

Derivative Financial Statement Presentation and Amounts

At March 31, 2015, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at March 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	$	6	$	1	$	5	$	—	$	—
Other deferred charges and assets	1		—		1		—		—
Total derivatives designated as hedging instruments for regulatory purposes	$	7	$	1	$	6	$	—	$	—	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	7	$	—	$	5	$	—	$	—	$	—
Other deferred charges and assets	1		—		1		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	8	$	—	$	6	$	—	$	—	$	—
Total asset derivatives	$	15	$	1	$	12	$	—	$	—	$	—

Liability Derivatives at March 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 liabilities(*)	$	117	$	33	$	21	$	37	$	26
Other deferred credits and liabilities	108		26		3		53		26
Total derivatives designated as hedging instruments for regulatory purposes	$	225	$	59	$	24	$	90	$	52	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current liabilities(*)	$	45	$	14	$	31	$	—	$	—	$	—
Other deferred credits and liabilities	1		—		—		—		—		—
Total derivatives designed as hedging instruments in cash flow and fair value hedges	$	46	$	14	$	31	$	—	$	—	$	—
Total liability derivatives	$	271	$	73	$	55	$	90	$	52	$	—

(*) Georgia Power and Gulf Power include current liabilities related to derivatives designated as hedging instruments in "Liabilities from risk management activities."

At December 31, 2014, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at December 31, 2014
	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	$	7	$	1	$	6	$	—	$	—
Other deferred charges and assets	—		—		1		—		—
Total derivatives designated as hedging instruments for regulatory purposes	$	7	$	1	$	7	$	—	$	—	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	7	$	—	$	5	$	—	$	—	$	—
Other deferred charges and assets	1		—		1		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	8	$	—	$	6	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets(*)	$	6	$	—	$	—	$	—	$	—	$	5
Total asset derivatives	$	21	$	1	$	13	$	—	$	—	$	5

(*) Southern Power includes current assets related to derivatives not designated as hedging instruments in "Assets from risk management activities."

Liability Derivatives at December 31, 2014
	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 liabilities(*)	$	118	$	32	$	23	$	37	$	26
Other deferred credits and liabilities	79		21		4		35		19
Total derivatives designated as hedging instruments for regulatory purposes	$	197	$	53	$	27	$	72	$	45	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current liabilities(*)	$	17	$	8	$	9	$	—	$	—	$	—
Other deferred credits and liabilities	7		—		5		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	24	$	8	$	14	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current liabilities	$	4	$	—	$	—	$	—	$	—	$	4
Total liability derivatives	$	225	$	61	$	41	$	72	$	45	$	4

(*) Georgia Power and Gulf Power include current liabilities related to derivatives designated as hedging instruments in "Liabilities from risk management activities."

The derivative contracts of Southern Company, the traditional 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 and interest rate derivative contracts at March 31, 2015 and December 31, 2014 are presented in the following tables.

Derivative Contracts at March 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		$	6		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(6		)	(1		)	(6		)	—		—		—
Net energy-related derivative assets	$	1		$	—		$	—		$	—	$	—	$	—
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	8		$	—		$	6		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(2		)	—			(2		)	—		—		—
Net interest rate derivative assets	$	6		$	—		$	4		$	—	$	—	$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	225		$	59		$	24		$	90	$	52	$	—
Gross amounts not offset in the Balance Sheet (b)	(6		)	(1		)	(6		)	—		—		—
Net energy-related derivative liabilities	$	219		$	58		$	18		$	90	$	52	$	—
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	46		$	14		$	31		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(2		)	—			(2		)	—		—		—
Net interest rate derivative liabilities	$	44		$	14		$	29		$	—	$	—	$	—

(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, 2014
	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)	$	13		$	1	$	7		$	—	$	—	$	5
Gross amounts not offset in the Balance Sheet (b)	(9		)	—		(7		)	—		—		—
Net energy-related derivative assets	$	4		$	1	$	—		$	—	$	—	$	5
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	8		$	—	$	6		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(8		)	—		(6		)	—		—		—
Net interest rate derivative assets	$	—		$	—	$	—		$	—	$	—	$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	201		$	53	$	27		$	72	$	45	$	4
Gross amounts not offset in the Balance Sheet (b)	(9		)	—		(7		)	—		—		—
Net energy-related derivative liabilities	$	192		$	53	$	20		$	72	$	45	$	4
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	24		$	8	$	14		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(8		)	—		(6		)	—		—		—
Net interest rate derivative liabilities	$	16		$	8	$	8		$	—	$	—	$	—

(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 March 31, 2015 and December 31, 2014, 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 March 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	$	(117	)	$	(33	)	$	(21	)	$	(37	)	$	(26	)
Other regulatory assets, deferred	(108		)	(26		)	(3		)	(53		)	(26		)
Other regulatory liabilities, current (a)	6			1			5			—			—
Other regulatory liabilities, deferred (b)	1			—			1			—			—
Total energy-related derivative gains (losses)	$	(218	)	$	(58	)	$	(18	)	$	(90	)	$	(52	)

(a) Southern Company and Georgia Power include 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, 2014
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	$	(118	)	$	(32	)	$	(23	)	$	(37	)	$	(26	)
Other regulatory assets, deferred	(79		)	(21		)	(4		)	(35		)	(19		)
Other regulatory liabilities, current (a)	7			1			6			—			—
Other regulatory liabilities, deferred (b)	—			—			1			—			—
Total energy-related derivative gains (losses)	$	(190	)	$	(52	)	$	(20	)	$	(72	)	$	(45	)

(a) Southern Company and Georgia Power include other regulatory liabilities, current in other current liabilities.

(b) Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.

For the three months ended March 31, 2015 and 2014, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income 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
	2015			2014			2015			2014
	(in millions)						(in millions)
Southern Company
Interest rate derivatives	$	(29	)	$	—	Interest expense, net of amounts capitalized	$	(2	)	$	(2	)
Alabama Power
Interest rate derivatives	$	(6	)	$	—	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Georgia Power
Interest rate derivatives	$	(23	)	$	—	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)

For the three months ended March 31, 2015 and 2014, 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 March 31, 2015 and 2014, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were immaterial on a gross basis for all registrants. Furthermore, 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 months ended March 31, 2015 and 2014, the pre-tax effects of energy-related 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 March 31, 2015, the registrants' collateral posted with their derivative counterparties was immaterial.

At March 31, 2015, the fair value of derivative liabilities with contingent features was $59 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 $59 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 operating companies, and Southern Power are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional 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 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 operating companies', and Southern Power's exposure to counterparty credit risk. Therefore, Southern Company, the traditional operating companies, and Southern Power do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

XML

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
Fair Value, Measurements, Recurring [Member]
Assets:
Derivative Asset, Fair Value, Gross Asset	$ 7
Interest Rate Derivative Assets, at Fair Value	8
Nuclear decommissioning trusts	1,573	[1]
Cash equivalents	863
Other investments	10
Total	2,461
Liabilities:
Derivative Liability, Fair Value, Gross Liability	225
Interest rate derivatives	46
Total	271
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Derivative Asset, Fair Value, Gross Asset	0
Interest Rate Derivative Assets, at Fair Value	0
Nuclear decommissioning trusts	632	[1]
Cash equivalents	863
Other investments	9
Total	1,504
Liabilities:
Derivative Liability, Fair Value, Gross Liability	0
Interest rate derivatives	0
Total	0
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Derivative Asset, Fair Value, Gross Asset	7
Interest Rate Derivative Assets, at Fair Value	8
Nuclear decommissioning trusts	937	[1]
Cash equivalents	0
Other investments	0
Total	952
Liabilities:
Derivative Liability, Fair Value, Gross Liability	225
Interest rate derivatives	46
Total	271
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Derivative Asset, Fair Value, Gross Asset	0
Interest Rate Derivative Assets, at Fair Value	0
Nuclear decommissioning trusts	4	[1]
Cash equivalents	0
Other investments	1
Total	5
Liabilities:
Derivative Liability, Fair Value, Gross Liability	0
Interest rate derivatives	0
Total	0
Alabama Power [Member]
Assets:
Derivative Asset, Fair Value, Gross Asset	1		1
Liabilities:
Derivative Liability, Fair Value, Gross Liability	73		61
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Derivative Asset, Fair Value, Gross Asset	1
Cash equivalents	287
Total	1,057
Liabilities:
Derivative Liability, Fair Value, Gross Liability	59
Interest rate derivatives	14
Total	73
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	483	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	101	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	34	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	123	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	18	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	10	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Derivative Asset, Fair Value, Gross Asset	0
Cash equivalents	287
Total	726
Liabilities:
Derivative Liability, Fair Value, Gross Liability	0
Interest rate derivatives	0
Total	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	393	[2]
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	36	[2]
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	[2]
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	10	[2]
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	[2]
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	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Derivative Asset, Fair Value, Gross Asset	1
Cash equivalents	0
Total	327
Liabilities:
Derivative Liability, Fair Value, Gross Liability	59
Interest rate derivatives	14
Total	73
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	90	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	65	[2]
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	34	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	113	[2]
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	18	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	6	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Derivative Asset, Fair Value, Gross Asset	0
Cash equivalents	0
Total	4
Liabilities:
Derivative Liability, Fair Value, Gross Liability	0
Interest rate derivatives	0
Total	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	0	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	0	[2]
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	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	0	[2]
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	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	4	[2]
Georgia Power [Member]
Assets:
Derivative Asset, Fair Value, Gross Asset	12		13
Nuclear decommissioning trusts	50
Liabilities:
Derivative Liability, Fair Value, Gross Liability	55		41
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Derivative Asset, Fair Value, Gross Asset	6
Interest Rate Derivative Assets, at Fair Value	6
Cash equivalents	406
Total	1,222
Liabilities:
Derivative Liability, Fair Value, Gross Liability	24
Interest rate derivatives	31
Total	55
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	184	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	126	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	86	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	92	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	192	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	107	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	17	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Derivative Asset, Fair Value, Gross Asset	0
Interest Rate Derivative Assets, at Fair Value	0
Cash equivalents	406
Total	599
Liabilities:
Derivative Liability, Fair Value, Gross Liability	0
Interest rate derivatives	0
Total	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	182	[2],[3]
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	[2],[3]
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	[2],[3]
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	[2],[3]
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	[2],[3]
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	[2],[3]
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	11	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Derivative Asset, Fair Value, Gross Asset	6
Interest Rate Derivative Assets, at Fair Value	6
Cash equivalents	0
Total	623
Liabilities:
Derivative Liability, Fair Value, Gross Liability	24
Interest rate derivatives	31
Total	55
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	2	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	126	[2],[3]
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	86	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	92	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	192	[2],[3]
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	107	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	6	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Derivative Asset, Fair Value, Gross Asset	0
Interest Rate Derivative Assets, at Fair Value	0
Cash equivalents	0
Total	0
Liabilities:
Derivative Liability, Fair Value, Gross Liability	0
Interest rate derivatives	0
Total	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	0	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	0	[2],[3]
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	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	0	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	0	[2],[3]
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	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	0	[2],[3]
Gulf Power [Member]
Assets:
Derivative Asset, Fair Value, Gross Asset	0		0
Liabilities:
Derivative Liability, Fair Value, Gross Liability	90		72
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Cash equivalents	18
Liabilities:
Derivative Liability, Fair Value, Gross Liability	90
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Cash equivalents	18
Liabilities:
Derivative Liability, Fair Value, Gross Liability	0
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Cash equivalents	0
Liabilities:
Derivative Liability, Fair Value, Gross Liability	90
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Cash equivalents	0
Liabilities:
Derivative Liability, Fair Value, Gross Liability	0
Mississippi Power [Member]
Assets:
Derivative Asset, Fair Value, Gross Asset	0		0
Liabilities:
Derivative Liability, Fair Value, Gross Liability	52		45
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Cash equivalents	110
Liabilities:
Derivative Liability, Fair Value, Gross Liability	52
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Cash equivalents	110
Liabilities:
Derivative Liability, Fair Value, Gross Liability	0
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Cash equivalents	0
Liabilities:
Derivative Liability, Fair Value, Gross Liability	52
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Cash equivalents	0
Liabilities:
Derivative Liability, Fair Value, Gross Liability	0
Southern Power [Member]
Assets:
Derivative Asset, Fair Value, Gross Asset	0		5
Liabilities:
Derivative Liability, Fair Value, Gross Liability	0		4
Southern Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Cash equivalents	3
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Cash equivalents	3
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Cash equivalents	0
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Cash equivalents	$ 0

[1] For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.

[2] Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies.

[3] Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of March 31, 2015, approximately $50 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan and pledged to creditors under the funds' managers' securities lending program.

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Segment and Related Information - Financial Data for Business Segments (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				12 Months Ended
	Mar. 31, 2015		Mar. 31, 2014		Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Number of States in which Entity Operates	4
Operating revenues	$ 4,183		$ 4,644
Segment net income (loss)	508	[1],[2]	351	[1],[2]
Total assets	71,610				70,923
Kemper Igcc [Member]
Segment Reporting Information [Line Items]
Pre-tax charge to income	9		380		868	1,200
After tax charge to income	6		235		536	729
Electric Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues	4,172		4,627
Segment net income (loss)	510	[1],[2]	351	[1],[2]
Total assets	70,821				70,063
Traditional Operating Companies [Member] | Electric Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues	3,948		4,378
Segment net income (loss)	477	[1],[2]	318	[1],[2]
Total assets	65,530				64,644
Southern Power [Member]
Segment Reporting Information [Line Items]
Operating revenues	114		72
Southern Power [Member] | Electric Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues	348		351
Segment net income (loss)	33	[1],[2]	33	[1],[2]
Total assets	5,564				5,550
Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	(29)		(24)
Segment net income (loss)	(5)	[1],[2]	0	[1],[2]
Total assets	(302)				(296)
Eliminations [Member] | Electric Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues	(124)		(102)
Segment net income (loss)	0	[1],[2]	0	[1],[2]
Total assets	(273)				(131)
All Other [Member]
Segment Reporting Information [Line Items]
Operating revenues	40		41
Segment net income (loss)	3	[1],[2]	0	[1],[2]
Total assets	$ 1,091				$ 1,156

[1] Segment net income (loss) for the traditional operating companies for the three months ended March 31, 2015 and March 31, 2014 includes a $9 million pre-tax charge ($6 million after tax) and a $380 million pre-tax charge ($235 million after tax), respectively, for estimated probable losses on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

[2] After dividends on preferred and preference stock of subsidiaries.

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Contingencies and Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Schedule of Recovery Balance of Each Regulatory Clause

The recovery balance of each regulatory clause follows:

Regulatory Clause	Balance Sheet Line Item	March 31, 2015		December 31, 2014
		(in millions)
Rate CNP Compliance – Under*	Deferred under recovered regulatory clause revenues	$	25	$	2
	Under recovered regulatory clause revenues, current	16		47
Rate CNP PPA – Under	Deferred under recovered regulatory clause revenues	62		29
	Under recovered regulatory clause revenues, current	—		27
Retail Energy Cost Recovery – Over	Deferred over recovered regulatory clause revenues	81		47
Natural Disaster Reserve	Other regulatory liabilities, deferred	82		84

* Formerly Known As Rate CNP Environmental

Recovery Position of Each Regulatory Clause

The recovery balance of each regulatory clause follows:

Recovery Clause	Balance Sheet Location	March 31, 2015		December 31, 2014
		(in millions)
Fuel Cost Recovery – Under	Under recovered regulatory clause revenues	$	32	$	40
Purchased Power Capacity Recovery – Under	Under recovered regulatory clause revenues	3		—
Environmental Cost Recovery – Under	Under recovered regulatory clause revenues	12		10
Energy Conservation Cost Recovery – Under	Under recovered regulatory clause revenues	1		3

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), and actual costs incurred as of March 31, 2015, as adjusted for the Court's decision, are as follows:

Cost Category	2010 Project Estimate(f)		Current Estimate		Actual Costs at March 31, 2015
	(in billions)
Plant Subject to Cost Cap(a)	$	2.40	$	4.94	$	4.37
Lignite Mine and Equipment	0.21		0.23		0.23
CO2 Pipeline Facilities	0.14		0.11		0.10
AFUDC(b)(c)	0.17		0.64		0.48
Combined Cycle and Related Assets Placed in Service – Incremental(d)	—		0.02		—
General Exceptions	0.05		0.10		0.08
Deferred Costs(c)(e)	—		0.18		0.14
Total Kemper IGCC(a)(c)	$	2.97	$	6.22	$	5.40

(a) The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and 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" for additional information.

(b) Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate includes an approximately $9 million increase in AFUDC related to a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.

(c) Amounts in the Current Estimate reflect estimated costs through March 31, 2016.

(d) Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information.

(e) The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities."

(f) The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificatedestimate for the CO₂ pipeline facilities which was approved in 2011 by the Mississippi PSC.

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Derivatives (Tables)

3 Months Ended

Mar. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of derivatives

At March 31, 2015, 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	241	2020	2017
Alabama Power	54	2018	—
Georgia Power	44	2017	—
Gulf Power	92	2020	—
Mississippi Power	49	2018	—
Southern Power	2	—	2017

Notional amount of interest rate derivatives

At March 31, 2015, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date	Fair Value Gain (Loss) at March 31, 2015
	(in millions)					(in millions)
Cash Flow Hedges of Forecasted Debt
Alabama Power	$	200	3-month LIBOR	2.93%	October 2025	$	(14	)
Georgia Power	350		3-month LIBOR	2.57%	May 2025	(17		)
Georgia Power	350		3-month LIBOR	2.57%	November 2025	(13		)
Cash Flow Hedges of Existing Debt
Georgia Power	250		3-month LIBOR + 0.32%	0.75%	March 2016	—
Georgia Power	200		3-month LIBOR + 0.40%	1.01%	August 2016	—
Fair Value Hedges on Existing Debt
Southern Company	250		1.30%	3-month LIBOR + 0.17%	August 2017	1
Georgia Power	250		5.40%	3-month LIBOR + 4.02%	June 2018	2
Georgia Power	200		4.25%	3-month LIBOR + 2.46%	December 2019	4
Total	$	2,050				$	(37	)

Fair value of energy-related derivatives and interest rate derivatives

At March 31, 2015, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at March 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	$	6	$	1	$	5	$	—	$	—
Other deferred charges and assets	1		—		1		—		—
Total derivatives designated as hedging instruments for regulatory purposes	$	7	$	1	$	6	$	—	$	—	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	7	$	—	$	5	$	—	$	—	$	—
Other deferred charges and assets	1		—		1		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	8	$	—	$	6	$	—	$	—	$	—
Total asset derivatives	$	15	$	1	$	12	$	—	$	—	$	—

Liability Derivatives at March 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 liabilities(*)	$	117	$	33	$	21	$	37	$	26
Other deferred credits and liabilities	108		26		3		53		26
Total derivatives designated as hedging instruments for regulatory purposes	$	225	$	59	$	24	$	90	$	52	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current liabilities(*)	$	45	$	14	$	31	$	—	$	—	$	—
Other deferred credits and liabilities	1		—		—		—		—		—
Total derivatives designed as hedging instruments in cash flow and fair value hedges	$	46	$	14	$	31	$	—	$	—	$	—
Total liability derivatives	$	271	$	73	$	55	$	90	$	52	$	—

(*) Georgia Power and Gulf Power include current liabilities related to derivatives designated as hedging instruments in "Liabilities from risk management activities."

At December 31, 2014, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at December 31, 2014
	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	$	7	$	1	$	6	$	—	$	—
Other deferred charges and assets	—		—		1		—		—
Total derivatives designated as hedging instruments for regulatory purposes	$	7	$	1	$	7	$	—	$	—	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	7	$	—	$	5	$	—	$	—	$	—
Other deferred charges and assets	1		—		1		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	8	$	—	$	6	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets(*)	$	6	$	—	$	—	$	—	$	—	$	5
Total asset derivatives	$	21	$	1	$	13	$	—	$	—	$	5

(*) Southern Power includes current assets related to derivatives not designated as hedging instruments in "Assets from risk management activities."

Liability Derivatives at December 31, 2014
	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 liabilities(*)	$	118	$	32	$	23	$	37	$	26
Other deferred credits and liabilities	79		21		4		35		19
Total derivatives designated as hedging instruments for regulatory purposes	$	197	$	53	$	27	$	72	$	45	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current liabilities(*)	$	17	$	8	$	9	$	—	$	—	$	—
Other deferred credits and liabilities	7		—		5		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	24	$	8	$	14	$	—	$	—	$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current liabilities	$	4	$	—	$	—	$	—	$	—	$	4
Total liability derivatives	$	225	$	61	$	41	$	72	$	45	$	4

(*) Georgia Power and Gulf Power include current liabilities related to derivatives designated as hedging instruments in "Liabilities from risk management activities."

Offsetting disclosure tables

Amounts related to energy-related derivative contracts and interest rate derivative contracts at March 31, 2015 and December 31, 2014 are presented in the following tables.

Derivative Contracts at March 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		$	6		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(6		)	(1		)	(6		)	—		—		—
Net energy-related derivative assets	$	1		$	—		$	—		$	—	$	—	$	—
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	8		$	—		$	6		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(2		)	—			(2		)	—		—		—
Net interest rate derivative assets	$	6		$	—		$	4		$	—	$	—	$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	225		$	59		$	24		$	90	$	52	$	—
Gross amounts not offset in the Balance Sheet (b)	(6		)	(1		)	(6		)	—		—		—
Net energy-related derivative liabilities	$	219		$	58		$	18		$	90	$	52	$	—
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	46		$	14		$	31		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(2		)	—			(2		)	—		—		—
Net interest rate derivative liabilities	$	44		$	14		$	29		$	—	$	—	$	—

(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, 2014
	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)	$	13		$	1	$	7		$	—	$	—	$	5
Gross amounts not offset in the Balance Sheet (b)	(9		)	—		(7		)	—		—		—
Net energy-related derivative assets	$	4		$	1	$	—		$	—	$	—	$	5
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	8		$	—	$	6		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(8		)	—		(6		)	—		—		—
Net interest rate derivative assets	$	—		$	—	$	—		$	—	$	—	$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	201		$	53	$	27		$	72	$	45	$	4
Gross amounts not offset in the Balance Sheet (b)	(9		)	—		(7		)	—		—		—
Net energy-related derivative liabilities	$	192		$	53	$	20		$	72	$	45	$	4
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	24		$	8	$	14		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(8		)	—		(6		)	—		—		—
Net interest rate derivative liabilities	$	16		$	8	$	8		$	—	$	—	$	—

(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 March 31, 2015 and December 31, 2014, 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 March 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	$	(117	)	$	(33	)	$	(21	)	$	(37	)	$	(26	)
Other regulatory assets, deferred	(108		)	(26		)	(3		)	(53		)	(26		)
Other regulatory liabilities, current (a)	6			1			5			—			—
Other regulatory liabilities, deferred (b)	1			—			1			—			—
Total energy-related derivative gains (losses)	$	(218	)	$	(58	)	$	(18	)	$	(90	)	$	(52	)

(a) Southern Company and Georgia Power include 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, 2014
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	$	(118	)	$	(32	)	$	(23	)	$	(37	)	$	(26	)
Other regulatory assets, deferred	(79		)	(21		)	(4		)	(35		)	(19		)
Other regulatory liabilities, current (a)	7			1			6			—			—
Other regulatory liabilities, deferred (b)	—			—			1			—			—
Total energy-related derivative gains (losses)	$	(190	)	$	(52	)	$	(20	)	$	(72	)	$	(45	)

(a) Southern Company and Georgia Power include other regulatory liabilities, current in other current liabilities.

(b) Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.

Pre-tax effects of interest rate derivatives

For the three months ended March 31, 2015 and 2014, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income 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
	2015			2014			2015			2014
	(in millions)						(in millions)
Southern Company
Interest rate derivatives	$	(29	)	$	—	Interest expense, net of amounts capitalized	$	(2	)	$	(2	)
Alabama Power
Interest rate derivatives	$	(6	)	$	—	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Georgia Power
Interest rate derivatives	$	(23	)	$	—	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)

XML

Derivatives - Narrative (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015 Btu
Derivatives (Textual) [Abstract]
Maximum Potential Collateral Requirements Arising from Credit Risk Related Contingent Features	59
Southern Company [Member]
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	4,000,000
Georgia Power [Member]
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	3,000,000
Maximum Potential Collateral Requirements Arising from Credit Risk Related Contingent Features	59
Southern Power [Member]
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	1,000,000
Maximum Potential Collateral Requirements Arising from Credit Risk Related Contingent Features	59
Alabama Power [Member]
Derivatives (Textual) [Abstract]
Maximum Potential Collateral Requirements Arising from Credit Risk Related Contingent Features	59
Gulf Power [Member]
Derivatives (Textual) [Abstract]
Maximum Potential Collateral Requirements Arising from Credit Risk Related Contingent Features	59
Mississippi Power [Member]
Derivatives (Textual) [Abstract]
Maximum Potential Collateral Requirements Arising from Credit Risk Related Contingent Features	59

XML

Financing - Schedule of Long-Term Debt Financing Activities (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015
Debt Instrument [Line Items]
Senior Note Issuances	$ 550	[1]
Senior Note Redemptions	250	[1]
Debt Redemptions [Member]
Debt Instrument [Line Items]
Other Long-Term Debt	83	[1],[2]
Alabama Power [Member]
Debt Instrument [Line Items]
Senior Note Issuances	550	[1]
Senior Note Redemptions	250	[1]
Alabama Power [Member] | Debt Redemptions [Member]
Debt Instrument [Line Items]
Other Long-Term Debt	0	[1],[2]
Georgia Power [Member]
Debt Instrument [Line Items]
Senior Note Issuances	0	[1]
Senior Note Redemptions	0	[1]
Georgia Power [Member] | Debt Redemptions [Member]
Debt Instrument [Line Items]
Other Long-Term Debt	3	[1],[2]
Mississippi Power [Member]
Debt Instrument [Line Items]
Senior Note Issuances	0	[1]
Senior Note Redemptions	0	[1]
Mississippi Power [Member] | Debt Redemptions [Member]
Debt Instrument [Line Items]
Other Long-Term Debt	76	[1],[2]
Other Subsidiaries [Member]
Debt Instrument [Line Items]
Senior Note Issuances	0	[1]
Senior Note Redemptions	0	[1]
Other Subsidiaries [Member] | Debt Redemptions [Member]
Debt Instrument [Line Items]
Other Long-Term Debt	$ 4	[1],[2]

[1] Southern Company, Gulf Power, and Southern Power did not issue or redeem any long-term debt during the first three months of 2015.

[2] Includes reductions in capital lease obligations resulting from cash payments under capital leases.

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Southern Company [Member]
Operating Activities:
Net income (loss)	$ 525	$ 368
Adjustments to reconcile net income (loss) to net cash provided from operating activities --
Depreciation and amortization, total	578	587
Deferred income taxes	113	(37)
Allowance for equity funds used during construction	(63)	(57)
Stock based compensation expense	56	28
Estimated loss on Kemper IGCC	9	380
Other, net	4	(42)
Changes in certain current assets and liabilities --
-Receivables	180	(128)
-Fossil fuel stock	76	441
-Materials and supplies	4	(5)
-Other current assets	(89)	(114)
-Accounts payable	(426)	(109)
-Accrued taxes	197	(44)
-Accrued compensation	(381)	(144)
-Mirror CWIP	40	34
-Other current liabilities	90	(55)
Net cash provided from operating activities	913	1,103
Investing Activities:
Property additions	(1,097)	(1,180)
Distribution of restricted cash	0	9
Nuclear decommissioning trust fund purchases	(290)	(231)
Nuclear decommissioning trust fund sales	284	229
Cost of removal, net of salvage	(36)	(22)
Change in construction payables	65	51
Prepaid long-term service agreement	(37)	(64)
Other investing activities	4	(7)
Net cash used for investing activities	(1,107)	(1,215)
Financing Activities:
Increase (decrease) in notes payable, net	597	(884)
Proceeds --
Long-term debt issuances	550	1,251
Interest-bearing refundable deposit	0	75
Common stock issuances	112	128
Short-term borrowings	280	0
Redemptions --
Long-term debt	(333)	(9)
Common stock repurchased	(115)	(4)
Payment of common stock dividends	(478)	(451)
Payment of dividends on preferred and preference stock of subsidiaries	(17)	(17)
Other financing activities	0	(46)
Net cash provided from (used for) financing activities	596	43
Net Change in Cash and Cash Equivalents	402	(69)
Cash and Cash Equivalents at Beginning of Period	710	659
Cash and Cash Equivalents at End of Period	1,112	590
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	207	186
Income taxes, net	(289)	(7)
Noncash transactions - Accrued property additions at end of period	347	450
Alabama Power [Member]
Operating Activities:
Net income (loss)	179	197
Adjustments to reconcile net income (loss) to net cash provided from operating activities --
Depreciation and amortization, total	196	210
Deferred income taxes	16	25
Allowance for equity funds used during construction	(15)	(10)
Other, net	2	(22)
Changes in certain current assets and liabilities --
-Receivables	(3)	(17)
-Fossil fuel stock	0	99
-Materials and supplies	12	3
-Other current assets	(80)	(81)
-Accounts payable	(229)	(139)
-Accrued taxes	246	147
-Accrued compensation	(89)	(37)
-Retail fuel cost over recovery - short-term	34	(20)
-Other current liabilities	21	(3)
Net cash provided from operating activities	290	352
Investing Activities:
Property additions	(325)	(287)
Nuclear decommissioning trust fund purchases	(129)	(56)
Nuclear decommissioning trust fund sales	129	56
Cost of removal, net of salvage	(13)	(12)
Change in construction payables	34	49
Other investing activities	(9)	(5)
Net cash used for investing activities	(313)	(255)
Proceeds --
Senior notes issuances	550	0
Capital contributions from parent company	6	7
Redemptions --
Senior notes	(250)	0
Payment of preferred and preference stock dividends	(10)	(10)
Payment of common stock dividends	(143)	(137)
Other financing activities	(8)	0
Net cash provided from (used for) financing activities	145	(140)
Net Change in Cash and Cash Equivalents	122	(43)
Cash and Cash Equivalents at Beginning of Period	273	295
Cash and Cash Equivalents at End of Period	395	252
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	68	61
Income taxes, net	(136)	(28)
Noncash transactions - Accrued property additions at end of period	41	66
Georgia Power [Member]
Operating Activities:
Net income (loss)	240	270
Adjustments to reconcile net income (loss) to net cash provided from operating activities --
Depreciation and amortization, total	256	250
Deferred income taxes	(7)	96
Allowance for equity funds used during construction	(15)	(6)
Retail fuel cost over recovery - long-term	0	(44)
Deferred expenses	33	33
Pension, postretirement, and other employee benefits	6	(4)
Other, net	(2)	(10)
Changes in certain current assets and liabilities --
-Receivables	166	(83)
-Fossil fuel stock	67	257
-Prepaid income taxes	170	(11)
-Other current assets	(13)	(12)
-Accounts payable	(261)	(28)
-Accrued taxes	(217)	(166)
-Accrued compensation	(81)	(38)
-Retail fuel cost over recovery - short-term	0	(14)
-Other current liabilities	21	9
Net cash provided from operating activities	363	499
Investing Activities:
Property additions	(422)	(460)
Nuclear decommissioning trust fund purchases	(161)	(175)
Nuclear decommissioning trust fund sales	155	173
Change in construction payables, net of joint owner portion	37	28
Prepaid long-term service agreement	(9)	(44)
Other investing activities	(5)	(2)
Net cash used for investing activities	(405)	(480)
Financing Activities:
Increase (decrease) in notes payable, net	434	(749)
Proceeds --
Capital contributions from parent company	11	12
FFB loan	0	1,000
Short-term borrowings	250	0
Redemptions --
Payment of preferred and preference stock dividends	(4)	(4)
Payment of common stock dividends	(259)	(238)
FFB loan issuance costs	0	(49)
Other financing activities	(1)	(3)
Net cash provided from (used for) financing activities	431	(31)
Net Change in Cash and Cash Equivalents	389	(12)
Cash and Cash Equivalents at Beginning of Period	24	30
Cash and Cash Equivalents at End of Period	413	18
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	79	71
Income taxes, net	(34)	11
Noncash transactions - Accrued property additions at end of period	177	229
Gulf Power [Member]
Operating Activities:
Net income (loss)	39	39
Adjustments to reconcile net income (loss) to net cash provided from operating activities --
Depreciation and amortization, total	22	34
Deferred income taxes	27	14
Allowance for equity funds used during construction	(4)	(2)
Other, net	11	2
Changes in certain current assets and liabilities --
-Receivables	12	(25)
-Fossil fuel stock	(2)	46
-Prepaid income taxes	3	10
-Other current assets	2	1
-Accounts payable	(28)	6
-Accrued taxes	5	9
-Accrued compensation	(16)	(5)
-Other current liabilities	10	13
Net cash provided from operating activities	81	142
Investing Activities:
Property additions	(84)	(79)
Cost of removal, net of salvage	(5)	(3)
Other investing activities	(3)	(1)
Net cash used for investing activities	(92)	(83)
Financing Activities:
Increase (decrease) in notes payable, net	40	(75)
Proceeds --
Common stock issuances	20	50
Redemptions --
Payment of preferred and preference stock dividends	(2)	(2)
Payment of common stock dividends	(33)	(31)
Other financing activities	2	0
Net cash provided from (used for) financing activities	27	(58)
Net Change in Cash and Cash Equivalents	16	1
Cash and Cash Equivalents at Beginning of Period	39	22
Cash and Cash Equivalents at End of Period	55	23
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	3	5
Income taxes, net	(8)	(6)
Noncash transactions - Accrued property additions at end of period	41	33
Mississippi Power [Member]
Operating Activities:
Net income (loss)	35	(172)
Adjustments to reconcile net income (loss) to net cash provided from operating activities --
Depreciation and amortization, total	26	24
Deferred income taxes	141	(124)
Allowance for equity funds used during construction	(28)	(38)
Regulatory assets associated with Kemper IGCC	(27)	(13)
Estimated loss on Kemper IGCC	9	380
Other, net	11	8
Changes in certain current assets and liabilities --
-Receivables	17	(14)
-Fossil fuel stock	4	37
-Prepaid income taxes	44	(33)
-Other current assets	(3)	(5)
-Accounts payable	(22)	15
-Accrued taxes	(54)	(55)
-Accrued interest	9	8
-Accrued compensation	(20)	(2)
-Over recovered regulatory clause revenues	22	(18)
-Mirror CWIP	40	34
Net cash provided from operating activities	204	32
Investing Activities:
Property additions	(213)	(324)
Change in construction payables	(14)	(31)
Other investing activities	(6)	(6)
Net cash used for investing activities	(233)	(361)
Proceeds --
Capital contributions from parent company	76	1
Interest-bearing refundable deposit	0	75
Other long-term debt issuances	0	250
Short-term borrowings	30	0
Redemptions --
Other long-term debt	(75)	0
Payment of preferred and preference stock dividends	0	0
Return of capital	0	(55)
Other financing activities	(1)	(2)
Net cash provided from (used for) financing activities	30	269
Net Change in Cash and Cash Equivalents	1	(60)
Cash and Cash Equivalents at Beginning of Period	133	145
Cash and Cash Equivalents at End of Period	134	85
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	(1)	3
Income taxes, net	(180)	26
Noncash transactions - Accrued property additions at end of period	100	132
Southern Power [Member]
Operating Activities:
Net income (loss)	33	34
Adjustments to reconcile net income (loss) to net cash provided from operating activities --
Depreciation and amortization, total	60	53
Deferred income taxes	(54)	(14)
Investment tax credits	0	26
Amortization of investment tax credits	(4)	(2)
Deferred revenues	(20)	(20)
Other, net	3	3
Changes in certain current assets and liabilities --
-Receivables	2	21
-Fossil fuel stock	6	2
-Prepaid income taxes	(2)	15
-Other current assets	0	(1)
-Accounts payable	(25)	2
-Accrued taxes	(4)	6
-Accrued interest	(15)	(15)
-Other current liabilities	1	0
Net cash provided from operating activities	(19)	110
Investing Activities:
Property additions	(38)	(5)
Change in construction payables	17	1
Payments pursuant to long-term service agreements	(16)	(10)
Other investing activities	(1)	(1)
Net cash used for investing activities	(38)	(15)
Financing Activities:
Increase (decrease) in notes payable, net	38	0
Redemptions --
Payment of common stock dividends	(33)	(33)
Other financing activities	0	(2)
Net cash provided from (used for) financing activities	5	(35)
Net Change in Cash and Cash Equivalents	(52)	60
Cash and Cash Equivalents at Beginning of Period	75	69
Cash and Cash Equivalents at End of Period	23	129
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	36	36
Income taxes, net	79	(44)
Noncash transactions - Accrued property additions at end of period	$ 16	$ 5

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Contingencies and Regulatory Matters

3 Months Ended

Mar. 31, 2015

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 Matters

New Source Review Actions

As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Alabama Power and Georgia Power alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including units co-owned by Gulf Power and Mississippi Power. These civil actions seek penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against Georgia Power (including claims related to a unit co-owned by Gulf Power) has been administratively closed in the U.S. District Court for the Northern District of Georgia since 2001. The case against Alabama Power (including claims involving a unit co-owned by Mississippi Power) has been actively litigated in the U.S. District Court for the Northern District of Alabama, resulting in a settlement in 2006 of the alleged NSR violations at Plant Miller; voluntary dismissal of certain claims by the EPA; and a grant of summary judgment for Alabama Power on all remaining claims and dismissal of the case with prejudice in 2011. In 2013, the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment in favor of Alabama Power, and the case has been transferred back to the U.S. District Court for the Northern District of Alabama for further proceedings.

Southern Company and each traditional operating company believe each such traditional operating company complied with applicable laws and regulations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of these matters cannot be determined at this time.

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 properties. The traditional 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 March 31, 2015 was $27 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 parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional cleanup and claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites are anticipated.

Georgia Power and numerous other entities have been designated by the EPA as PRPs at the Ward Transformer Superfund site located in Raleigh, North Carolina. In 2011, the EPA issued a Unilateral Administrative Order (UAO) to Georgia Power and 22 other parties, ordering specific remedial action of certain areas at the site. Later in 2011, Georgia Power filed a response with the EPA stating it has sufficient cause to believe it is not a liable party under CERCLA. The EPA notified Georgia Power in 2011 that it is considering enforcement options against Georgia Power and other non-complying UAO recipients. If the EPA pursues enforcement actions and the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party's failure to comply with the UAO.

In addition to the EPA's action at this site, Georgia Power, along with many other parties, was sued in a private action by several existing PRPs for cost recovery related to the removal action. In 2013, the U.S. District Court for the Eastern District of North Carolina Western Division granted Georgia Power's summary judgment motion ruling that Georgia Power has no liability in the private action. On March 20, 2015, the U.S. Court of Appeals for the Fourth Circuit affirmed the lower court's ruling. The plaintiffs may seek review by the U.S. Supreme Court.

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. See Note 1 to the financial statements of Georgia Power under "Environmental Remediation Recovery" in Item 8 of the Form 10-K for additional information regarding the regulatory treatment.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $47 million as of March 31, 2015. 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.

In 2003, Mississippi Power and numerous other entities were designated by the Texas Commission on Environmental Quality (TCEQ) as PRPs at a site that was owned by an electric transformer company that handled Mississippi Power's transformers. The TCEQ approved the final site remediation plan in 2013 and, in March 2014, the impacted utilities, including Mississippi Power, agreed to commence remediation actions on the site. Mississippi Power's environmental remediation liability was $0.5 million as of March 31, 2015 and is expected to be recovered through the ECO Plan.

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, Georgia Power, Gulf Power, and Mississippi Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.

Nuclear Fuel Disposal Cost Litigation

Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.

In December 2014, the Court of Federal Claims entered a judgment in favor of Georgia Power and Alabama Power in the second spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. Georgia Power recovered approximately $18 million, based on its ownership interests, and Alabama Power recovered approximately $26 million. The judgment amounts were paid on March 19, 2015. In March 2015, Georgia Power credited the award to accounts where the original costs were charged and reduced rate base, fuel, and cost of service for the benefit of customers. The final outcome of this matter for Alabama Power cannot be determined at this time; however, no material impact on Southern Company's or Alabama Power's net income is expected as the damage amounts collected from the government are expected to be used for the benefit of customers.

In March 2014, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of March 31, 2015 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.

FERC Matters

Municipal and Rural Associations Tariff

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

On March 31, 2015, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC to forgo the Municipal and Rural Associations cost-based electric tariff increase reflected in the filing by, among other things, increasing the accrual of AFUDC in lieu of including CWIP in rate base. The settlement agreement, if accepted by the FERC, provides that the additional accrual of AFUDC is effective April 1, 2015. The additional resulting AFUDC is projected to be approximately $12 million annually, of which $9 million relates to the Kemper IGCC. In addition, a settlement agreement entered into in 2014 and approved by the FERC allowed for an adjustment to the wholesale revenue requirement in the event the Kemper IGCC, or any substantial portion thereof, was placed in service before or after December 1, 2014. A regulatory asset account was recorded as a result of a portion of the Kemper IGCC being placed in service prior to the projected date. The March 31, 2015 settlement agreement provides that the regulatory asset will be amortized over nine months, beginning April 1, 2015. The ultimate outcome of this matter cannot be determined at this time.

Market-Based Rate Authority

The traditional 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 operating companies and Southern Power filed a triennial market power analysis on June 30, 2014, which included continued reliance on the energy auction as tailored mitigation. On April 27, 2015, the FERC issued an order finding that the traditional 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 operating companies and in some adjacent areas. To retain market-based rate authority, the FERC has directed the traditional operating companies and Southern Power, within 60 days, 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 operating companies and Southern Power are evaluating the order. 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 recovery balance of each regulatory clause follows:

Regulatory Clause	Balance Sheet Line Item	March 31, 2015		December 31, 2014
		(in millions)
Rate CNP Compliance – Under*	Deferred under recovered regulatory clause revenues	$	25	$	2
	Under recovered regulatory clause revenues, current	16		47
Rate CNP PPA – Under	Deferred under recovered regulatory clause revenues	62		29
	Under recovered regulatory clause revenues, current	—		27
Retail Energy Cost Recovery – Over	Deferred over recovered regulatory clause revenues	81		47
Natural Disaster Reserve	Other regulatory liabilities, deferred	82		84

* Formerly Known As Rate CNP Environmental

Rate CNP

In March 2015, the Emerging Issues Task Force unanimously recommended to allow the normal purchases and normal sales exception for physical forward transactions in nodal energy markets. The FASB proposed new accounting guidance reflecting the recommendation on April 23, 2015. This guidance is subject to a public comment period before the FASB issues a final accounting standard. The ultimate outcome of this matter cannot be determined at this time.

Rate CNP Compliance(Formerly Known As Rate CNP Environmental)

See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" and of Alabama Power under "Retail Regulatory Matters – Rate CNP" and " – Non-Environmental Federal Mandated Costs Accounting Order" in Item 8 of the Form 10-K for additional information regarding Alabama Power's development of a revised cost recovery mechanism.

On March 3, 2015, the Alabama PSC approved a modification to Rate CNP Environmental to include compliance costs for both environmental and non-environmental mandates. The recoverable non-environmental compliance costs result from laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. This modification to Rate CNP Environmental was effective March 20, 2015 with the revised rate now defined as Rate CNP Compliance. Alabama Power incurred $14 million of non-environmental compliance costs during the first quarter 2015 and will be limited to recovery of $50 million for the year. Customer rates will not be impacted before January 2016; therefore, the modification will increase the under-recovered position for Rate CNP Compliance during the year.

Georgia Power

Integrated Resource Plan

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

To comply with the April 16, 2015 effective date of the MATS rule, Plant Branch Units 1, 3, and 4 (1,266 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) were retired on April 15, 2015. In addition, operations were discontinued at Plant Mitchell Unit 3 (155 MWs) and its decertification will be requested in connection with the triennial Integrated Resource Plan in 2016. The switch to natural gas as the primary fuel is complete at Plant Yates Unit 7 and is underway at Plant Yates Unit 6. Plant Yates Unit 7 was returned to service on May 4, 2015 and Plant Yates Unit 6 is expected to return to service in mid-2015.

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 March 31, 2015, Georgia Power's under recovered fuel balance totaled $151 million and is included in current assets and other deferred charges and assets on Southern Company's and Georgia Power's Condensed Balance Sheets herein. As of December 31, 2014, Georgia Power's under recovered fuel balance totaled $199 million and is included in current assets and other deferred charges and assets on Southern Company's and Georgia Power's Condensed Balance Sheets herein. On January 20, 2015, the Georgia PSC approved the deferral of Georgia Power's next fuel case filing until at least June 30, 2015.

Fuel cost recovery revenues as recorded on the financial statements 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, and pending litigation.

In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement (Vogtle 3 and 4 Agreement) with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is 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. The Contractor's liability to the Vogtle Owners for schedule and performance liquidated damages and warranty claims is 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%.

Certain payment obligations of Westinghouse and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.) under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group Inc. (a subsidiary of Chicago Bridge & Iron Company, N.V.), respectively. 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. 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 NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. 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 are expected as construction proceeds.

In 2012, the Vogtle Owners and the Contractor began negotiations regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Also in 2012, Georgia Power and the other Vogtle Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against Georgia Power and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. On March 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit affirmed the District Court's decision. The portion of additional costs claimed by the Contractor in its initial complaint that would be attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately $425 million (in 2008 dollars). The Contractor also asserted it is entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. In May 2014, the Contractor filed an amended counterclaim to the suit pending in the U.S. District Court for the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations; however, the Contractor has subsequently asserted related minimum damages (based on Georgia Power's ownership interest) of $113 million. The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these allegations, any of which could be substantial. Georgia Power has not agreed to the proposed cost or to any changes to the guaranteed substantial completion dates or that the Vogtle Owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power intends to vigorously defend the positions of the Vogtle Owners. Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule. During such negotiations the parties may reach a mutually acceptable compromise of their positions.

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 certified construction capital costs to be borne by Georgia Power increase by 5% 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. Georgia Power's eighth VCM report filed in 2013 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 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. In 2013, the Georgia PSC approved a stipulation (2013 Stipulation) entered into by Georgia Power and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. The Georgia PSC has approved eleven VCM reports covering the periods through June 30, 2014, including construction capital costs incurred, which through that date totaled $2.8 billion.

On January 29, 2015, Georgia Power announced it was notified by the Contractor of the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4, which would incrementally delay the previously disclosed estimated in-service dates by 18 months (from the fourth quarter of 2017 to the second quarter of 2019 for Unit 3 and from the fourth quarter of 2018 to the second quarter of 2020 for Unit 4).

Georgia Power does not believe that the Contractor's revised forecast reflects all efforts that may be possible to mitigate the Contractor's delay. In addition, Georgia Power believes that, pursuant to the Vogtle 3 and 4 Agreement, the Contractor is responsible for the Contractor's costs related to the Contractor's delay (including any related construction and mitigation costs, which could be material) and that the Vogtle Owners are entitled to recover liquidated damages for the Contractor's delay beyond the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. Consistent with the Contractor's position in the pending litigation described above, Georgia Power expects the Contractor to contest any claims for liquidated damages and to assert that the Vogtle Owners are responsible for additional costs related to the Contractor's delay.

On February 27, 2015, Georgia Power filed its twelfth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2014, which requested approval for an additional $0.2 billion of construction capital costs incurred during that period. The twelfth VCM report also reflected the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 as well as additional estimated owner-related costs, which include approximately $10 million per month expected to result from the Contractor's proposed 18-month delay, including property taxes, oversight costs, compliance costs, and other operational readiness costs. No Contractor costs related to the Contractor's proposed 18-month delay were included in the twelfth VCM report. Additionally, while Georgia Power has not agreed to any change to the guaranteed substantial completion dates, the twelfth VCM report included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast, to include the estimated 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.

Georgia Power will continue to incur financing costs of approximately $30 million per month until Plant Vogtle Units 3 and 4 are placed in service. The twelfth VCM report estimated financing costs during the construction period to total approximately $2.5 billion.

On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report. Pursuant to this 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, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.

Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, 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 issues are expected to 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 ongoing challenges with Contractor performance including additional challenges in its fabrication, assembly, delivery, and installation of 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.

Additional claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) are also likely to arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement, but also may be resolved through litigation.

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 December 2013, the Florida PSC approved a settlement agreement that provides Gulf Power may reduce depreciation expense and record a regulatory asset up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation expense reduction may not exceed the amount necessary for the ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Gulf Power recognized a $19.6 million reduction in depreciation expense in the first three months of 2015.

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 recovery balance of each regulatory clause follows:

Recovery Clause	Balance Sheet Location	March 31, 2015		December 31, 2014
		(in millions)
Fuel Cost Recovery – Under	Under recovered regulatory clause revenues	$	32	$	40
Purchased Power Capacity Recovery – Under	Under recovered regulatory clause revenues	3		—
Environmental Cost Recovery – Under	Under recovered regulatory clause revenues	12		10
Energy Conservation Cost Recovery – Under	Under recovered regulatory clause revenues	1		3

Mississippi Power

Performance Evaluation Plan

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's base rates.

On March 17, 2015, Mississippi Power submitted its annual PEP lookback filing for 2014, which indicated no surcharge or refund. On March 26, 2015, the Mississippi PSC suspended the filing to allow more time for review.

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

System Restoration Rider

See Note 1 to the financial statements of Mississippi Power under "Provision for Property Damage" in Item 8 of the Form 10-K for additional information.

On February 2, 2015, Mississippi Power submitted its 2015 System Restoration Rider (SRR) rate filing with the Mississippi PSC, which proposed that the 2015 SRR rate remain level at zero and Mississippi Power be allowed to accrue $3 million to the property damage reserve in 2015. On March 3, 2015, the Mississippi PSC suspended the filing to allow more time for review.

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

Environmental Compliance Overview Plan

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for information on Mississippi Power's annual environmental filing with the Mississippi PSC.

In 2012, the Mississippi PSC approved Mississippi Power's request for a CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which are scheduled to be placed in service in September and November 2015, respectively. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Power's portion being $330 million, excluding AFUDC. Mississippi Power's portion of the cost is expected to be recovered through the ECO Plan following the scheduled completion of the project in December 2015. As of March 31, 2015, total project expenditures were $570 million, of which Mississippi Power's portion was $290 million, excluding AFUDC of $22 million.

On February 25, 2015, Mississippi Power submitted its annual ECO filing for 2015, which indicated an annual increase in revenues of approximately $8 million. The filing is under review by the Mississippi PSC.

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 fuel cost recovery.

At March 31, 2015, the amount of over-recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $15 million compared to under-recovered retail fuel costs of $2 million at December 31, 2014.

Ad Valorem Tax Adjustment

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

On April 23, 2015, Mississippi Power filed its annual ad valorem tax adjustment factor filing for 2015, which requested an annual rate decrease of 0.35%, or $2 million in annual retail revenues, primarily due to a decrease in average millage rates.

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 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 (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 using natural gas in August 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, for which the in-service date is currently expected to occur in the first half of 2016. Recovery of the Kemper IGCC 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) remain 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), and actual costs incurred as of March 31, 2015, as adjusted for the Court's decision, are as follows:

Cost Category	2010 Project Estimate(f)		Current Estimate		Actual Costs at March 31, 2015
	(in billions)
Plant Subject to Cost Cap(a)	$	2.40	$	4.94	$	4.37
Lignite Mine and Equipment	0.21		0.23		0.23
CO2 Pipeline Facilities	0.14		0.11		0.10
AFUDC(b)(c)	0.17		0.64		0.48
Combined Cycle and Related Assets Placed in Service – Incremental(d)	—		0.02		—
General Exceptions	0.05		0.10		0.08
Deferred Costs(c)(e)	—		0.18		0.14
Total Kemper IGCC(a)(c)	$	2.97	$	6.22	$	5.40

(a) The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and 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" for additional information.

(b) Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." The current estimate includes an approximately $9 million increase in AFUDC related to a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.

(c) Amounts in the Current Estimate reflect estimated costs through March 31, 2016.

(d) Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information.

(e) The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities."

(f) The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificatedestimate for the CO₂ pipeline facilities which was approved in 2011 by the Mississippi PSC.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of March 31, 2015, $3.27 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $2.06 billion), $2 million in other property and investments, $52 million in fossil fuel stock, $35 million in materials and supplies, $174 million in other regulatory assets, $12 million in other deferred charges and assets, and $24 million in AROs in the balance sheet, with $1 million previously expensed.

Mississippi Power does not intend to seek any rate recovery or joint owner contributions for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $9 million ($6 million after tax) in the first quarter 2015. This amount is in addition to charges totaling $868 million ($536 million after tax), $1.10 billion ($681 million after tax), and $78 million ($48 million after tax) in 2014, 2013, and 2012, respectively. Southern Company recorded pre-tax charges to income for revisions to the cost estimate of $868 million ($536 million after tax) and $1.2 billion ($729 million after tax) in 2014 and 2013, respectively. The increases to the cost estimate in the first quarter 2015 primarily reflected costs related to additional labor costs in support of start-up and operational readiness activities. The current estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 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. Any further extension of the in-service date with respect to the Kemper IGCC 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 $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees, which are being deferred as regulatory assets and are estimated to total approximately $6 million per month.

Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). 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 DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and Mississippi Power's statements of operations and these changes could be material.

Rate Recovery of Kemper IGCC Costs

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 the evaluation of the Rate Mitigation Plan (defined below) and any alternative 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 Settlement Agreement

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, established 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. The 2013 Settlement Agreement also allowed Mississippi Power to secure alternate financing for costs not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. The Court found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. See "2015 Mississippi Supreme Court Decision" herein for additional information.

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's intent under the 2013 Settlement Agreement was to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs, which include carrying costs from the estimated in-service date until securitization is finalized and other costs not included in the Rate Mitigation Plan as approved by the Mississippi PSC. The Court's decision did not impact Mississippi Power's ability to utilize alternate financing through securitization, the 2012 MPSC CPCN Order, or the February 2013 legislation. See "2015 Mississippi Supreme Court Decision" herein for additional information.

2013 MPSC Rate Order

Consistent with the terms of the 2013 Settlement Agreement, 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). For the period from March 2013 through March 31, 2015, $294 million had been collected primarily to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service. Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. 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. Mississippi Power will continue to record AFUDC and collect and defer the approved rates through the in-service date until directed to do otherwise by the Mississippi PSC.

In August 2014, Mississippi Power provided an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment. Mississippi Power's analysis requested, among other things, confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued collection of rates as prescribed by the 2013 MPSC Rate Order, with the current recognition as revenue of the related equity return on all assets placed in service and the deferral of all remaining rate collections under the 2013 MPSC Rate Order to a regulatory liability account. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which would discontinue the collection of, and require the refund of, all amounts previously collected under the 2013 MPSC Rate Order.

In addition, Mississippi Power's August 2014 filing with the Mississippi PSC requested confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC and the deferral of operating costs for the combined cycle as regulatory assets. Under Mississippi Power's proposal, non-incremental costs that would have been incurred whether or not the combined cycle was placed in service would be included in a regulatory asset and would continue to be subject tothe $2.88 billion cost cap. Additionally, incremental costs that would not have been incurred if the combined cycle had not gone into service would be included in a regulatory asset and would not be subject to the cost cap because these costs are incurred to support operation of the combined cycle. All energy revenues associated with the combined cycle variable operating and maintenance expenses would be credited to this regulatory asset. See "Regulatory Assets and Liabilities" for additional information. Any action by the Mississippi PSC that is inconsistent with the treatment requested by Mississippi Power could have a material impact on the results of operations, financial condition, and liquidity of Southern Company and Mississippi Power.

2015 Mississippi Supreme Court Decision

On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order filed by Thomas A. Blanton. 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. The Court's ruling remands the matter to the Mississippi PSC to (1) fix by order the rates that were in existence prior to the 2013 MPSC Rate Order, (2) fix no rate increases until the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts collected under the 2013 MPSC Rate Order. Through March 31, 2015, Mississippi Power had collected $294 million through rates under the 2013 MPSC Rate Order. Any required refunds would also include carrying costs. The Court's decision will become legally effective upon the issuance of a mandate to the Mississippi PSC. Absent specific instruction from the Court, the Mississippi PSC will determine the method and timing of the refund. On March 12, 2015, Mississippi Power and the Mississippi PSC filed motions for rehearing. If the Court denies the motions, it would issue the mandate to the Mississippi PSC no later than seven days following such decision.

Rate Mitigation Plan

In 2013, Mississippi Power, in compliance with the 2013 MPSC Rate Order, filed a revision to the proposed rate recovery plan with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020 (Rate Mitigation Plan), which is still under review by the Mississippi PSC. The revenue requirements set forth in the Rate Mitigation Plan assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation, which currently requires that the related long-term asset be placed in service in 2015.In the Rate Mitigation Plan, Mississippi Power proposed recovery of an annual revenue requirement of approximately $156 million of Kemper IGCC-related operational costs and rate base amounts, including plant costs equal to the $2.4 billion certificated cost estimate. The 2013 MPSC Rate Order, which increased rates beginning in March 2013, was integral to the Rate Mitigation Plan, which contemplates amortization of the regulatory liability balance at the in-service date to be used to mitigate customer rate impacts through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Rate Mitigation Plan, Mississippi Power proposed annual rate recovery to remain the same from 2014 through 2020, with the proposed revenue requirement approximating the forecasted cost of service for the period 2014 through 2020. Under Mississippi Power's proposal, to the extent the actual annual cost of service differs from the approved forecast for certain items, the difference would be deferred as a regulatory asset or liability, subject to accrual of carrying costs, and would be included in the next year's rate recovery calculation. If any deferred balance remains at the end of 2020, the Mississippi PSC would review the amount and, if approved, determine the appropriate method and period of disposition. See "Regulatory Assets and Liabilities" herein for additional information.

To the extent that refunds of amounts collected under the 2013 MPSC Rate Order are required on a schedule different from the amortization schedule proposed in the Rate Mitigation Plan, the customer billing impacts proposed under the Rate Mitigation Plan would no longer be viable. See "2015 Mississippi Supreme Court Decision" herein for additional information.

In addition to current estimated costs at March 31, 2015 of $6.22 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.

Mississippi Power also expects to seek rate recovery through alternate means, which could include a traditional rate case. On May 1, 2015, Mississippi Power notified the Mississippi PSC of its plans to file a rate request in May 2015.

Prudence Reviews

The Mississippi PSC's review of Kemper IGCC costs is ongoing. In August 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the Mississippi Public Utilities Staff (MPUS). The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues and Mississippi Power is working to reach a mutually acceptable resolution. As a result of the Court's decision, Mississippi Power intends to request that the Mississippi PSC reconsider its prudence review schedule. See "2015 Mississippi Supreme Court Decision" herein for additional information.

Regulatory Assets and Liabilities

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

In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. As of March 31, 2015, the regulatory asset balance associated with the Kemper IGCC was $174 million. The projected balance at March 31, 2016 is estimated to total approximately $266 million. The amortization period for any such costs approved for recovery remains subject to approval by the Mississippi PSC.

The 2013 MPSC Rate Order approved 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. On February 12, 2015, the Court ordered the Mississippi PSC to refund Mirror CWIP and to fix by order the rates that were in existence prior to the 2013 MPSC Rate Order. Mississippi Power is deferring the collections under the approved rates in the Mirror CWIP regulatory liability until otherwise directed by the Mississippi PSC. Mississippi Power is also accruing carrying costs on the unamortized balance of the Mirror CWIP regulatory liability for the benefit of retail customers. As of March 31, 2015, the balance of the Mirror CWIP regulatory liability, including carrying costs, was $311 million.

See "2015 Mississippi Supreme Court Decision" herein for additional information.

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

Lignite Mine and CO₂ Pipeline Facilities

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

In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managing the mining operations. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See 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 has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop will purchase 30% of the CO₂ captured from the Kemper IGCC. The agreements with Denbury and Treetop provide termination rights in the event that Mississippi Power does not satisfy its contractual obligation with respect to deliveries of captured CO₂ by May 11, 2015. While Mississippi Power has received no indication from either Denbury or Treetop of their intent to terminate their respective agreements, any termination or material modification of these agreements could result in a material reduction in future chemical product sales revenues and could have a material financial impact on Mississippi Power to the extent Mississippi Power is not able to enter into other similar contractual arrangements.

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

Proposed Sale of Undivided Interest to SMEPA

In 2010, Mississippi Power and SMEPA entered into an asset purchase agreement (APA) whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In 2012, the Mississippi PSC approved the sale and transfer of the 17.5% undivided interest in the Kemper IGCC to SMEPA. Later in 2012, Mississippi Power and SMEPA signed an amendment to the APA whereby SMEPA reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC. In March 2013, Mississippi Power and SMEPA signed an amendment to the APA whereby they agreed to amend a 2011 power supply agreement between the parties to reduce the capacity amounts to be received by SMEPA by half (approximately 75 MWs) at the sale and transfer of the undivided interest in the Kemper IGCC to SMEPA. Capacity revenues under the 2011 power supply agreement were $4 million in the first quarter 2015 and $17 million in 2014.

By letter agreement dated October 6, 2014, Mississippi Power and SMEPA agreed in principle on certain issues related to SMEPA's proposed purchase of a 15% undivided interest in the Kemper IGCC. The parties agreed to further amend the APA as follows: (1) Mississippi Power agreed to cap at $2.88 billion the portion of the purchase price payable for development and construction costs, net of the Cost Cap Exceptions, title insurance reimbursement, and AFUDC and/or carrying costs through the Closing Commitment Date (defined below); (2) SMEPA agreed to close the purchase within 180 days after the date of the execution of the amended APA or before the Kemper IGCC in-service date, whichever occurs first (Closing Commitment Date), subject only to satisfaction of certain conditions; and (3) AFUDC and/or carrying costs will continue to be accrued on the capped development and construction costs, the Cost Cap Exceptions, and any operating costs, net of revenues until the amended APA is executed by both parties, and thereafter AFUDC and/or carrying costs and payment of interest on SMEPA's deposited money will be suspended and waived provided closing occurs by the Closing Commitment Date. The letter agreement also provided for certain post-closing adjustments to address any differences between the actual and the estimated amounts of post-in-service date costs (both expenses and capital) and revenue credits for those portions of the Kemper IGCC previously placed in service.

By letter dated December 18, 2014, SMEPA notified Mississippi Power that SMEPA decided not to extend the December 31, 2014 estimated closing date in the APA or revise the APA to include the contemplated amendments; however, both parties agree that the APA will remain in effect until closing or until either party gives notice of termination.

The closing of this transaction is also conditioned upon execution of a joint ownership and operating agreement, the absence of material adverse effects, receipt of all construction permits, and appropriate regulatory approvals, as well as SMEPA's receipt of Rural Utilities Service (RUS) funding. In 2012, SMEPA received a conditional loan commitment from RUS for the purchase.

In 2012, in January 2014, and in October 2014, Mississippi Power received $150 million, $75 million, and $50 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied to the purchase. While the expectation is that these amounts will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposits upon the termination of the APA or within 15 days of a request by SMEPA for a full or partial refund. Accordingly, the deposits have been presented as a current liability in the balance sheet and as financing proceeds in the statement of cash flow. Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any refund of the deposits to SMEPA. The ultimate outcome of these matters cannot be determined at this time.

Investment Tax Credits

The IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Through March 31, 2015, Mississippi Power had recorded tax benefits totaling $276 million for the Phase II credits, of which approximately $207 million had been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%of the CO₂ produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. Mississippi Power currently expects to place the Kemper IGCC in service in the first half of 2016. In addition, a portion of the Phase II tax credits will be subject to recapture upon completion of SMEPA's proposed purchase of an undivided interest in the Kemper IGCC as described above. The ultimate outcome of this matter cannot be determined at this time.

Section 174 Research and Experimental Deduction

Southern Company, on behalf of Mississippi Power, reflected deductions for research and experimental (R&E) expenditures related to the Kemper IGCC in its federal income tax calculations for 2013 and 2014. Due to the uncertainty related to this tax position, Southern Company and Mississippi Power had unrecognized tax benefits totaling approximately $211 million at March 31, 2015. See Note 5 to the financial statements of Southern Company and Mississippi Power under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K and Note (G) herein under "Unrecognized Tax Benefits" for additional information. The ultimate outcome of this matter cannot be determined at this time.

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Segment and Related Information (Tables)

3 Months Ended

Mar. 31, 2015

Segment Reporting [Abstract]

Financial data for business segments

Financial data for business segments and products and services for the three months ended March 31, 2015 and 2014 was as follows:

	Electric Utilities
	Traditional Operating Companies		Southern Power		Eliminations			Total		All Other		Eliminations			Consolidated
	(in millions)
Three Months Ended March 31, 2015:
Operating revenues	$	3,948	$	348	$	(124	)	$	4,172	$	40	$	(29	)	$	4,183
Segment net income (loss)(a)(b)	477		33		—			510		3		(5		)	508
Total assets at March 31, 2015	$	65,530	$	5,564	$	(273	)	$	70,821	$	1,091	$	(302	)	$	71,610
Three Months Ended March 31, 2014:
Operating revenues	$	4,378	$	351	$	(102	)	$	4,627	$	41	$	(24	)	$	4,644
Segment net income (loss)(a)(b)	318		33		—			351		—		—			351
Total assets at December 31, 2014	$	64,644	$	5,550	$	(131	)	$	70,063	$	1,156	$	(296	)	$	70,923

(a) After dividends on preferred and preference stock of subsidiaries.

(b) Segment net income (loss) for the traditional operating companies for the three months ended March 31, 2015 and March 31, 2014 includes a $9 million pre-tax charge ($6 million after tax) and a $380 million pre-tax charge ($235 million after tax), respectively, for estimated probable losses on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein 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 March 31, 2015	$	3,542	$	467	$	163	$	4,172
Three Months Ended March 31, 2014	3,858		604		165		4,627

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Stockholders' Equity - Earnings per Share (Details) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Earnings per Share
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		17
Southern Company [Member]
Earnings per Share
As reported shares	910	890
Effect of options and performance share award units	5	3
Diluted shares	915	893

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Introduction (Tables)

3 Months Ended

Mar. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Asset Retirement Obligations

In the second quarter 2015, Southern Company and the traditional operating companies expect to record incremental asset retirement obligations (ARO) related to the CCR Rule in amounts currently estimated to fall within the following ranges:

	Low		High
	(in millions)
Southern Company	$	525	$	575
Alabama Power	$	330	$	350
Georgia Power	$	10	$	20
Gulf Power	$	70	$	80
Mississippi Power	$	75	$	85